[Title 30 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2007 Edition]
[From the U.S. Government Printing Office]



[[Page i]]

          

          30


          Parts 200 to 699

                         Revised as of July 1, 2007


          Mineral Resources
          



________________________

          Containing a codification of documents of general 
          applicability and future effect

          As of July 1, 2007
          With Ancillaries
                    Published by
                    Office of the Federal Register
                    National Archives and Records
                    Administration
                    A Special Edition of the Federal Register

[[Page ii]]

          U.S. GOVERNMENT OFFICIAL EDITION NOTICE

          Legal Status and Use of Seals and Logos
          
          
          The seal of the National Archives and Records Administration 
              (NARA) authenticates the Code of Federal Regulations (CFR) as 
              the official codification of Federal regulations established 
              under the Federal Register Act. Under the provisions of 44 
              U.S.C. 1507, the contents of the CFR, a special edition of the 
              Federal Register, shall be judicially noticed. The CFR is 
              prima facie evidence of the original documents published in 
              the Federal Register (44 U.S.C. 1510).

          It is prohibited to use NARA's official seal and the stylized Code 
              of Federal Regulations logo on any republication of this 
              material without the express, written permission of the 
              Archivist of the United States or the Archivist's designee. 
              Any person using NARA's official seals and logos in a manner 
              inconsistent with the provisions of 36 CFR part 1200 is 
              subject to the penalties specified in 18 U.S.C. 506, 701, and 
              1017.

          Use of ISBN Prefix

          This is the Official U.S. Government edition of this publication 
              and is herein identified to certify its authenticity. Use of 
              the 0-16 ISBN prefix is for U.S. Government Printing Office 
              Official Editions only. The Superintendent of Documents of the 
              U.S. Government Printing Office requests that any reprinted 
              edition clearly be labeled as a copy of the authentic work 
              with a new ISBN.

              
              
          U . S . G O V E R N M E N T P R I N T I N G O F F I C E

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

          U.S. Superintendent of Documents  Washington, DC 
              20402-0001

          http://bookstore.gpo.gov

          Phone: toll-free (866) 512-1800; DC area (202) 512-1800

[[Page iii]]




                            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                      597
          Chapter IV--Geological Survey, Department of the 
          Interior                                                 601
  Finding Aids:
      Material Approved for Incorporation by Reference........     615
      Table of CFR Titles and Chapters........................     623
      Alphabetical List of Agencies Appearing in the CFR......     641
      List of CFR Sections Affected...........................     651

[[Page iv]]





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

                     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.

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

[[Page v]]



                               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, 2007), 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, 2001, consult either the List of CFR Sections Affected, 1949-
1963, 1964-1972, 1973-1985, or 1986-2000, published in 11 separate 
volumes. For the period beginning January 1, 2001, 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 202-741-6010.

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.

[[Page vii]]


REPUBLICATION OF MATERIAL

    There are no restrictions on the republication of textual 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 202-741-6000 
or write to the Director, Office of the Federal Register, National 
Archives and Records Administration, Washington, DC 20408 or e-mail 
[email protected].

SALES

    The Government Printing Office (GPO) processes all sales and 
distribution of the CFR. For payment by credit card, call toll-free, 
866-512-1800 or DC area, 202-512-1800, M-F, 8 a.m. to 4 p.m. e.s.t. or 
fax your order to 202-512-2250, 24 hours a day. For payment by check, 
write to the Superintendent of Documents, Attn: New Orders, P.O. Box 
371954, Pittsburgh, PA 15250-7954. For GPO Customer Service call 202-
512-1803.

ELECTRONIC SERVICES

    The full text of the Code of Federal Regulations, the LSA (List of 
CFR Sections Affected), The United States Government Manual, the Federal 
Register, Public Laws, Public Papers, Weekly Compilation of Presidential 
Documents and the Privacy Act Compilation are available in electronic 
format at www.gpoaccess.gov/nara (``GPO Access''). For more information, 
contact Electronic Information Dissemination Services, U.S. Government 
Printing Office. Phone 202-512-1530, or 888-293-6498 (toll-free). E-
mail, [email protected].
    The Office of the Federal Register also offers a free service on the 
National Archives and Records Administration's (NARA) World Wide Web 
site for public law numbers, Federal Register finding aids, and related 
information. Connect to NARA's web site at www.archives.gov/federal-
register. The NARA site also contains links to GPO Access.

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

July 1, 2007.

[[Page ix]]



                               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, 2007.

    For this volume, Cheryl E. Sirofchuck was Chief Editor. The Code of 
Federal Regulations publication program is under the direction of 
Frances D. McDonald, assisted by Ann Worley.


[[Page 1]]



                       TITLE 30--MINERAL RESOURCES




                  (This book contains parts 200 to 699)

  --------------------------------------------------------------------
                                                                    Part

chapter ii--Minerals Management Service, Department of the 
  Interior..................................................         201

chapter iii--Board of Surface Mining and Reclamation 
  Appeals, Department of the Interior.......................         301

chapter iv--Geological Survey, Department of the Interior...         401

[[Page 3]]



   CHAPTER II--MINERALS MANAGEMENT SERVICE, DEPARTMENT OF THE INTERIOR




                           (Parts 200 to 699)

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

                SUBCHAPTER A--MINERALS REVENUE MANAGEMENT
Part                                                                Page
201             General.....................................           5
202             Royalties...................................           5
203             Relief or reduction in royalty rates........          14
204             Alternatives for marginal properties........          44
206             Product valuation...........................          50
207             Sales agreements or contracts governing the 
                    disposal of lease products..............         162
208             Sale of Federal royalty oil.................         164
210             Forms and reports...........................         171
212             Records and files maintenance...............         183
215

Accounting and auditing standards [Reserved]

216             Production accounting.......................         185
217             Audits and inspections......................         192
218             Collection of royalties, rentals, bonuses 
                    and other monies due the Federal 
                    Government and credits and incentives 
                    due lessees.............................         194
219             Distribution and disbursement of royalties, 
                    rentals, and bonuses....................         211
220             Accounting procedures for determining net 
                    profit share payment for Outer 
                    Continental Shelf oil and gas leases....         213
227             Delegation to States........................         226
228             Cooperative activities with States and 
                    Indian tribes...........................         238
229             Delegation to States........................         241
230

Recoupments and refunds [Reserved]

232

Interest payments [Reserved]

233

Escrow and investments [Reserved]

234

Bonding--payment liability [Reserved]

241             Penalties...................................         249
242

Orders [Reserved]

[[Page 4]]

243             Suspensions pending appeal and bonding--
                    Minerals revenue management.............         254
                         SUBCHAPTER B--OFFSHORE
250             Oil and gas and sulphur operations in the 
                    Outer Continental Shelf.................         260
251             Geological and geophysical (G & G) 
                    explorations of the Outer Continental 
                    Shelf...................................         461
252             Outer Continental Shelf (OCS) oil and gas 
                    information program.....................         474
253             Oil spill financial responsibility for 
                    offshore facilities.....................         479
254             Oil-spill response requirements for 
                    facilities located seaward of the coast 
                    line....................................         493
256             Leasing of sulphur or oil and gas in the 
                    Outer Continental Shelf.................         505
259             Mineral leasing: Definitions................         533
260             Outer Continental Shelf oil and gas leasing.         534
270             Nondiscrimination in the Outer Continental 
                    Shelf...................................         542
280             Prospecting for minerals other than oil, 
                    gas, and sulfur on the Outer Continental 
                    Shelf...................................         543
281             Leasing of minerals other than oil, gas, and 
                    sulphur in the Outer Continental Shelf..         555
282             Operations in the Outer Continental Shelf 
                    for minerals other than oil, gas, and 
                    sulphur.................................         568
                          SUBCHAPTER C--APPEALS
290             Appeals procedures..........................         591

[[Page 5]]



                SUBCHAPTER A_MINERALS REVENUE 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 Minerals Revenue 
          Management.

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

Subpart E--Coal [Reserved]

Subpart F--Other Solid Minerals [Reserved]

Subpart G--Geothermal Resources [Reserved]

Subpart H--Indian Lands [Reserved]

    Authority: The Act of February 25, 1920 (30 U.S.C. 181, et seq.), as 
amended; the Act of May 21, 1930 (30 U.S.C. 301-306); the Mineral 
Leasing Act for Acquired Lands (30 U.S.C. 351-359), as amended; the Act 
of March 3, 1909 (25 U.S.C. 396), as amended; the National Environmental 
Policy Act of 1969 (42 U.S.C. 4321, et seq.) as amended; the Act of May 
11, 1938 (25 U.S.C. 396a-396q), as amended; the Act of February 28, 1891 
(25 U.S.C. 397), as amended; the Act of May 29, 1924 (25 U.S.C. 398); 
the Act of March 3, 1927 (25 U.S.C. 398a-398e); the Act of June 30, 1919 
(25 U.S.C. 399), as amended; R.S. 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 Minerals Revenue 

Management.

    The Associate Director is responsible for the collection of certain 
rents, royalties, and other payments; for the receipt of sales and 
production reports; for determining royalty liability; for maintaining 
accounting records; for any audits of the royalty payments and 
obligations; and for any and all other functions relating to royalty 
management on Federal and Indian oil and gas leases.

[47 FR 47768, Oct. 27, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983]

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

Subpart E--Coal [Reserved]

Subpart F--Other Solid Minerals [Reserved]

Subpart G--Geothermal Resources [Reserved]

Subpart H--Indian Lands [Reserved]



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.

[[Page 6]]

                          Subpart D_Federal Gas

202.150 Royalty on gas.
202.151 Royalty on processed gas.
202.152 Standards for reporting and paying royalties on gas.

Subpart E--Solid Minerals, General [Reserved]

                             Subpart F_Coal

202.250 Overriding royalty interest.

Subpart G--Other Solid Minerals [Reserved]

                     Subpart H_Geothermal Resources

202.350 Scope and definitions.
202.351 Royalties on geothermal resources.
202.352 Minimum royalty.
202.353 Measurement standards for reporting and paying royalties and 
          direct use fees.

Subpart I--OCS Sulfur [Reserved]

               Subpart J_Gas Production from Indian Leases

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

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

Subpart A--General Provisions [Reserved]



               Subpart B_Oil, Gas, and OCS Sulfur, General

    Source: 53 FR 1217, Jan. 15, 1988, unless otherwise noted.



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

[[Page 7]]

MMS or BLM, as appropriate) produced from a Federal or Indian lease to 
which this part applies is subject to royalty.
    (2) When oil is used on, or for the benefit of, the lease at a 
production facility handling production from more than one lease with 
the approval of the MMS or BLM, as appropriate, or at a production 
facility handling unitized or communitized production, only that 
proportionate share of each lease's production (actual or allocated) 
necessary to operate the production facility may be used royalty-free.
    (3) Where the terms of any lease are inconsistent with this section, 
the lease terms shall govern to the extent of that inconsistency.
    (c) If BLM determines that oil was avoidably lost or wasted from an 
onshore lease, or that oil was drained from an onshore lease for which 
compensatory royalty is due, or if MMS determines that oil was avoidably 
lost or wasted from an offshore lease, then the value of that oil shall 
be determined in accordance with 30 CFR part 206.
    (d) If a lessee receives insurance compensation for unavoidably lost 
oil, royalties are due on the amount of that compensation. This 
paragraph shall not apply to compensation through self-insurance.
    (e)(1) In those instances where the lessee of any lease committed to 
a federally approved unitization or communitization agreement does not 
actually take the proportionate share of the agreement production 
attributable to its lease under the terms of the agreement, the full 
share of production attributable to the lease under the terms of the 
agreement nonetheless is subject to the royalty payment and reporting 
requirements of this title. Except as provided in paragraph (e)(2) of 
this section, the value, for royalty purposes, of production 
attributable to unitized or communitized leases will be determined in 
accordance with 30 CFR part 206. In applying the requirements of 30 CFR 
part 206, the circumstances involved in the actual disposition of the 
portion of the production to which the lessee was entitled but did not 
take shall be considered as controlling in arriving at the value, for 
royalty purposes, of that portion as though the person actually selling 
or disposing of the production were the lessee of the Federal or Indian 
lease.
    (2) If a Federal or Indian lessee takes less than its proportionate 
share of agreement production, upon request of the lessee MMS may 
authorize a royalty valuation method different from that required by 
paragraph (e)(1) of this section, but consistent with the purposes of 
these regulations, for any volumes not taken by the lessee but for which 
royalties are due.
    (3) For purposes of this subchapter, all persons actually taking 
volumes in excess of their proportionate share of production in any 
month under a unitization or communitization agreement shall be deemed 
to have taken ratably from all persons actually taking less than their 
proportionate share of the agreement production for that month.
    (4) If a lessee takes less than its proportionate share of agreement 
production for any month but royalties are paid on the full volume of 
its proportionate share in accordance with the provisions of this 
section, no additional royalty will be owed for that lease for prior 
periods when the lessee subsequently takes more than its proportionate 
share to balance its account or when the lessee is paid a sum of money 
by the other agreement participants to balance its account.
    (f) For production from Federal and Indian leases which are 
committed to federally-approved unitization or communitization 
agreements, upon request of a lessee MMS may establish the value of 
production pursuant to a method other than the method required by the 
regulations in this title if: (1) The proposed method for establishing 
value is consistent with the requirements of the applicable statutes, 
lease terms, and agreement terms; (2) persons with an interest in the 
agreement, including, to the extent practical, royalty interests, are 
given notice and an opportunity to comment on the proposed valuation 
method before it is authorized; and (3) to the extent practical, persons 
with an interest in a Federal or Indian lease committed to the 
agreement, including royalty interests, must agree to use the proposed 
method for valuing production from the agreement for royalty purposes.

[53 FR 1217, Jan. 15, 1988]

[[Page 8]]



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. 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

[[Page 9]]

than their proportionate share of the agreement production for that 
month.
    (4) If a lessee takes less than its proportionate share of agreement 
production for any month but royalties are paid on the full volume of 
its proportionate share in accordance with the provisions of this 
section, no additional royalty will be owed for that lease for prior 
periods at the time the lessee subsequently takes more than its 
proportionate share to balance its account or when the lessee is paid a 
sum of money by the other agreement participants to balance its account.
    (f) For production from Federal leases which are committed to 
federally-approved unitization or communitization agreements, upon 
request of a lessee MMS may establish the value of production pursuant 
to a method other than the method required by the regulations in this 
title if: (1) The proposed method for establishing value is consistent 
with the requirements of the applicable statutes, lease terms and 
agreement terms; (2) to the extent practical, persons with an interest 
in the agreement, including royalty interests, are given notice and an 
opportunity to comment on the proposed valuation method before it is 
authorized; and (3) to the extent practical, persons with an interest in 
a Federal lease committed to the agreement, including royalty interests, 
must agree to use the proposed method for valuing production from the 
agreement for royalty purposes.

[53 FR 1271, Jan. 15, 1988, as amended at 64 FR 43513, Aug. 10, 1999]



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.

[[Page 10]]

    (b)(1) Residue gas and gas plant product volumes shall be reported 
as specified in this paragraph.
    (2) Carbon dioxide (CO2), nitrogen (N2), 
helium (He), residue gas, and any other gas marketed as a separate 
product shall be reported by using the same standards specified in 
paragraph (a) of this section.
    (3) Natural gas liquids (NGL) volumes shall be reported in standard 
U.S. gallons (231 cubic inches) at 60 [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)(1) Royalties on geothermal resources, including byproducts, or 
on electricity produced using geothermal resources, will be at the 
royalty rate(s) specified in the lease, unless the Secretary of the 
Interior temporarily waives, suspends, or reduces that rate(s). 
Royalties are determined under 30 CFR part 206, subpart H.
    (2) Fees in lieu of royalties on geothermal resources are prescribed 
in 30 CFR part 206, subpart H.
    (3) Except for the amount credited against royalties for in-kind 
deliveries of electricity to a State or county under Sec. 218.306, you 
must pay royalties and direct use fees in money.
    (b)(1) Except as specified in paragraph (b)(2) of this section, 
royalties or fees are due on--
    (i) All geothermal resources produced from a lease and that are sold 
or used by the lessee or are reasonably susceptible to sale or use by 
the lessee, or
    (ii) All proceeds derived from the sale of electricity produced 
using geothermal resources produced from a lease.
    (2) For purposes of this subparagraph, the terms ``Class I lease,'' 
``Class II lease,'' and ``Class III lease'' have the same meanings 
prescribed in 30 CFR 206.351.
    (i) For Class I leases, MMS will allow free of royalty--
    (A) Geothermal resources that are unavoidably lost or reinjected 
before use on or off the lease, as determined by the Bureau of Land 
Management (BLM), or that are reasonably necessary to generate plant 
parasitic electricity or electricity for Federal lease operations; and
    (B) A reasonable amount of commercially demineralized water 
necessary for power plant operations or otherwise used on or for the 
benefit of the lease.
    (ii) For Class II and Class III leases where the lessee uses 
geothermal resources for commercial production or generation of 
electricity, or where geothermal resources are sold at arm's length for 
the commercial production or generation of electricity, MMS will allow 
free of royalty or direct use fees geothermal resources that are:
    (A) Unavoidably lost or reinjected before use on or off the lease, 
as determined by BLM;
    (B) Reasonably necessary for the lessee to generate plant parasitic 
electricity or electricity for Federal lease operations, as approved by 
BLM; or

[[Page 11]]

    (C) Otherwise used for Federal lease operations related to 
commercial production or generation of electricity, as approved by BLM.
    (iii) For Class II and Class III leases where the lessee uses the 
geothermal resources for a direct use or in a direct use facility, as 
defined in 30 CFR 206.351, resources that are used to generate 
electricity for Federal lease operations or that are otherwise used for 
Federal lease operations are subject to direct use fees, except for 
geothermal resources that are unavoidably lost or reinjected before use 
on or off the lease, as determined by BLM.
    (3) Royalties on byproducts are due at the time the recovered 
byproduct is used, sold, or otherwise finally disposed of. Byproducts 
produced and added to stockpiles or inventory do not require payment of 
royalty until the byproducts are sold, utilized, or otherwise finally 
disposed of. The MMS may ask BLM to increase the lease bond to protect 
the lessor's interest when BLM determines that stockpiles or inventories 
become excessive.
    (c) If BLM determines that geothermal resources (including 
byproducts) were avoidably lost or wasted from the lease, or that 
geothermal resources (including byproducts) were drained from the lease 
for which compensatory royalty (or compensatory fees in lieu of 
compensatory royalty) are due, the value of those geothermal resources, 
or the royalty or fees owed, will be determined under 30 CFR part 206, 
subpart H.
    (d) If a lessee receives insurance or other compensation for 
unavoidably lost geothermal resources (including byproducts), royalties 
at the rates specified in the lease (or fees in lieu of royalties) are 
due on the amount of, or as a result of, that compensation. This 
paragraph will not apply to compensation through self-insurance.

[72 FR 24458, May 2, 2007]



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 and 

direct use fees.

    (a) For geothermal resources used to generate electricity, you must 
report the quantity on which royalty is due on Form MMS-2014 (Report of 
Sales and Royalty Remittance) as follows:
    (1) For geothermal resources for which royalty is calculated under 
Sec. 206.352(a), you must report quantities in:
    (i) Thousands of pounds to the nearest whole thousand pounds if the 
contract for the geothermal resources specifies delivery in terms of 
weight; or
    (ii) Millions of Btu to the nearest whole million Btu if the sales 
contract for the geothermal resources specifies delivery in terms of 
heat or thermal energy.
    (2) For geothermal resources for which royalty is calculated under 
Sec. 206.352(b), you must report the quantities in kilowatt-hours to 
the nearest whole kilowatt-hour.
    (b) For geothermal resources used in direct use processes, you must 
report the quantity on which a royalty or direct use fee is due on Form 
MMS-2014 in:
    (1) Millions of Btu to the nearest whole million Btu if valuation is 
in terms of heat or thermal energy used or displaced;
    (2) Millions of gallons to the nearest million gallons of geothermal 
fluid produced if valuation or fee calculation is in terms of volume;
    (3) Millions of pounds to the nearest million pounds of geothermal 
fluid produced if valuation or fee calculation is in terms of mass; or
    (4) Any other measurement unit MMS approves for valuation and 
reporting purposes.
    (c) For byproducts, you must report the quantity on which royalty is 
due on Form MMS-2014 consistent with MMS-established reporting 
standards.
    (d) For commercially demineralized water, you must report the 
quantity on which royalty is due on Form MMS-2014 in hundreds of gallons 
to the nearest hundred gallons.
    (e) You need not report the quality of geothermal resources, 
including byproducts, to MMS. However, you must maintain quality 
measurements for

[[Page 12]]

audit purposes. Quality measurements include, but are not limited to:
    (1) Temperatures and chemical analyses for fluid geothermal 
resources; and
    (2) Chemical analyses, weight percent, or other purity measurements 
for byproducts.

[72 FR 24458, May 2, 2007]

Subpart I--OCS Sulfur [Reserved]



               Subpart J_Gas Production From Indian Leases

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



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.
    (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 Sec. Sec. 
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.

[[Page 13]]



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.
    (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

[[Page 14]]

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 How can I get royalty relief?
203.3 Why must I pay a fee to request royalty relief?
203.4 How do the provisions in this part apply to different types of 
          leases and projects?
203.5 What is MMS's authority to collect information?

               Subpart B_OCS Oil, Gas, and Sulfur General

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

203.40 Which leases are eligible for royalty relief as a result of 
          drilling deep wells?
203.41 If I have a qualified well, what royalty relief will my lease 
          earn?
203.42 To which production do I apply the royalty suspension volume 
          earned from qualified wells on my lease?
203.43 What administrative steps must I take to use the royalty 
          suspension volume?
203.44 If I drill a certified unsuccessful well, what royalty relief 
          will my lease earn?
203.45 To which production do I apply the royalty suspension supplements 
          from drilling one or two certified unsuccessful wells on my 
          lease?
203.46 What administrative steps do I take to obtain and use the royalty 
          suspension supplement?
203.47 Do I keep royalty relief if prices rise significantly?
203.48 May I substitute the deep gas drilling provisions in Sec. 203.0 
          and Sec. Sec. 203.40 through 203.47 for the deep gas royalty 
          relief provided in my lease terms?

                  Royalty Relief for end-of-life Leases

203.50 Who may apply for end-of-life royalty relief?
203.51 How do I apply for end-of-life royalty relief?
203.52 What criteria must I meet to get relief?
203.53 What relief will MMS grant?
203.54 How does my relief arrangement for an oil and gas lease operate 
          if prices rise sharply?
203.55 Under what conditions can my end-of-life royalty relief 
          arrangement for an oil and gas lease be ended?
203.56 Does relief transfer when a lease is assigned?

Royalty Relief For Deep Water Expansion Projects And Pre-Act Deep Water 
                                 Leases

203.60 Who may apply for deep water royalty relief?
203.61 How do I assess my chances for getting relief?
203.62 How do I apply for relief?
203.63 Does my application have to include all leases in the field?
203.64 How many applications may I file on a field or a development 
          project?
203.65 How long will MMS take to evaluate my application?
203.66 What happens if MMS does not act in the time allowed?

[[Page 15]]

203.67 What economic criteria must I meet to get royalty relief on an 
          authorized field or project?
203.68 What pre-application costs will MMS consider in determining 
          economic viability?
203.69 If my application is approved, what royalty relief will I 
          receive?
203.70 What information must I provide after MMS approves relief?
203.71 How does MMS allocate a field's suspension volume between my 
          lease and other leases on my field?
203.72 Can my lease receive more than one suspension volume?
203.73 How do suspension volumes apply to natural gas?
203.74 When will MMS reconsider its determination?
203.75 What risk do I run if I request a redetermination?
203.76 When might MMS withdraw or reduce the approved size of my relief?
203.77 May I voluntarily give up relief if conditions change?
203.78 Do I keep relief if prices rise significantly?
203.79 How do I appeal MMS's decisions related to Deep Water Royalty 
          Relief?
203.80 When can I get royalty relief if I am not eligible for end-of-
          life or deep water royalty relief?

                            Required Reports

203.81 What supplemental reports do royalty-relief applications require?
203.82 What is MMS's authority to collect this information?
203.83 What is in an administrative information report?
203.84 What is in a net revenue and relief justification report?
203.85 What is in an economic viability and relief justification report?
203.86 What is in a G&G report?
203.87 What is in an engineering report?
203.88 What is in a production report?
203.89 What is in a deep water cost report?
203.90 What is in a fabricator's confirmation report?
203.91 What is in a post-production development report?

Subpart C--Federal and Indian Oil [Reserved]

Subpart D--Federal and Indian Gas [Reserved]

Subpart E--Solid Minerals, General [Reserved]

                             Subpart F_Coal

203.250 Advance royalty.
203.251 Reduction in royalty rate or rental.

Subpart G--Other Solid Minerals [Reserved]

Subpart H--Geothermal Resources [Reserved]

Subpart I--OCS Sulfur [Reserved]

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



                      Subpart A_General Provisions

    Source: 63 FR 2616, Jan. 16, 1998, unless otherwise noted.



Sec. 203.0  What definitions apply to this part?

    Authorized field means a field:
    (1) Located in a water depth of at least 200 meters and in the Gulf 
of Mexico (GOM) west of 87 degrees, 30 minutes West longitude;
    (2) That includes one or more pre-Act leases; and
    (3) From which no current pre-Act lease produced, other than test 
production, before November 28, 1995.
    Certified unsuccessful well means an original well, or a sidetrack 
with a sidetrack measured depth of at least 10,000 feet, on your lease 
that:
    (1) You begin drilling on or after March 26, 2003, and before May 3, 
2009, and before your lease produces gas or oil from a deep well with a 
perforated interval the top of which is at least 18,000 feet true 
vertical depth below the datum at mean sea level (TVD SS);
    (2) You drill to at least 18,000 feet TVD SS with a target reservoir 
on your lease, identified from seismic and related data, deeper than 
that depth;
    (3) Fails to meet the producibility requirements of 30 CFR part 250, 
subpart A, and does not produce gas or oil, or the MMS agrees is not 
commercially producible; and
    (4) For which you have provided the notices and information in Sec. 
203.46.
    Complete application means an original and two copies of the six 
reports consisting of the data specified in 30 CFR 203.81, 203.83 and 
203.85 through

[[Page 16]]

203.89, along with one set of digital information, which MMS has 
reviewed and found complete.
    Deep well means either an original well or a sidetrack with a 
perforated interval the top of which is at least 15,000 feet TVD SS. A 
deep well subsequently re-perforated less than 15,000 feet TVD SS in the 
same reservoir is still a deep well.
    Determination means the binding decision by MMS on whether your 
field qualifies for relief or how large a royalty-suspension volume must 
be to make the field economically viable.
    Development project means a project to develop one or more oil or 
gas reservoirs located on one or more contiguous leases that:
    (1) Were issued in a sale held after November 28, 2000;
    (2) Are located in a water depth of at least 200 meters and in the 
GOM wholly west of 87 degrees, 30 minutes West longitude; and
    (3) Have had no production (other than test production) before the 
current application for royalty relief.
    Draft application means the preliminary set of information and 
assumptions you submit to seek a nonbinding assessment on whether a 
field could be expected to qualify for royalty relief.
    Eligible lease means a lease that:
    (1) Is issued as part of an OCS lease sale held after November 28, 
1995, and before November 28, 2000;
    (2) Is located in the Gulf of Mexico in water depths of 200 meters 
or deeper;
    (3) Lies wholly west of 87 degrees, 30 minutes West longitude; and
    (4) Is offered subject to a royalty suspension volume.
    Expansion project means a project you propose in a Development 
Operations Coordination Document (DOCD) or a Supplement approved by the 
Secretary of the Interior after November 28, 1995, that will 
significantly increase the ultimate recovery of resources from one or 
more reservoirs that have not produced on a pre-Act lease or a lease 
issued in a sale held after November 28, 2000. A significant increase 
does not simply extend recovery from reservoirs already in production. 
For a pre-Act lease, the expansion project must also involve a 
substantial capital investment (e.g., fixed-leg platform, subsea 
template and manifold, tension-leg platform, multiple well project, 
etc.). For a lease issued after November 28, 2000, the expansion project 
must involve a new well drilled into a reservoir that has not previously 
produced. In all cases, all leases in an expansion project must be 
wholly located in a water depth of at least 200 meters and in the GOM 
wholly west of 87 degrees, 30 minutes West longitude.
    Fabrication (or start of construction) means evidence of an 
irreversible commitment to a concept and scale of development. Evidence 
includes copies of a binding contract between you (as applicant) and a 
fabrication yard, a letter from a fabricator certifying that continuous 
construction has begun, and a receipt for the customary down payment.
    Field means an area consisting of a single reservoir or multiple 
reservoirs all grouped on, or related to, the same general geological 
structural feature or stratigraphic trapping condition. Two or more 
reservoirs may be in a field, separated vertically by intervening 
impervious strata or laterally by local geologic barriers, or both.
    Lease means a lease or unit.
    New production means any production from a current pre-Act lease 
from which no royalties are due on production, other than test 
production, before November 28, 1995. Also, it means any additional 
production resulting from new lease-development activities on a lease 
issued in a sale after November 28, 2000, or a current pre-Act lease 
under a DOCD or a Supplement approved by the Secretary of the Interior 
after November, 28, 1995.
    Nonbinding assessment means an opinion by MMS of whether your field 
could qualify for royalty relief. It is based on your draft application 
and does not entitle the field to relief.
    Original well means a well that is drilled without utilizing an 
existing wellbore. An original well includes all sidetracks drilled from 
the original wellbore before the drilling rig moves off the well 
location. A bypass from an original well (e.g., drilling around material 
blocking the hole or to straighten crooked holes) is part of the 
original well.

[[Page 17]]

    Participating area means that part of the unit area that MMS 
determines is reasonably proven by drilling and completion of producible 
wells, geological and geophysical information, and engineering data to 
be capable of producing hydrocarbons in paying quantities.
    Performance conditions means minimum conditions you must meet, after 
we have granted relief and before production begins, to remain qualified 
for that relief. If you do not meet each one of these performance 
conditions, we consider it a change in material fact significant enough 
to invalidate our original evaluation and approval.
    Pre-Act lease means a lease that:
    (1) Results from a sale held before November 28, 1995;
    (2) Is located in the GOM in water depths of 200 meters or deeper; 
and
    (3) Lies wholly west of 87 degrees, 30 minutes West longitude.
    Production means all oil, gas, and other relevant products you save, 
remove, or sell from a tract or those quantities allocated to your tract 
under a unitization formula, as measured for the purposes of determining 
the amount of royalty payable to the United States.
    Project means any activity that requires at least a permit to drill.
    Qualified well means a deep well:
    (1) For which drilling begins on or after March 26, 2003;
    (2) That produces natural gas (other than test production), 
including gas associated with oil production, before May 3, 2009; and
    (3) For which you have met the requirements prescribed in Sec. 
203.43.
    Redetermination means our reconsideration of our determination on 
royalty relief because you request it after:
    (1) We have rejected your application;
    (2) We have granted relief but you want a larger suspension volume;
    (3) We withdraw approval; or
    (4) You renounce royalty relief.
    Renounce means action you take to give up relief after we have 
granted it and before you start production.
    Reservoir means an underground accumulation of oil or natural gas, 
or both, characterized by a single pressure system and segregated from 
other such accumulations.
    Royalty suspension (RS) lease means a lease that:
    (1) Is issued as part of an OCS lease sale held after November 28, 
2000;
    (2) Is in locations or planning areas specified in a particular 
Notice of OCS Lease Sale offering that lease; and
    (3) Is offered subject to a royalty suspension specified in a Notice 
of OCS Lease Sale published in the Federal Register.
    Royalty suspension supplement means a royalty suspension volume 
resulting from drilling a certified unsuccessful well that is applied to 
future natural gas and oil production generated at any drilling depth 
on, or allocated under an MMS-approved unit agreement to, the same 
lease.
    Royalty suspension volume means a volume of production from a lease 
that is not subject to royalty under the provisions of this part.
    Sidetrack means, for the purpose of this subpart, a well resulting 
from drilling an additional hole to a new objective bottom-hole location 
by leaving a previously drilled hole. A sidetrack also includes drilling 
a well from a platform slot reclaimed from a previously drilled well or 
re-entering and deepening a previously drilled well. A bypass from a 
sidetrack (e.g., drilling around material blocking the hole, or to 
straighten crooked holes) is part of the sidetrack.
    Sidetrack measured depth means the actual distance or length in feet 
a sidetrack is drilled beginning where it exits a previously drilled 
hole to the bottom hole of the sidetrack, that is, to its total depth.
    Sunk costs for an authorized field means the after-tax eligible 
costs that you (not third parties) incur for exploration, development, 
and production from the spud date of the first discovery on the field to 
the date we receive your complete application for royalty relief. The 
discovery well must be qualified as producible under part 250, subpart A 
of this title. Sunk costs include the rig mobilization and material 
costs for the discovery well that you incurred before its spud date.
    Sunk costs for an expansion or development project means the after-
tax eligible costs that you (not third parties)

[[Page 18]]

incur for only the first well that encounters hydrocarbons in the 
reservoir(s) included in the application and that meets the 
producibility requirements under part 250, subpart A of this chapter on 
each lease participating in the application. Sunk costs include rig 
mobilization and material costs for the discovery wells that you 
incurred before their spud dates.
    Withdraw means action we take on a field that has qualified for 
relief if you have not met one or more of the performance conditions.

[63 FR 2616, Jan. 16, 1998, as amended at 67 FR 1872, Jan. 15, 2002; 69 
FR 3509, Jan. 26, 2004; 69 FR 24053, Apr. 30, 2004]



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  How can I get royalty relief?

    We may reduce or suspend royalties for Outer Continental Shelf (OCS) 
leases or projects that meet the criteria in the following table.

------------------------------------------------------------------------
                                                       Then we may grant
    If you have a lease . . .      And if you . . .        you . . .
------------------------------------------------------------------------
(a) With earnings that cannot     Would abandon       A reduced royalty
 sustain production (i.e., End-    otherwise           rate on current
 of-life lease).                   potentially         monthly
                                   recoverable         production and a
                                   resources but       higher royalty
                                   seek to increase    rate on
                                   production by       additional
                                   operating beyond    monthly
                                   the point at        production. (See
                                   which the lease     Sec. Sec.
                                   is economic under   203.50 through
                                   the existing        203.56.)
                                   royalty rate.
(b) Located in a designated GOM   Are producing and   A royalty
 deep water area, and acquired     seek to increase    suspension for
 in a lease sale before November   ultimate resource   additional
 28, 1995, or after November 28,   recovery from one   production large
 2000, and you propose in a DOCD   or more             enough to make
 or supplement to expand           reservoirs not      the project
 production significantly.         previously or       economic. (See
                                   currently           Sec. Sec.
                                   producing on the    203.60 through
                                   field or lease,     203.79.)
                                   not simply extend
                                   recovery of
                                   reservoirs that
                                   already produced.
                                   (Expansion
                                   project).
(c) Located in a designated GOM   Are on a field      A royalty
 deep water area and acquired in   from which no       suspension for a
 a lease sale held before          current pre-Act     minimum
 November 28, 1995 (Pre-Act        lease produced      production volume
 lease).                           (other than test    plus any
                                   production)         additional volume
                                   before November     needed to make
                                   28, 1995            the field
                                   (Authorized         economic. (See
                                   field).             Sec. Sec.
                                                       203.60 through
                                                       203.79.)
(d) Located in a designated GOM   Have not produced   A royalty
 deep water area and acquired in   and can             suspension for a
 a lease sale held after           demonstrate that    minimum
 November 28, 2000.                the suspension      production volume
                                   volume, if any,     plus any
                                   in your lease is    additional volume
                                   not enough to       needed to make
                                   make development    your project
                                   economic            economic. (See
                                   (Development        Sec. Sec.
                                   project).           203.60 through
                                                       203.79.)
(e) Where royalty relief would    Are not eligible    A royalty
 recover significant additional    to apply for end-   modification in
 resources or, in certain areas    of-life or deep     size, duration,
 of the GOM, would enable          water royalty       or form that
 development.                      relief, but show    makes your lease
                                   us you meet         or project
                                   certain             economic. (See
                                   elligibility        Sec.  203.80.)
                                   conditions.
------------------------------------------------------------------------


[[Page 19]]


[67 FR 1872, Jan. 15, 2002]



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 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 the similar application and 
approval provisions for the discretionary end-of-life and deep water 
royalty relief programs in Sec. Sec. 203.50 to 203.91. Because royalty 
relief for deep gas on leases not subject to deep water royalty relief, 
as provided for under Sec. Sec. 203.40 to 203.48, does not involve an 
application, its provisions do not parallel the other two royalty relief 
programs and are not summarized in this section.
    (a) We require the information elements indicated by an X in the 
following table and described in Sec. Sec. 203.51, 203.62, and 203.81 
through 203.89 for applications for royalty relief.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                             End-of-  ------------------------------------------
                   Information elements                        life       Expansion     Pre-act     Development
                                                              lease        project       lease        project
----------------------------------------------------------------------------------------------------------------
(1) Administrative information report.....................         X               X          X               X
(2) Net revenue and relief justification report                    X
 (prescribed format)......................................
(3) Economic viability and relief justification report      .........              X          X               X
 (Royalty Suspension Viability Program (RSVP) model inputs
 justified with Geological and Geophysical (G&G),
 Engineering, Production, & Cost reports).................
(4) G&G report............................................  .........              X          X               X
(5) Engineering report....................................  .........              X          X               X
(6) Production report.....................................  .........              X          X               X
(7) Deep water cost report................................  .........              X          X               X
----------------------------------------------------------------------------------------------------------------

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

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                             End-of-  ------------------------------------------
                   Confirmation elements                       life       Expansion     Pre-act     Development
                                                              lease        project       lease        project
----------------------------------------------------------------------------------------------------------------
(1) Fabricator's confirmation report......................  .........              X          X               X
(2) Post-production development report approved by an       .........              X          X               X
 independent certified public accountant (CPA)............
----------------------------------------------------------------------------------------------------------------

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

[[Page 20]]



----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                             End-of-  ------------------------------------------
                    Approval conditions                        life                     Pre-act     Development
                                                              lease       Expansion      lease        project
----------------------------------------------------------------------------------------------------------------
(1) At least 12 of the last 15 months have the required            X
 level of production......................................
(2) Already producing.....................................         X
(3)A producible well into a reservoir that has not          .........              X          X               X
 produced before..........................................
(4) Royalties for qualifying months exceed 75% of net              X
 revenue (NR).............................................
(5) Substantial investment on a pre-Act lease (e.g.,
 platform, subsea template)...............................
(6) Determined to be economic only with relief............  .........              X          X               X
----------------------------------------------------------------------------------------------------------------

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

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                             End-of-  ------------------------------------------
                Redetermination conditions                     Life       Expansion     Pre-act     Development
                                                              lease        project       lease        project
----------------------------------------------------------------------------------------------------------------
(1) After 12 months under current rate, criteria same as           X
 for approval.............................................
(2) For material change in geologic data, prices, costs,    .........              X          X               X
 or available technology..................................
----------------------------------------------------------------------------------------------------------------

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

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                             End-of-  ------------------------------------------
   Relief rate and volume, subject to certain conditions       life       Expansion     Pre-act     Development
                                                              lease        project       lease        project
----------------------------------------------------------------------------------------------------------------
(1) 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........................
(2) Qualifying amount is the average monthly production            X
 for 12 qualifying months.................................
(3) Zero royalty rate on the suspension volume and the      .........              X          X               X
 original lease rate on additional production.............
(4) Suspension volume is at least 17.5, 52.5 or 87.5        .........  ..............         X
 million barrels of oil equivalent (MMBOE)................
(5) Suspension volume is at least the minimum set in the    .........              X   .........              X
 Notice of Sale, the lease, or the regulations............
(6) Amount needed to become economic......................  .........              X          X               X
----------------------------------------------------------------------------------------------------------------

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

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                             End-of-  ------------------------------------------
                 Full royalty resumes when                     life       Expansion     Pre-act     Development
                                                              lease        project       lease        project
----------------------------------------------------------------------------------------------------------------
(1) Average NYMEX price for last 12 months is at least 25          X
 percent above the average for the qualifying months......
(2) Average NYMEX price for last calendar year exceeds $28/ .........              X          X
 bbl or $3.50/mcf, escalated by the gross domestic product
 (GDP) deflator since 1994................................
(3) Average prices for designated periods exceed levels we  .........              X   .........              X
 specify in the Notice of Sale or the lease...............
----------------------------------------------------------------------------------------------------------------

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

[[Page 21]]



----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                             End-of-  ------------------------------------------
                Relief withdrawn or reduced                    life       Expansion     Pre-act     Development
                                                              lease        project       lease        project
----------------------------------------------------------------------------------------------------------------
(1) If recipient requests.................................         X               X          X               X
(2) Lease royalty rate is at the effective rate for 12             X
 consecutive months.......................................
(3) Conditions occur that we specified in the approval             X
 letter in individual cases...............................
(4) Recipient does not submit post-production report that   .........              X          X               X
 compares expected to actual costs........................
(5) Recipient changes development system..................  .........              X          X               X
(6) Recipient excessively delays starting fabrication.....  .........              X          X               X
(7) Recipient spends less than 80 percent of proposed pre-  .........              X          X               X
 production costs prior to start of production............
(8) Amount of relief volume is produced...................  .........              X          X               X
----------------------------------------------------------------------------------------------------------------


[67 FR 1873, Jan. 15, 2002, as amended at 69 FR 3509, Jan. 26, 2004]



Sec. 203.5  What is MMS's authority to collect information?

    The Paperwork Reduction Act of 1995 (PRA) requires us to inform you 
that MMS may not conduct or sponsor and you are not required to respond 
to a collection of information unless it displays a currently valid OMB 
control number. OMB approved the information collection requirements in 
this part 203 under 44 U.S.C. 3501 et seq. in two actions. The 
information collection requirements in Sec. Sec. 203.50 through 203.91 
are approved under OMB control number 1010-0071, and those in Sec. Sec. 
203.40 through 203.48 are approved under 1010-0153.

[69 FR 3509, Jan. 26, 2004]



               Subpart B_OCS Oil, Gas, and Sulfur General

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

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

    Source: 69 FR 3510, Jan. 26, 2004, unless otherwise noted.



Sec. 203.40  Which leases are eligible for royalty relief as a result of 

drilling deep wells?

    Your lease may receive a royalty suspension volume under Sec. Sec. 
203.41 through 203.43, and may receive a royalty suspension supplement 
under Sec. Sec. 203.44 through 203.46, if it:
    (a) Was:
    (1) In existence on January 1, 2001;
    (2) Issued in a lease sale held after January 1, 2001, and before 
April 1, 2004, and either the lessee has exercised the option provided 
for in Sec. 203.48 or the lease is located partly in water less than 
200 meters deep and no deep water royalty relief provisions in statutes 
or lease terms apply to the lease; or
    (3) Issued in a lease sale held on or after April 1, 2004, and 
either the lease terms provide for royalty relief under Sec. Sec. 
203.41 through 203.47 of this part or the lease is located partly in 
water less than 200 meters deep and no deep water royalty relief 
provisions in statutes or lease terms apply to the lease;
    (b) Is located:
    (1) In the GOM, wholly west of 87 degrees, 30 minutes West 
longitude;
    (2) Entirely in water less than 200 meters deep, or partly in water 
less than 200 meters deep and no deep-water royalty relief provisions in 
statutes or lease terms apply to the lease; and
    (c) Has not produced gas or oil from a deep well with a perforated 
interval the top of which is 18,000 feet TVD SS or deeper that commenced 
drilling before March 26, 2003.

[69 FR 3510, Jan. 26, 2004, as amended at 70 FR 22252, Apr. 29, 2005]



Sec. 203.41  If I have a qualified well, what royalty relief will my lease 

earn?

    (a) This paragraph and paragraph (b) of this section apply if your 
lease has not produced gas or oil from a deep well that commenced 
drilling before March 26, 2003. Subject to the administrative 
requirements of Sec. 203.43, the provisions of Sec.  203.44(d), and the 
price

[[Page 22]]

conditions in Sec. 203.47, you earn a royalty suspension volume shown 
in the following table in billions of cubic feet (BCF) or in thousands 
of cubic feet (MCF) applicable to gas production as prescribed in Sec. 
203.42:

------------------------------------------------------------------------
                                             Then you earn a royalty
                                            suspension volume on this
 If you have a qualified well that is .    amount of gas production, as
                  . .                     prescribed in this section and
                                                  Sec.  203.42:
------------------------------------------------------------------------
(1) An original well with a perforated   15 BCF.
 interval the top of which is from
 15,000 to less than 18,000 feet TVD SS.
(2) A sidetrack with a perforated        4 BCF plus 600 MCF times
 interval the top of which is from        sidetrack measured depth
 15,000 to less than 18,000 feet TVD SS.  (rounded to the nearest 100
                                          feet) but no more than 15 BCF.
(3) An original well with a perforated   25 BCF.
 interval the top of which is 18,000
 feet TVD SS or deeper.
(4) A sidetrack with a perforated        4 BCF plus 600 MCF times
 interval the top of which is 18,000      sidetrack measured depth
 feet TVD SS or deeper.                   (rounded to the nearest 100
                                          feet) but no more than 25 BCF.
------------------------------------------------------------------------

    (b) We will suspend royalties on gas volumes produced on or after 
May 3, 2004, reported on the Oil and Gas Operations Report, Part A 
(OGOR-A) for your lease under Sec. 216.53, as and to the extent 
prescribed in Sec. 203.42. All gas production from qualified wells 
reported on the OGOR-A, including production that is not subject to 
royalty (except for production to which a royalty suspension supplement 
under Sec. Sec. 203.44 and 203.45 applies), counts toward the lease 
royalty suspension volume.

    Example 1. If you have a qualified well that is an original well 
with a perforated interval the top of which is 16,000 feet TVD SS, you 
earn a royalty suspension volume of 15 BCF of gas production from 
qualified wells on your lease, as prescribed in Sec. 203.42. However, 
if the top of the perforated interval is 18,500 feet TVD SS, the royalty 
suspension volume is 25 BCF.
    Example 2. If you have a qualified well that is a sidetrack with a 
perforated interval the top of which is 16,000 feet TVD SS, that has a 
sidetrack measured depth of 6,789 feet, we round the distance to 6,800 
feet and you earn a royalty suspension volume of 8.08 BCF of gas 
production from qualified wells on your lease, as prescribed in Sec. 
203.42.
    Example 3. If you have a qualified well that is a sidetrack with a 
perforated interval the top of which is 16,000 feet TVD SS, that has a 
sidetrack measured depth of 19,500 feet, you earn a royalty suspension 
volume of 15 BCF of gas production from qualified wells on your lease, 
as prescribed in Sec. 203.42, even though 4 BCF plus 600 MCF per foot 
of sidetrack measured depth equals 15.7 BCF.

    (c) This paragraph and paragraph (d) of this section apply if your 
lease has produced gas or oil from a deep well with a perforated 
interval the top of which is from 15,000 to less than 18,000 feet TVD SS 
(regardless of whether drilling began before or after March 26, 2003), 
and you subsequently have a qualified well on your lease with a 
perforated interval the top of which is 18,000 feet TVD or deeper. 
Subject to the administrative requirements of Sec. 203.43, the 
provisions of Sec. 203.44(d), and the price conditions in Sec.  203.47, 
you earn a royalty suspension volume specified in the following table, 
applicable to gas production as prescribed in Sec. 203.42. This royalty 
suspension volume is in addition to any royalty suspension volume your 
lease already may have earned, if any, as a result of a qualified well 
with a perforated interval the top of which is from 15,000 to less than 
18,000 feet TVD SS.

------------------------------------------------------------------------
 If your lease has produced gas or oil
   from a deep well with a perforated        Then, you earn a royalty
   interval the top of which is from        suspension volume on this
15,000 to less than 18,000 feet TVD SS,    amount of gas production, as
 and you subsequently have a qualified    prescribed in this section and
           well that is . . .                     Sec.  203.42
------------------------------------------------------------------------
(1) An original well or a sidetrack      0 BCF.
 with a perforated interval the top of
 which is from 15,000 to less than
 18,000 feet TVD SS.
(2) An original well with a perforated   10 BCF.
 interval the top of which is 18,000
 feet TVD SS or deeper.
(3) A sidetrack with a perforated        4 BCF plus 600 MCF times
 interval the top of which is 18,000      sidetrack measured depth
 feet TVD SS or deeper.                   (rounded to the nearest 100
                                          feet) but no more than 10 BCF.
------------------------------------------------------------------------

    (d) We will suspend royalties on gas volumes produced on or after 
May 3, 2004, reported on the Oil and Gas Operations Report, Part A 
(OGOR-A) for

[[Page 23]]

your lease under Sec. 216.53, as and to the extent prescribed in Sec.  
203.42. All gas production from qualified wells reported on the OGOR-A, 
including production that is not subject to royalty (except for 
production to which a royalty suspension supplement under Sec. Sec. 
203.44 and 203.45 applies), counts toward the lease royalty suspension 
volume.

    Example 1. If you have drilled and produced a well with a perforated 
interval the top of which is 16,000 feet TVD SS before March 26, 2003 
(and therefore, it is not a qualified well and has earned no royalty 
suspension volume) and later drill:
    (i) A well with a perforated interval the top of which is 17,000 
feet TVD SS, you earn no royalty suspension volume.
    (ii) A qualified well that is an original well with a perforated 
interval the top of which is 19,000 feet TVD SS, you earn a royalty 
suspension volume of 10 BCF of gas production from qualified wells on 
your lease, as prescribed in Sec. 203.42.
    (iii) A qualified well that is a sidetrack with a perforated 
interval the top of which is 19,000 feet TVD SS, that has a sidetrack 
measured depth of 7,000 feet, you earn a royalty suspension volume of 
8.2 BCF of gas production from qualified wells on your lease, as 
prescribed in Sec. 203.42.
    Example 2. If you have a qualified well (i.e., drilled after March 
26, 2003) that is an original well with a perforated interval the top of 
which is 16,000 feet TVD SS and later drill a second qualified well that 
is an original well with a perforated interval the top of which is 
19,000 feet TVD SS, we increase the total royalty suspension volume for 
your lease from 15 BCF to 25 BCF, as prescribed in Sec. 203.42.
    Example 3. If you have a qualified well (i.e., drilled after March 
26, 2003) that is a sidetrack with a perforated interval the top of 
which is 16,000 feet TVD SS, that has a sidetrack measured depth of 
4,000 feet, and later drill a second qualified well that is a sidetrack 
with a perforated interval the top of which is 19,000 feet TVD SS, that 
has a sidetrack measured depth of 8,000 feet, we increase the total 
royalty suspension volume for your lease from 6.4 BCF to 15.2 BCF, as 
prescribed in Sec. 203.42. The difference of 8.8 BCF represents the 
royalty suspension volume earned by the second sidetrack.

    (e) After your lease has produced gas or oil from a deep well with a 
perforated interval the top of which is 18,000 feet TVD SS or deeper, 
your lease cannot earn a royalty suspension volume as a result of 
drilling any subsequent qualified wells.
    (f) The royalty suspension volume determined under this section for 
the first qualified well on your lease (whether an original well or a 
sidetrack) establishes the total royalty suspension volume available for 
that drilling depth interval on your lease, regardless of the number of 
subsequent qualified wells you drill to that depth interval.

    Example to paragraph (f): If your first qualified well is a 
sidetrack with a perforated interval the top of which is 16,000 feet TVD 
SS and earns a royalty suspension volume of 12.5 BCF, and you later 
drill a qualified original well to 17,000 feet TVD SS, the royalty 
suspension volume for your lease remains at 12.5 BCF and does not 
increase to 15 BCF. However, under paragraph (b) of this section, if you 
subsequently drill a qualified well to another depth interval 18,000 
feet or greater TVD SS, you may earn an additional royalty suspension 
volume.

    (g) If a qualified well on your lease is within a unitized portion 
of your lease, the royalty suspension volume earned by that well under 
this section applies only to your lease and not to other leases within 
the unit.
    (h) If your qualified well is a directional well (either an original 
well or a sidetrack) drilled across a lease line, the lease with the 
perforated interval that initially produces earns the royalty suspension 
volume. However, if the perforated interval crosses a lease line, the 
lease where the surface of the well is located earns the royalty 
suspension volume.
    (i) Any royalty suspension volume earned under this section is in 
addition to any royalty suspension supplement for your lease under Sec. 
203.44 that results from a different wellbore.
    (j) If your lease earns a royalty suspension volume under this 
section and later produces from a deep well that is not a qualified 
well, the royalty suspension volume is not forfeited or terminated. 
However, you may not apply the royalty suspension volume under this 
section to production from the deep well that is not a qualified well, 
even if it begins producing after your first qualified well.
    (k) You owe minimum royalties or rentals in accordance with your 
lease terms notwithstanding any royalty

[[Page 24]]

suspension volumes allowed under paragraphs (a) and (b) of this section.

[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24053, Apr. 30, 2004]



Sec. 203.42  To which production do I apply the royalty suspension volume 

earned from qualified wells on my lease?

    (a) This paragraph applies to any lease that is not within an MMS-
approved unit. Subject to the requirements of Sec. Sec. 203.40, 203.41, 
203.43, 203.44, and 203.47, you must apply the royalty suspension 
volumes prescribed in Sec. 203.41 to the earliest gas production:
    (1) Occurring on and after the later of May 3, 2004, or the date 
that the first qualified well that earns your lease the royalty 
suspension volume begins production (other than test production);
    (2) From all qualified wells, regardless of their depth, on your 
lease for which you have met the requirements in Sec. 203.43, up to the 
aggregate royalty suspension volume earned by your lease.

    Example to paragraph (a): You began drilling an original well that 
was a qualified well with a perforated interval the top of which is 
18,200 feet TVD SS on May 1, 2003 and it began producing on September 1, 
2003. You subsequently drilled two more original wells that are 
qualified wells with a perforated interval the tops of which are 16,600 
feet TVD SS. The first well earned a royalty suspension volume of 25 
BCF. You must apply the royalty suspension volume each month beginning 
on March 1, 2004 to production from all three wells until the 25 BCF 
royalty suspension volume is fully utilized.

    (b) This paragraph applies to any lease all or part of which is 
within an MMS-approved unit. If your lease has a qualified well, a share 
of the production from all the qualified wells in the unit participating 
area will be allocated to your lease each month according to the 
participating area percentages. Subject to the requirements of 
Sec. Sec. 203.40, 203.41, 203.43, 203.44, and 203.47, you must apply 
the royalty suspension volume to the earliest gas production occurring 
on and after the later of May 3, 2004, or the date that the first 
qualified well that earns your lease the royalty suspension volume 
begins production (other than test production):
    (1) From all qualified wells on the non-unitized area of your lease 
and
    (2) Allocated to your lease from qualified wells on unitized areas 
of your lease and other leases in the unit under an MMS-approved unit 
agreement. That allocated share does not increase the royalty suspension 
volume for your lease. None of the volumes produced from a well that is 
not within a unit participating area may be allocated to other leases in 
the unit.

    Example to paragraph (b): The east half of your lease A is unitized 
with all of lease B. There is one qualified well on the non-unitized 
portion of lease A, one qualified well on the unitized portion of lease 
A and a qualified well on lease B. The participating area percentages 
allocate 32 percent of production from both of the unit qualified wells 
to lease A and 68 percent to lease B. If the non-unitized qualified well 
on lease A produces 12,000 MCF and the unitized qualified well on lease 
A produces 15,000 MCF, and the qualified well on lease B produces 10,000 
MCF, then the production volume from and allocated to lease A to which 
the lease A royalty suspension volume applies is 20,000 MCF [12,000 + 
(15,000 + 10,000)(32 percent)]. The production volume allocated to lease 
B to which the lease B royalty suspension volume applies is 17,000 MCF 
[(15,000 + 10,000)(68 percent)].

    (c) Unused royalty suspension volume transfers to a successor lessee 
and expires with the lease.
    (d) You may not apply the royalty suspension volume allowed under 
Sec. 203.41:
    (1) To production from completions less than 15,000 feet TVD SS, 
except in cases where the qualified well is re-perforated in the same 
reservoir previously perforated deeper than 15,000 feet TVD SS;
    (2) To production from a deep well that commenced drilling before 
March 26, 2003; or
    (3) To production from a deep well on any other lease, except as 
provided in paragraph (b) of this section.
    (e) You must begin paying royalties when the cumulative production 
of gas from all qualified wells on your lease, or allocated to your 
lease under paragraph (b) of this section, reaches the applicable 
royalty suspension volume allowed under Sec. 203.41. For the month in 
which cumulative production reaches this royalty suspension volume, you

[[Page 25]]

owe royalties on the portion of gas production that exceeds the royalty 
suspension volume remaining at the beginning of that month.
    (f) No royalty suspension volume may be applied to any liquid 
hydrocarbon (oil and condensate) volumes.

[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004]



Sec. 203.43  What administrative steps must I take to use the royalty 

suspension volume?

    (a) You must notify, in writing, the MMS Regional Supervisor for 
Production and Development of your intent to begin drilling operations 
on all deep wells; and
    (b) Within 30 days of the beginning of production from all wells 
that would become qualified wells by satisfying the requirements of this 
section, you must:
    (1) Provide written notification to the MMS Regional Supervisor for 
Production and Development that production has begun; and
    (2) Request confirmation of the size of the royalty suspension 
volume earned by your lease.
    (c) Before beginning production, you must meet any production 
measurement requirements that the MMS Regional Supervisor for Production 
and Development has determined are necessary under 30 CFR part 250, 
subpart L.
    (d) If you produced from a qualified well before May 3, 2004, you 
must provide the information in paragraph (b) of this section no later 
than August 3, 2004.
    (e) If you cannot produce from a well that otherwise meets the 
criteria for a qualified well before May 3, 2009, the MMS Regional 
Supervisor for Production and Development may extend the deadline for 
beginning production for up to 1 year, based on the circumstances of the 
particular well involved, provided you demonstrate that:
    (1) The delay occurred after reaching total depth in your well;
    (2) Production (other than test production) was expected to begin 
before March 1, 2009; and
    (3) The delay in beginning production is for reasons beyond your 
control, including but not limited to adverse weather and unavoidable 
accidents.

[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004]



Sec. 203.44  If I drill a certified unsuccessful well, what royalty relief 

will my lease earn?

    Your lease may earn a royalty suspension supplement. Subject to 
paragraph (d) of this section, the royalty suspension supplement is in 
addition to any royalty suspension volume your lease may earn under 
Sec. 203.41.
    (a) If you drill a certified unsuccessful well and you satisfy the 
administrative requirements of Sec. 203.46 and subject to the price 
conditions in Sec. 203.47, you earn a royalty suspension supplement 
shown in the following table (in billions of cubic feet of gas 
equivalent (BCFE) or in thousands of cubic feet of gas equivalent 
(MCFE)) applicable to oil and gas production as prescribed in Sec. 
203.45:

------------------------------------------------------------------------
                                             Then, you earn a royalty
                                          suspension supplement on this
  If you have a certified unsuccessful        volume of oil and gas
           well that is . . .              production as prescribed in
                                         this section and Sec.  203.45:
------------------------------------------------------------------------
(1) An original well and your lease has  5 BCFE.
 not produced gas or oil from a deep
 well.
(2) A sidetrack (with a sidetrack        0.8 BCFE plus 120 MCFE times
 measured depth of at least 10,000        sidetrack measured depth
 feet) and your lease has not produced    (rounded to the nearest 100
 gas or oil from a deep well.             feet) but no more than 5 BCFE.
(3) An original well or a sidetrack      2 BCFE.
 (with a sidetrack measured depth of at
 least 10,000 feet) and your lease has
 produced gas or oil from a deep well
 with a perforated interval the top of
 which is from 15,000 to less than
 18,000 feet TVD SS.
------------------------------------------------------------------------

    (b) We will suspend royalties on oil and gas volumes produced on or 
after May 3, 2004, reported on the Oil and Gas Operations Report, Part A 
(OGOR-A) for your lease under Sec. 216.53, as and to the extent 
prescribed in Sec. 203.45. All oil and gas production reported on the 
OGOR-A, including production that is

[[Page 26]]

not subject to royalty (except for production to which a royalty 
suspension volume under Sec. Sec. 203.41 and 203.42 applies), counts 
toward the lease royalty suspension supplement.

    Example 1. If you drill a certified unsuccessful well that is an 
original well to a target 19,000 feet TVD SS, you earn a royalty 
suspension supplement of 5 BCFE of gas and oil production if your lease 
has not previously produced from a deep well, or you earn a royalty 
suspension supplement of 2 BCFE of gas and oil production if your lease 
has previously produced from a deep well with a perforated interval from 
15,000 to less than 18,000 feet TVD SS, as prescribed in Sec. 203.45.
    Example 2. If you drill a certified unsuccessful well that is a 
sidetrack that reaches a target 19,000 feet TVD SS, that has a sidetrack 
measured depth of 12,545 feet, and your lease has not produced gas or 
oil from any deep well, we round the distance to 12,500 feet and you 
earn a royalty suspension supplement of 2.3 BCFE of gas and oil 
production as prescribed in Sec. 203.45.

    (c) The conversion from oil to gas for using the royalty suspension 
supplement is specified in Sec. 203.73.
    (d) Each lease is eligible for up to two royalty suspension 
supplements. Therefore, the total royalty suspension supplement for a 
lease cannot exceed 10 BCFE.
    (1) You may not earn more than one royalty suspension supplement 
from a single wellbore.
    (2) If you begin drilling a certified unsuccessful well on one lease 
but the completion target is on a second lease, the entire royalty 
suspension supplement belongs to the second lease. However, if the 
target straddles a lease line, the lease where the surface of the well 
is located earns the royalty suspension supplement.
    (e) If the same wellbore that earns a royalty suspension supplement 
as a certified unsuccessful well later produces from a perforated 
interval the top of which is 15,000 feet TVD SS or deeper before May 3, 
2009, it will become a qualified well subject to the following 
conditions:
    (1) Beginning on the date production starts, you must stop applying 
the royalty suspension supplement earned by that wellbore to your lease 
production.
    (2) If the completion of this qualified well is on your lease or, in 
the case of a directional well, is on another lease, then you must 
subtract from the royalty suspension volume earned by that qualified 
well the royalty suspension supplement amounts earned by that wellbore 
that have already been applied either on your lease or any other lease. 
The difference represents the royalty suspension volume earned by the 
qualified well.
    (f) If the same wellbore that earned a royalty suspension supplement 
later has a sidetrack drilled from that wellbore, you are not required 
to subtract any royalty suspension supplement earned by that wellbore 
from the royalty suspension volume that may be earned by the sidetrack.
    (g) You owe minimum royalties or rentals in accordance with your 
lease terms notwithstanding any royalty suspension supplements under 
this section.

[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004; 72 
FR 25198, May 4, 2007]



Sec. 203.45  To which production do I apply the royalty suspension 

supplements from drilling one or two certified unsuccessful wells on my lease?

    (a) Subject to the requirements of Sec. Sec. 203.40, 203.42, 
203.44, 203.46 and 203.47, you must apply royalty suspension supplements 
in Sec. 203.44 to the earliest oil and gas production:
    (1) Occurring on and after the day you file the information under 
Sec. 203.46(b),
    (2) From, or allocated under an MMS-approved unit agreement to, the 
lease on which the certified unsuccessful well was drilled, without 
regard to the drilling depth of the well producing the gas or oil.
    (b) If you have a royalty suspension volume for the lease under 
Sec. 203.41, you must use the royalty suspension volumes for gas 
produced from qualified wells on the lease before using royalty 
suspension supplements for gas produced from qualified wells.

    Example to paragraph (b): You have two shallow oil wells on your 
lease. Then you drill a certified unsuccessful well and earn a royalty 
suspension supplement of 5 BCFE. Thereafter, you begin production from 
an original well that is a qualified well that earns a royalty 
suspension volume of 15 BCF.

[[Page 27]]

You use only 2 BCFE of the royalty suspension supplement before the oil 
wells deplete. You must use up the 15 BCF of royalty suspension volume 
before you use the remaining 3 BCFE of the royalty suspension supplement 
for gas produced from the qualified well.

    (c) If you have no current production on which to apply the royalty 
suspension supplement allowed under Sec. 203.44, your royalty 
suspension supplement applies to the earliest subsequent production of 
gas and oil from, or allocated under an MMS-approved unit agreement to, 
your lease.
    (d) Unused royalty suspension supplements transfer to a successor 
lessee and expire with the lease.
    (e) You may not apply the royalty suspension supplement allowed 
under Sec. 203.44 to production from any other lease, except for 
production allocated to your lease from an MMS-approved unit agreement. 
If your certified unsuccessful well is on a lease subject to an MMS-
approved unit agreement, the lessees of other leases in the unit may not 
apply any portion of the royalty suspension supplement for your lease to 
production from the other leases in the unit.
    (f) You must begin or resume paying royalties when cumulative gas 
and oil production from, or allocated under an MMS-approved unit 
agreement to, your lease (excluding any gas produced from qualified 
wells subject to a royalty suspension volume allowed under Sec. 203.41) 
reaches the applicable royalty suspension supplement. For the month in 
which the cumulative production reaches this royalty suspension 
supplement, you owe royalties on the portion of gas or oil production 
that exceeds the amount of the royalty suspension supplement remaining 
at the beginning of that month.



Sec. 203.46  What administrative steps do I take to obtain and use the 

royalty suspension supplement?

    (a) Before you start drilling a well on your lease targeted to a 
reservoir at least 18,000 feet TVD SS, you must notify, in writing, the 
MMS Regional Supervisor for Production and Development of your intent to 
begin drilling operations and the depth of the target.
    (b) After drilling the well, you must provide the MMS Regional 
Supervisor for Production and Development within 60 days after reaching 
the total depth in your well:
    (1) Information that allows MMS to confirm that you drilled a 
certified unsuccessful well as defined under Sec. 203.0, including:
    (i) Well log data, if your original well or sidetrack does not meet 
the producibility requirements of 30 CFR part 250, subpart A; or
    (ii) Well log, well test, seismic, and economic data, if your well 
does meet the producibility requirements of 30 CFR part 250, subpart A; 
and
    (2) Information that allows MMS to confirm the size of the royalty 
suspension supplement for a sidetrack, including sidetrack measured 
depth and supporting documentation.
    (c) If you commenced drilling a well that otherwise meets the 
criteria for a certified unsuccessful well on or after March 26, 2003, 
and finished it before May 3, 2004, provide the information in paragraph 
(b) of this section no later than August 3, 2004.

[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004]



Sec. 203.47  Do I keep royalty relief if prices rise significantly?

    (a) You must pay royalties on all gas and oil production for which 
royalty suspension volume or royalty suspension supplement otherwise 
would be allowed under Sec. Sec. 203.40 through 203.46 for any calendar 
year when the average daily closing NYMEX natural gas price exceeds the 
threshold of $9.34 per MMBtu, adjusted annually after year 2004 for 
inflation. The threshold price for any calendar year after 2004 is found 
by adjusting the threshold price in the previous year by the percentage 
that the implicit price deflator for the gross domestic product as 
published by the Department of Commerce changed during the calendar 
year.
    (b) You must pay any royalty due under this paragraph, plus late 
payment interest from the end of the month after the month of production 
until the date of payment under 30 CFR 218.54, no later than 90 days 
after the end of the calendar year for which you owe royalty.
    (c) Production volumes on which you must pay royalty under this 
section

[[Page 28]]

count as part of your royalty suspension volumes and royalty suspension 
supplements.



Sec. 203.48  May I substitute the deep gas drilling provisions in Sec.  203.0 

and Sec. Sec. 203.40 through 203.47 for the deep gas royalty relief provided 

in my lease terms?

    (a) You may exercise an option to replace the applicable lease terms 
for royalty relief related to deep-well drilling with those in Sec. 
203.0 and Sec. Sec. 203.40 through 203.47 if you have a lease issued 
with royalty relief provisions for deep-well drilling. Such leases:
    (1) Must be issued as part of an OCS lease sale held after January 
1, 2001, and before April 1, 2004; and
    (2) Must be located wholly west of 87 degrees, 30 minutes West 
longitude in the GOM entirely or partly in water less than 200 meters 
deep.
    (b) To exercise the option under paragraph (a) of this section, you 
must notify, in writing, the MMS Regional Supervisor for Production and 
Development of your decision before September 1, 2004 or 180 days after 
your lease is issued, whichever is later, and specify the lease and 
block number.
    (c) Once you exercise the option under paragraph (a) of this 
section, you are subject to all the activity, timing, and administrative 
requirements pertaining to deep gas royalty relief as specified in 
Sec. Sec. 203.40 through 203.47.
    (d) Exercising the option under paragraph (a) of this section is 
irrevocable. If you do not exercise this option, then the terms of your 
lease apply.

                  Royalty Relief for End-of-life Leases



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., 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

[[Page 29]]

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 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?

    You may apply for royalty relief under Sec. Sec. 203.61(b) and 
203.62 if:
    (a) You are a lessee of a lease in water at least 200 meters deep in 
the GOM and lying wholly west of 87 degrees, 30 minutes West longitude;
    (b) We have assigned your pre-Act lease to a field (as defined in 
Sec. 203.0); and
    (c) You either:
    (1) Hold a pre-Act lease on an authorized field (as defined in Sec. 
203.0) or
    (2) Propose an expansion project (as defined in Sec. 203.0) or
    (3) Propose a development project (as defined in Sec. 203.0).

[67 FR 1875, Jan. 15, 2002]



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

[[Page 30]]

    (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 
Regional Director for the GOM.
    (a) Your application for deep water royalty relief must include an 
original and two copies (one set of digital information) of:
    (1) Administrative information report;
    (2) Deep water economic viability and relief justification report;
    (3) G&G report;
    (4) Engineering report;
    (5) Production report; and
    (6) Deep water cost report.
    (b) Section 203.82 explains why we are authorized to require these 
reports.
    (c) Sections 203.81, 203.83, and 203.85 through 203.89 describe what 
these reports must include. The MMS regional office for the GOM will 
guide you on the format for the required reports, and we encourage you 
to contact this office prior to preparing your application for this 
guidance.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]



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

    (a) For authorized fields, we will accept only one joint application 
for all leases that are part of the designated field on the date of 
application, except as provided in paragraph (a)(3) of this section and 
Sec. 203.64. However, we will evaluate all acreage that may eventually 
become part of the authorized field. Therefore, if you have any other 
leases that you believe may eventually be part of the authorized field, 
you must submit data for these leases according to Sec. 203.81.
    (1) The Regional Director maintains a Field Names Master List with 
updates of all leases in each designated field.
    (2) To avoid sharing proprietary data with other lessees on the 
field, you may submit your proprietary G&G report separately from the 
rest of your application. Your application is not complete until we 
receive all the required information for each lease on the field. We 
will not disclose proprietary data when explaining our assumptions and 
reasons for our determinations under Sec. 203.67.
    (3) We will not require a joint application if you show good cause 
and honest effort to get all lessees in the field to participate. If you 
must exclude a lease from your application because its lessee will not 
participate, that lease is ineligible for the royalty relief for the 
designated field.
    (b) If your application seeks only relief for a development project 
or an expansion project, your application does not have to include all 
leases in the field.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]



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

project?

    You may file one complete application for royalty relief during the 
life of the field or for a development project or an expansion project 
designed to produce a reservoir or set of reservoirs. However, you may 
send another application if:
    (a) You are eligible to apply for a redetermination under 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.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]

[[Page 31]]



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, evaluate your first application on a development project or an 
expansion project within 150 days and evaluate a redetermination under 
Sec. 203.75 within 120 days after we determine that it is complete.
    (c) We may ask to extend the review period for your application 
under the conditions in the following table.

------------------------------------------------------------------------
                If--                            Then we may--
------------------------------------------------------------------------
We need more records to audit sunk   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.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]



Sec. 203.66  What happens if MMS does not act in the time allowed?

    If we do not act within the timeframes established under Sec. 
203.65, you get royalty relief according to the following table.

------------------------------------------------------------------------
                                     And we do not
 If you apply for royalty relief   decide within the    As long as you
               for                  time specified
------------------------------------------------------------------------
(a) An authorized field.........  You get the         Abide by Sec.
                                   minimum             Sec.  203.70 and
                                   suspension          203.76.
                                   volumes specified
                                   in Sec.  203.69.
(b) An expansion project........  You get a royalty   Abide by Sec.
                                   suspension for      Sec.  203.70 and
                                   the first year of   203.76.
                                   production.
(c) A development project.......  You get a royalty   Abide by Sec.
                                   suspension for      Sec.  203.70 and
                                   initial             203.76.
                                   production for
                                   the number of
                                   months that a
                                   decision is
                                   delayed beyond
                                   the stipulated
                                   timeframes set by
                                   Sec.  203.65,
                                   plus all the
                                   royalty
                                   suspension volume
                                   for which you
                                   qualify.
------------------------------------------------------------------------


[67 FR 1875, Jan. 15, 2002]



Sec. 203.67  What economic criteria must I meet to get royalty relief on an 

authorized field or project?

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

[67 FR 1876, Jan. 15, 2002]

[[Page 32]]



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 according to the following table.

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


[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1876, Jan. 15, 2002]



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

receive?

    If we approve your application, subject to certain conditions, we 
will not collect royalties on a specified suspension volume for your 
field, development project, or expansion project. Suspension volumes 
include volumes allocated to a lease under an approved unit agreement, 
but exclude any volumes of production that are not normally royalty-
bearing under the lease or the regulations of this chapter (e.g., fuel 
gas).
    (a) For authorized fields, the minimum royalty-suspension volumes 
are:
    (1) 17.5 million barrels of oil equivalent (MMBOE) for fields in 200 
to 400 meters of water;
    (2) 52.5 MMBOE for fields in 400 to 800 meters of water; and
    (3) 87.5 MMBOE for fields in more than 800 meters of water.
    (b) For development projects, any relief we grant applies only to 
project wells and replaces the royalty suspension volume with which we 
issued your lease. If your project is economic given the royalty 
suspension volume with which we issued your lease, we will reject the 
application. Otherwise, the minimum royalty suspension volumes are as 
shown in the following table:

------------------------------------------------------------------------
                                  The minimum royalty
              For                suspension volume is         Plus
------------------------------------------------------------------------
(1) RS leases.................  A volume equal to the   10 percent of
                                 combined royalty        the median of
                                 suspension volumes      the
                                 (or the volume          distribution of
                                 equivalent based on     known
                                 the data in your        recoverable
                                 approved application    resources upon
                                 for other forms of      which we based
                                 royalty suspension)     approval of
                                 with which we issued    your
                                 the leases              application
                                 participating in the    from all
                                 application that have   reservoirs
                                 or plan a well into a   included in the
                                 reservoir identified    project.
                                 in the application.
(2) Other deep water leases     A volume equal to 10
 issued in sales after           percent of the median
 November 28, 2000.              of the distribution
                                 of known recoverable
                                 resources upon which
                                 we based approval of
                                 your application from
                                 all reservoirs
                                 included in the
                                 project.
------------------------------------------------------------------------

    (c) If your application includes pre-Act or eligible leases in 
different categories of water depth, we apply the minimum royalty 
suspension volume for the deepest such lease then assigned to the field. 
We base the water depth and makeup of a field on the water-depth 
delineations in the ``Lease Terms and Economic Conditions'' map and the 
``Field Names Master List'' documents and updates in effect at the time 
your application is deemed complete. These publications are available 
from the MMS Regional Office for the GOM.
    (d) You will get a royalty suspension volume above the minimum if we 
determine that you need more to make

[[Page 33]]

the field or development project economic.
    (e) For expansion projects, the minimum royalty suspension volume 
equals 10 percent of the median of the distribution of known recoverable 
resources upon which we based approval of your application from all 
reservoirs included in your project plus any suspension volumes required 
under Sec. 203.66. If we determine that your expansion project may be 
economic only with more relief, we will determine and grant you the 
royalty suspension volume necessary to make the project economic.
    (f) The royalty suspension volume applicable to specific leases will 
continue through the end of the month in which cumulative production 
reaches that volume. You must calculate cumulative production from all 
the leases in the authorized field or project that are entitled to share 
the royalty suspension volume.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1876, Jan. 15, 2002]



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, 203.90, and 203.91 describe what these reports must 
include. The MMS regional office for the GOM will prescribe the formats.

------------------------------------------------------------------------
                                                           Due date
         Required report            When due to MMS       extensions
------------------------------------------------------------------------
(a) Fabricator's confirmation     Within 18 months    MMS Director may
 report.                           after approval of   grant you an
                                   relief.             extension under
                                                       Sec.  203.79(c)
                                                       for up to 6
                                                       months.
(b) Post-production report......  Within 120 days     With acceptable
                                   after the start     justification
                                   of production       from you, MMS
                                   that is subject     Regional Director
                                   to the approved     for the GOM may
                                   royalty             extend due date
                                   suspension volume.  up to 30 days.
------------------------------------------------------------------------


[67 FR 1876, Jan. 15, 2002]



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

------------------------------------------------------------------------
            If . . .                  Then . . .           And . . .
------------------------------------------------------------------------
(1) We assign an eligible lease   We will not change  The assigned
 to your field after we approve    your field's        lease(s) may
 relief.                           royalty             share in any
                                   suspension volume.  remaining royalty
                                                       relief.
(2) We assign a pre-Act or post-  We will not change  The assigned
 November 2000 deep water lease    your field's        lease(s) may
 to your field after we approve    royalty             share in any
 your application.                 suspension volume.  remaining royalty
                                                       relief by filing
                                                       the short-form
                                                       application
                                                       specified in Sec.
                                                         203.83 and
                                                       authorized in
                                                       Sec.  203.82. An
                                                       assigned RS lease
                                                       also gets any
                                                       portion of its
                                                       royalty
                                                       suspension volume
                                                       remaining even
                                                       after the field
                                                       has produced the
                                                       approved relief
                                                       volume.

[[Page 34]]

 
(3) We assign another lease(s)    We will change      (i) You toll the
 that you operate to your field    your field's        time period for
 while we are evaluating your      minimum             evaluation until
 application.                      suspension volume   you modify your
                                   if the assigned     application to be
                                   lease is a pre-     consistent with
                                   Act or eligible     the new field;
                                   lease entitled to  (ii) We have an
                                   a larger minimum    additional 60
                                   or automatic        days to review
                                   suspension volume.  the new
                                                       information; and
                                                      (iii) The assigned
                                                       lease(s) shares
                                                       the royalty
                                                       suspension we
                                                       grant to the new
                                                       field. If you do
                                                       not agree to
                                                       toll, we will
                                                       have to reject
                                                       your application
                                                       due to incomplete
                                                       information. But,
                                                       an eligible lease
                                                       we assigned to
                                                       the field kept
                                                       its automatic
                                                       suspension
                                                       volume.
(4) We assign another operator's  We will change      (i) You both toll
 lease to your field while we      your field's        the time period
 are evaluating your application.  minimum             for evaluation
                                   suspension volume   until both of you
                                   provided the        modify your
                                   assigned lease      application to be
                                   joins the           consistent with
                                   application and     the new field;
                                   is entitled to a   (ii) We have an
                                   larger minimum      additional 60
                                   suspension volume.  days to review
                                                       the new
                                                       information; and
                                                      (iii) The assigned
                                                       lease(s) shares
                                                       the royalty
                                                       suspension we
                                                       grant to the new
                                                       field. If you
                                                       (the original
                                                       applicant) do not
                                                       agree to toll,
                                                       the other
                                                       operator's lease
                                                       retains any
                                                       suspension volume
                                                       it has or may
                                                       share in any
                                                       relief that we
                                                       grant by filing
                                                       the short form
                                                       application
                                                       specified in Sec.
                                                         203.83 and
                                                       authorized in
                                                       Sec.  203.82.
(5) We reassign a well on a pre-  The past            The past
 Act, eligible, or post-November   production from     production from
 2000 deep water lease to          the well counts     that well will
 another field.                    toward the          not count toward
                                   royalty             any royalty
                                   suspension volume   suspension volume
                                   of the field to     granted to the
                                   which we assigned   field from which
                                   the well.           we reassigned it.
------------------------------------------------------------------------

    (b) If your authorized field has a royalty suspension volume 
established under Sec. 260.111 of this title (i.e., a field with a pre-
Act lease where an eligible lease starts production first), we will 
suspend payment of royalties on production from all eligible leases in 
the field until their cumulative production equals the established 
volume. The following conditions also apply:

------------------------------------------------------------------------
            If . . .                  Then . . .           And . . .
------------------------------------------------------------------------
(1) We assign another eligible    Your field's        The assigned lease
 lease to your field.              royalty             may share in any
                                   suspension volume   remaining royalty
                                   does not change.    relief.
(2) We assign an RS lease to      Your field's        The assigned lease
 your field.                       royalty             gets only the
                                   suspension volume   volume suspension
                                   does not change.    with which we
                                                       issued it, and
                                                       its production
                                                       volume counts
                                                       against the
                                                       field's royalty
                                                       suspension
                                                       volume.
(3) We assign a pre-Act lease or  Your field's        We assign lease
 a lease issued after November     royalty             shares none of
 2000 without royalty suspension   suspension volume   the volume
 to your field.                    does not change.    suspension, and
                                                       its production
                                                       does not count as
                                                       part of the
                                                       suspension
                                                       volume.
(4) A pre-Act or post-November    Your field's        (i) All leases in
 2000 deep water lease applies     royalty             the field share
 (along with the other leases in   suspension volume   the royalty
 the field) and qualifies          may increase or     suspension volume
 (subject to any pre-existing      stay the same,      if we approve the
 suspension volumes) for royalty   but will not        application; or
 relief under Sec. Sec.           diminish.          (ii) The eligible
 203.67 and 203.69.                                    or RS leases in
                                                       the field keep
                                                       their respective
                                                       volumes if we
                                                       reject the
                                                       application.
------------------------------------------------------------------------

    (c) When a project has more than one lease, the royalty suspension 
volume for each lease equals that lease's actual production from the 
project (or production allocated under an approved unit agreement) until 
total production for all leases in the project equals the project's 
approved royalty suspension volume.
    (d) You may receive a royalty-suspension volume only if your entire 
lease is west of 87 degrees, 30 minutes West longitude. If the field 
lies on both

[[Page 35]]

sides of this meridian, only leases located entirely west of the 
meridian will receive a royalty-suspension volume.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1877, Jan. 15, 2002]



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-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?

    You may request a redetermination after we withdraw approval or 
after you renounce royalty relief, unless we withdraw approval due to 
your providing false or intentionally inaccurate information. Under 
certain conditions you may also request a redetermination if we deny 
your application or if you want your approved royalty suspension volume 
to change. In these instances, to be eligible for a redetermination, at 
least one of the following four conditions must occur.
    (a) You have significant new G&G data and you previously have not 
either requested a redetermination or reapplied for relief after we 
withdrew approval or you relinquished royalty relief. ``Significant'' 
means that the new G&G data:
    (1) Results from drilling new wells or getting new three-dimensional 
seismic data and information (but not reinterpreting old data);
    (2) Did not exist at the time of the earlier application; and
    (3) Changes your estimates of gross resource size, quality, or 
projected flow rates enough to materially affect the results of our 
earlier determination.
    (b) You demonstrate in your new application that the technology that 
most efficiently develops this field or lease was not considered or 
deemed feasible in the original application. Your newly proposed 
technology must improve the profitability, under equivalent market 
conditions, of the field or lease relative to the development system 
proposed in the prior application.
    (c) Your current reference price decreases by more than 25 percent 
from your base reference price as calculated under this paragraph.
    (1) Your current reference price is a weighted-average of daily 
closing prices on the NYMEX for light sweet crude oil and natural gas 
over the most recent full 12 calendar months;
    (2) Your base reference price is a weighted average of daily closing 
prices on the NYMEX for light sweet crude oil and natural gas for the 
full 12 calendar months preceding the date of your most recently 
approved application for this royalty relief; and
    (3) The weighting factors are the proportions of the total 
production volume (in BOE) for oil and gas associated with the most 
likely scenario (identified in Sec. Sec. 203.85 and 203.88) from your 
most recently approved application for this royalty relief.
    (d) Before starting to build your development and production system, 
you have revised your estimated development costs, and they are more 
than 120 percent of the eligible development costs associated with the 
most likely scenario from your most recently approved application for 
this royalty relief.

[63 FR 2618, Jan. 16, 1998; 63 FR 24747, May 5, 1998, as amended at 67 
FR 1878, Jan. 15, 2002]



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

[[Page 36]]

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, or from an independent development and production system to one 
with subsea wells tied back to a host production facility, etc.).
    (b) You do not start building the proposed development and 
production system within18 months of the date we approved your 
application, unless the MMS Director grants you an extension under Sec. 
203.79(c). If you start building the proposed system and then suspend 
its construction before completion, and you do not restart continuous 
building of the proposed system within 18 months of our approval, we 
will withdraw the relief we granted.
    (c) Your actual development costs are less than 80 percent of the 
eligible development costs estimated in your application's most likely 
scenario, and you do not report that fact in your post-production 
development report (Sec. 203.70). Development costs are those 
expenditures defined in Sec. 203.89(b) incurred between the application 
submission date and start of production. If you report this fact in the 
post-production development report, you may retain the lesser of 50 
percent of the original royalty suspension volume or 50 percent of the 
median of the distribution of the potentially recoverable resources 
anticipated in your application.
    (d) We granted you a royalty-suspension volume after you qualified 
for a redetermination under 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.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1878, Jan. 15, 2002]



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

    Yes, by sending a letter to that effect to the MMS Regional Director 
for the GOM.

[67 FR 1878, Jan. 15, 2002]



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

    If prices rise above a base price for light sweet crude oil or 
natural gas, set by statute for pre-Act leases, indicated in your 
original lease agreement or Notice of Sale for post-November 2000 deep 
water leases, you must pay full royalties as prescribed in this section. 
For post-November 2000 deepwater leases, price thresholds apply on a 
lease basis, so different leases on the same field, development project, 
or expansion project may have different price thresholds.
    (a) Suppose the arithmetic average of the daily closing NYMEX light 
sweet crude oil prices for the previous calendar year exceeds $28.00 per 
barrel, as adjusted in paragraph (f) of this section. In this case, we 
retract the royalty relief authorized in this section and you must:

[[Page 37]]

    (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 March 31 of the current calendar year, 
and
    (2) Pay royalties on all your oil production in the current year.
    (b) Suppose the arithmetic average of the daily closing NYMEX 
natural gas prices for the previous calendar year exceeds $3.50 per 
million British thermal units (Btu), as adjusted in paragraph (f) of 
this section. In this case, we retract the royalty relief authorized in 
this section and you must:
    (1) Pay royalties on all natural gas production for the previous 
year at the lease stipulated royalty rate plus interest (under 30 U.S.C. 
1721 and Sec. 218.54 of this chapter) by March 31 of the current 
calendar year, and
    (2) Pay royalties on all your natural gas production in the current 
year.
    (c) Production under both paragraphs (a) and (b) of this section 
counts as part of the royalty-suspension volume.
    (d) You are entitled to a refund or credit, with interest, of 
royalties paid on any production (that counts as part of the royalty-
suspension volume):
    (1) Of oil if the arithmetic average of the closing oil prices for 
the current calendar year is $28.00 per barrel or less, as adjusted in 
paragraph (f) of this section, and
    (2) Of gas if the arithmetic average of the closing natural gas 
prices for the current calendar year is $3.50 per million Btu or less, 
as adjusted in paragraph (f) of this section.
    (e) You must follow our regulations in part 230 of this chapter for 
receiving refunds or credits.
    (f) We change the prices referred to in paragraphs (a), (b), and (d) 
of this section periodically. For pre-Act leases, these prices change 
during each calendar year after 1994 by the percentage that the implicit 
price deflator for the gross domestic product changed during the 
preceding calendar year. For post-November 2000 deepwater leases, these 
prices change as indicated in the lease instrument or in the Notice of 
Sale under which we issued the lease.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1878, Jan. 15, 2002]



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.



Sec. 203.80  When can I get royalty relief if I am not eligible for end-of-

life or deep water royalty relief?

    We may grant royalty relief when it serves the statutory purposes 
summarized in Sec. 203.1, and our formal relief programs provide 
inadequate encouragement to increase production or development. Unless 
your lease lies wholly west of 87 degrees, 30 minutes West longitude in 
the Gulf of Mexico, your lease must be producing to qualify for relief. 
Before you may apply for royalty relief apart from our end-of-life or 
deepwater programs, we must agree that your lease or project has two or 
more of the following characteristics:
    (a) The lease has produced for a substantial period and the lessee 
can recover significant additional resources. Significant additional 
resources means enough to allow production for at least

[[Page 38]]

a year more than would be profitable without royalty relief.
    (b) Valuable facilities (e.g., a platform or pipeline that would be 
removed upon lease relinquishment) exist that we do not expect a 
successor lessee to use. If the facilities are located off the lease, 
their preservation must depend on continued production from the lease 
applying for royalty relief. We will only consider an allocable share of 
costs for off-lease facilities in the relief application.
    (c) A substantial risk exists that no new lessee will recover the 
resources.
    (d) The lessee made major efforts to reduce operating costs too 
recently to use the formal program for royalty relief (e.g., recent 
significant change in operations).
    (e) Circumstances beyond the lessee's control, other than water 
depth, preclude reliance on one of the existing royalty relief programs.

[67 FR 1879, Jan. 15, 2002]

                            Required Reports



Sec. 203.81  What supplemental reports do royalty-relief applications 

require?

    (a) You must send us the supplemental reports, indicated in the 
following table by an X, that apply to your field. Sections 203.83 
through 203.91 describe these reports in detail.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                             End-of-  ------------------------------------------
                     Required reports                          life       Expansion     Pre-act     Development
                                                              lease        project       lease        project
----------------------------------------------------------------------------------------------------------------
(1) Administrative information Report.....................         X               X          X               X
(2) Net revenue & relief justification report.............         X
(3) Economic viability & relief justification report (RSVP  .........              X          X               X
 model imputs justified by other required reports)........
(4) G&G report............................................  .........              X          X               X
(5) Engineering report....................................  .........              X          X               X
(6) Production report.....................................  .........              X          X               X
(7) Deep water cost report................................  .........              X          X               X
(8) Fabricator's confirmation report......................  .........              X          X               X
(9) Post-production development report....................  .........              X          X               X
----------------------------------------------------------------------------------------------------------------

    (b) You must certify that all information in your application, 
fabricator's confirmation and post-production development reports is 
accurate, complete, and conforms to the most recent content and 
presentation guidelines available from the MMS GOM Regional Office.
    (c) With your application and post-production development report, 
you must submit an additional report prepared by an independent CPA 
that:
    (1) Assesses the accuracy of the historical financial information in 
your report; and
    (2) Certifies that the content and presentation of the financial 
data and information conform to our most recent guidelines on royalty 
relief. This means the data and information must--
    (i) Include only eligible costs that are incurred during the 
qualification months; and
    (ii) Be shown in the proper format.
    (d) You must identify the people in the CPA firm who prepared the 
reports referred to in paragraph (c) of this section and make them 
available to us to respond to questions about the historical financial 
information. We may also further review your records to support this 
information.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002]



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

[[Page 39]]

characteristics, production, and engineering estimates for us to 
determine whether:
    (i) We should grant relief under the law, and
    (ii) The requested relief will ultimately recover more resources and 
return a reasonable profit on project investments.
    (2) Your fabricator confirmation and post-production development 
reports must contain enough information for us to verify that your 
application reasonably represented your plans.
    (b) Applicants (respondents) are Federal OCS oil and gas lessees. 
Applications are required to obtain or retain a benefit. Therefore, if 
you apply for royalty relief, you must provide this information. We will 
protect information considered proprietary under applicable law and 
under regulations at 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) Well number, API number, location, and status of each well that 
has been drilled on the field or lease or project (not required for non-
oil and gas leases);
    (d) The location of any new wells proposed under the terms of the 
application (not required for non-oil and gas leases);
    (e) A description of field or lease history;
    (f) Full information as to whether you will pay royalties or a share 
of production to anyone other than the United States, the amount you 
will pay, and how much you will reduce this payment if we grant relief;
    (g) The type of royalty relief you are requesting;
    (h) Confirmation that we approved a DOCD or supplemental DOCD (Deep 
Water expansion project applications only); and
    (i) A narrative description of the development activities associated 
with the proposed capital investments and an explanation of proposed 
timing of the activities and the effect on production (Deep Water 
applications only).

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002]



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;

[[Page 40]]

    (4) Any costs associated with exploratory activities;
    (5) Civil or criminal fines or penalties;
    (6) Fees for your royalty relief application; and
    (7) Costs associated with existing obligations (e.g., royalty 
overrides or other forms of payment for acquiring the lease, 
depreciation on previously acquired equipment or facilities).
    (c) We may, in reviewing and evaluating your application, disallow 
costs when you have not shown they are necessary to operate the lease, 
or if they are inconsistent with end-of-life operations.

[63 FR 2618, Jan. 16, 1998, as amended at 63 FR 57249, Oct. 27, 1998]



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 
(Sec. Sec. 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,

[[Page 41]]

    (iii) The 5-inch electric log shows pay zones and pay counts and 
labeled points used in establishing resistivity of the formation, 100 
percent water saturated (Ro) and the resistivity of the 
undisturbed formation (Rt), and
    (iv) The 5-inch porosity logs show pay zones and pay counts and 
labeled points used in establishing reservoir porosity or labeled points 
showing values used in calculating reservoir porosity such as bulk 
density or transit time;
    (2) Digital copies of all well logs spudded before December 1, 1995;
    (3) Core data, if available;
    (4) Well correlation sections;
    (5) Pressure data;
    (6) Production test results;
    (7) Pressure-volume-temperature analysis, if available; and
    (8) A table listing the wells and completions, and indicating which 
sands and fault blocks will be targeted for completion or recompletion.
    (c) Map interpretations which includes for each reservoir in the 
field:
    (1) Structure maps consisting of top and base of sand maps showing 
well and seismic shot point locations;
    (2) Isopach maps for net sand, net oil, net gas, all with well 
locations;
    (3) Maps indicating well surface and bottom hole locations, location 
of development facilities, and shot points; and
    (4) An explanation for excluding the reservoirs you are not planning 
to develop.
    (d) Reservoir-specific data which includes:
    (1) Probability of reservoir occurrence with hydrocarbons;
    (2) Probability the hydrocarbon in the reservoir is all oil and the 
probability it is all gas;
    (3) Distributions or point estimates (accompanied by explanations of 
why distributions less appropriately reflect the uncertainty) for the 
parameters used to estimate reservoir size, i.e., acres and net 
thickness;
    (4) Most likely values for porosity, salt water saturation, volume 
factor for oil formation, and volume factor for gas formation;
    (5) Distributions or point estimates (accompanied by explanations of 
why distributions less appropriately reflect the uncertainty) for 
recovery efficiency (in percent) and oil or gas recovery (in stock-tank-
barrels per acre-foot or in thousands of cubic feet per acre foot);
    (6) A gas/oil ratio distribution or point estimate (accompanied by 
explanations of why distributions less appropriately reflect the 
uncertainty) for each reservoir;
    (7) A yield distribution or point estimate (accompanied by 
explanations of why distributions less appropriately reflect the 
uncertainty) for each gas reservoir; and
    (8) Reserve or resource distribution by reservoir.
    (e) Aggregated reserve and resource data which includes:
    (1) The aggregated distributions for reserves and resources (in BOE) 
and oil fraction for your field computed by the resource module of our 
RSVP model;
    (2) A description of anticipated hydrocarbon quality (i.e., specific 
gravity); and
    (3) The ranges within the aggregated distribution for reserves and 
resources that define the development and production scenarios presented 
in the engineering and production reports. Typically there will be three 
ranges specified by two positive reserve and resource points on the 
aggregated distribution. The range at the low end of the distribution 
will be associated with the conservative development and production 
scenario; the middle range will be related to the most likely 
development and production scenario; and, the high end range will be 
consistent with the optimistic development and production scenario.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002]



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 along with basic design specifications and drawings; 
and
    (2) The construction schedule.

[[Page 42]]

    (b) An identification of planned wells which includes:
    (1) The number;
    (2) The type (platform, subsea, vertical, deviated, horizontal);
    (3) The well depth;
    (4) The drilling schedule;
    (5) The kind of completion (single, dual, horizontal, etc.); and
    (6) The completion schedule.
    (c) A description of the production system equipment which includes:
    (1) The production capacity for oil and gas and a description of 
limiting component(s);
    (2) Any unusual problems (low gravity, paraffin, etc.);
    (3) All subsea structures;
    (4) All flowlines; and
    (5) Schedule for installing the production system.
    (d) A discussion of any plans for multi-phase development which 
includes the conceptual basis for developing in phases and goals or 
milestones required for starting later phases.
    (e) A set of development scenarios consisting of activity timing and 
scale associated with each of up to three production profiles 
(conservative, most likely, optimistic) provided in the production 
report for your field (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.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]



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 costs. Report sunk costs in dollars not adjusted for 
inflation and only if you have documentation.
    (b) Appraisal, delineation and development costs. Base them on 
actual spending, current authorization for expenditure, engineering 
estimates, or analogous projects. These costs cover:
    (1) Platform well drilling and average depth;
    (2) Platform well completion;
    (3) Subsea well drilling and average depth;
    (4) Subsea well completion;
    (5) Production system (platform); and
    (6) Flowline fabrication and installation.
    (c) Production costs based on historical costs, engineering 
estimates, or analogous projects. These costs cover:
    (1) Operation;
    (2) Equipment; and
    (3) Existing royalty overrides (we will not use the royalty 
overrides in evaluations).
    (d) Transportation costs, based on historical costs, engineering 
estimates, or analogous projects. These costs cover:
    (1) Oil or gas tariffs from pipeline or tankerage;
    (2) Trunkline and tieback lines; and
    (3) Gas plant processing for natural gas liquids.
    (e) Abandonment costs, based on historical costs, engineering 
estimates, or analogous projects. You should provide the costs to plug 
and abandon only wells and to remove only production systems for which 
you have not incurred costs as of the time of application submission. 
You should also include a point estimate or distribution of prospective 
salvage value for all potentially reusable facilities and materials, 
along with the source and an explanation of the figures provided.

[[Page 43]]

    (f) A set of cost estimates consistent with each one of up to three 
field-development scenarios and production profiles (conservative, most 
likely, optimistic). You should express costs in constant real dollar 
terms for the base year. You may also express the uncertainty of each 
cost estimate with a minimum and maximum percentage of the base value.
    (g) A spending schedule. You should provide costs for each year (in 
real dollars) for each category in paragraphs (a) through (f) of this 
section.
    (h) A summary of other costs which are ineligible for evaluating 
your need for relief. These costs cover:
    (1) Expenses before first discovery on the field;
    (2) Cash bonuses;
    (3) Fees for royalty relief applications;
    (4) Lease rentals, royalties, and payments of net profit share and 
net revenue share;
    (5) Legal expenses;
    (6) Damages and losses;
    (7) Taxes;
    (8) Interest or finance charges, including those embedded in 
equipment leases;
    (9) Fines or penalties; and
    (10) Money spent on previously existing obligations (e.g., royalty 
overrides or other forms of payment for acquiring a financial position 
in a lease, expenditures for plugging wells and removing and abandoning 
facilities that existed on the application submission date).

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]



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. Also, you must have this 
report certified by an independent CPA according to Sec. 203.81(c).

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]

Subpart C--Federal and Indian Oil [Reserved]

Subpart D--Federal and Indian Gas [Reserved]

Subpart E--Solid Minerals, General [Reserved]



                             Subpart F_Coal



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]

[[Page 44]]



PART 204_ALTERNATIVES FOR MARGINAL PROPERTIES--Table of Contents




                      Subpart A_General Provisions

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

Subpart B--Prepayment of Royalty [Reserved]

                Subpart C_Accounting and Auditing Relief

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

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

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



                      Subpart A_General Provisions



Sec. 204.1  What is the purpose of this part?

    This part explains how you as a lessee or designee of a Federal 
onshore or Outer Continental Shelf (OCS) oil and gas lease may obtain 
prepayment or accounting and auditing relief for production from certain 
marginal properties. This part does not apply to production from Indian 
leases, even if the Indian lease is within an agreement that qualifies 
as a marginal property.



Sec. 204.2  What definitions apply to this part?

    Agreement means a federally approved communitization agreement or 
unit participating area.
    Barrels of oil equivalent (BOE) means the combined equivalent 
production of oil and gas stated in barrels of oil. Each barrel of oil 
production is equal to one BOE. Also, each 6,000 cubic feet of gas 
production is equal to one BOE.
    Base period means the 12-month period from July 1 through June 30 
immediately preceding the calendar year for which you take or request 
marginal property relief. For example, if you request relief for 
calendar year 2006, your base period is July 1, 2004, through June 30, 
2005.
    Combined equivalent production means the total of all oil and gas 
production for the marginal property, stated in BOE.
    Designee means the person designated by a lessee under 30 CFR 218.52 
to make all or part of the royalty or other payments due on a lease on 
the lessee's behalf.
    Producing wells means only those producing oil or gas wells that 
contribute to the sum of BOE used in the calculation under Sec. 
204.4(c). Producing wells do not include injection or water wells. Wells 
with multiple zones commingled downhole are considered as a single well.
    Property means a lease, a portion of a lease, or an agreement that 
may be a marginal property if it meets the qualification requirements of 
Sec. 204.4.
    State concerned (State) means the State that receives a statutorily 
prescribed portion of the royalties from a Federal onshore or OCS lease.

[[Page 45]]



Sec. 204.3  What alternatives are available for marginal properties?

    If you have production from a marginal property, MMS and the State 
may allow you the following options:
    (a) Prepay royalty. MMS and the State may allow you to make a lump-
sum advance payment of royalties instead of monthly royalty payments for 
the remainder of the lease term. See Subpart B for prepayment of royalty 
requirements.
    (b) Take accounting and auditing relief. MMS and the State may allow 
various accounting and auditing relief options to encourage you to 
continue to produce and develop your marginal property. See Subpart C 
for accounting and auditing relief requirements.



Sec. 204.4  What is a marginal property under this part?

    (a) To qualify as a marginal property eligible for royalty 
prepayment or accounting and auditing relief under this part, the 
property must meet the following requirements:

------------------------------------------------------------------------
     If your lease is . . .           Then . . .           And . . .
------------------------------------------------------------------------
(1) Not in an agreement.........  The lease must      ..................
                                   qualify as a
                                   marginal property
                                   under paragraph
                                   (b) of this
                                   section.
(2) Entirely or partly committed  The entire          Agreement
 to one agreement.                 agreement must      production
                                   qualify as a        allocable to your
                                   marginal property   lease may be
                                   under paragraph     eligible for
                                   (b) of this         relief under this
                                   section.            part. Any
                                                       production from
                                                       your lease that
                                                       is not committed
                                                       to the agreement
                                                       also may be
                                                       eligible for
                                                       separate relief
                                                       under paragraph
                                                       (a)(4) of this
                                                       table.
(3) Entirely or partly committed  Each agreement      For any agreement
 to more than one agreement.       must qualify        that does
                                   separately as a     qualify, that
                                   marginal property   agreement's
                                   under paragraph     production
                                   (b) of this         allocable to your
                                   section.            lease may be
                                                       eligible for
                                                       relief under this
                                                       part. Any
                                                       production from
                                                       your lease that
                                                       is not committed
                                                       to an agreement
                                                       also may be
                                                       eligible for
                                                       separate relief
                                                       under paragraph
                                                       (a)(4) of this
                                                       table.
(4) Partly committed to an        The part of the
 agreement and you have            lease that is not
 production from the part of the   committed to the
 lease that is not committed to    agreement must
 the agreement.                    qualify
                                   separately as a
                                   marginal property
                                   under paragraph
                                   (b) of this
                                   section.
------------------------------------------------------------------------

    (b) To qualify as a marginal property for a calendar year, the 
combined equivalent production of the property during the base period 
must equal an average daily well production of less than 15 barrels of 
oil equivalent (BOE) per well per day calculated under paragraph (c) of 
this section.
    (c) To determine the average daily well production for a property, 
divide the sum of the BOE for all producing wells on the property during 
the base period by the sum of the number of days that each of those 
wells actually produced during the base period. If the property is an 
agreement, your calculation under this paragraph must include all wells 
included in the agreement, even if they are not on a Federal onshore or 
OCS lease.



Sec. 204.5  What statutory requirements must I meet to obtain royalty 

prepayment or accounting and auditing relief?

    (a) MMS and the State may allow royalty prepayment or accounting and 
auditing relief for your marginal property production if MMS and the 
State jointly determine that the prepayment or accounting and auditing 
relief is in the best interests of the Federal Government and the State 
to:
    (1) Promote production;
    (2) Reduce the administrative costs of MMS and the State; and
    (3) Increase net receipts to the Federal Government and the State.
    (b) At any time, if MMS and the State determine that either 
prepayment or accounting and auditing relief no longer meets the 
criteria in paragraph (a) of this section, MMS, with

[[Page 46]]

the State's concurrence, may discontinue any prepayment or accounting 
and auditing relief options granted for production from any marginal 
property.
    (1) MMS will provide you written notice of the decision to 
discontinue relief.
    (i) If you took the cumulative reports and payments relief option 
under Sec. 204.202, your relief will terminate at the end of the 
calendar year in which you received the notice.
    (ii) If you were approved for prepayment relief under subpart B of 
this part or other relief under Sec. 204.203, MMS's notice will tell 
you when your relief terminates.
    (2) MMS's decision to discontinue relief is not subject to 
administrative appeal.



Sec. 204.6  May I appeal if MMS denies my request for prepayment or other 

relief?

    If MMS denies your request for prepayment relief under Subpart B of 
this part or other relief under Sec. 204.203, you may appeal under 30 
CFR part 290.

Subpart B--Prepayment of Royalty [Reserved]



                Subpart C_Accounting and Auditing Relief



Sec. 204.200  What is the purpose of this subpart?

    This subpart explains how you as a lessee or designee may obtain 
accounting and auditing relief for your Federal onshore or OCS lease 
production from a marginal property. The two types of accounting and 
auditing relief that you can receive under this subpart are cumulative 
reports and payment relief (explained in Sec. 204.202) and other 
accounting and auditing relief appropriate for your property (explained 
in Sec. 204.203).



Sec. 204.201  Who may obtain accounting and auditing relief?

    (a) You may obtain accounting and auditing relief under this 
subpart:
    (1) If you are a lessee or a designee for a Federal lease with 
production from a property that qualifies as a marginal property under 
Sec. 204.4;
    (2) If you meet any additional requirements for specific types of 
relief under this subpart; and
    (3) Only for the fractional interest in production from the marginal 
property for which you report and pay royalty. You may obtain relief 
even if the other lessees or designees for your lease or agreement do 
not request relief.
    (b) You may not obtain one or both of the relief options specified 
in this subpart on any portion of production from a marginal property 
if:
    (1) The marginal property covers multiple States; and
    (2) One of the States determines under Sec. 204.208 that it will 
not allow the relief option you seek.



Sec. 204.202  What is the cumulative royalty reports and payments relief 

option?

    (a) The cumulative royalty reports and payments relief option allows 
you to submit one royalty report and payment annually for production 
during a calendar year. You are eligible for this option only if the 
total volume produced from the marginal property (not just your share of 
the production) is 1,000 BOE or less during the base period.
    (b) To use the cumulative royalty reports and payments relief 
option, you must do all of the following:
    (1) Notify MMS in writing by January 31 of the calendar year for 
which you begin taking your relief. See Sec. 204.205(a) for what your 
notification must contain;
    (2) Submit your royalty report and payment in accordance with 30 CFR 
218.51(g) by the end of February of the year following the calendar year 
for which you reported annually, unless you have an estimated payment on 
file. If you have an estimated payment on file, you must submit your 
royalty report and payment by the end of March of the year following the 
calendar year for which you reported annually;
    (3) Use the sales month prior to the month that you submit your 
annual report and payment under paragraph (b)(2) of this section on your 
Report of Sales and Royalty Remittance, Form MMS-2014, for the entire 
previous calendar year's production for which you are paying annually. 
(For example, for

[[Page 47]]

a report in February use January as your sales month, and for a report 
in March use February as your sales month, to report production for the 
entire previous calendar year for which you are paying annually);
    (4) Report one line of cumulative royalty information on Form MMS-
2014 for the calendar year, the same as if it were a monthly report; and
    (5) Report allowances on Form MMS-2014 on the same annual basis as 
the royalties for your marginal property production.
    (c) If you do not pay your royalty by the date due in paragraph (b) 
of this section, you will owe late payment interest determined under 30 
CFR 218.54 from the date your payment was due under this section until 
the date MMS receives it.
    (d) If you take relief you are not qualified for, you may be liable 
for civil penalties. Also you must:
    (1) Pay MMS late payment interest determined under 30 CFR 218.54 
from the date your payment was due until the date MMS receives it; and
    (2) Amend your Form MMS-2014 to reflect the required monthly 
reporting.
    (e) If you dispose of your ownership interest in a marginal property 
for which you have taken relief under this section (or if you are a 
designee who reports and pays royalty for a lessee who has disposed of 
its ownership interest), you must:
    (1) Report and pay royalties for the portion of the calendar year 
for which you had an ownership interest; and
    (2) Make the report and payment by the end of the month after you 
dispose of the ownership interest in the marginal property. If you do 
not report and pay timely, you will owe interest determined under 30 CFR 
218.54 from the date the payment was due under this section.



Sec. 204.203  What is the other relief option?

    (a) Under this relief option, you may request any type of accounting 
and auditing relief that is appropriate for production from your 
marginal property, provided it is not prohibited under Sec. 204.204 and 
meets the statutory requirements of Sec. 204.5. Examples of relief 
options you could request are:
    (1) To report and pay royalties using a valuation method other than 
that required under 30 CFR part 206 that approximates royalties payable 
under that part 206; and
    (2) To reduce your royalty audit burden. However, MMS will not 
consider any request that eliminates MMS's or the States' right to 
audit.
    (b) You must request approval from MMS under Sec. 204.205(b), and 
receive approval under Sec. 204.206 before taking relief under this 
option.



Sec. 204.204  What accounting and auditing relief will MMS not allow?

    MMS will not approve your request for accounting and auditing relief 
under this subpart if your request:
    (a) Prohibits MMS or the State from conducting any form of audit;
    (b) Permanently relieves you from making future royalty reports or 
payments;
    (c) Provides for less frequent royalty reports and payments than 
annually;
    (d) Provides for you to submit royalty reports and payments at 
separate times;
    (e) Impairs MMS's ability to properly or efficiently account for or 
distribute royalties;
    (f) Requests relief for a lease under which the Federal Government 
takes its royalties in kind;
    (g) Alters production reporting requirements;
    (h) Alters lease operation or safety requirements;
    (i) Conflicts with rent, minimum royalty, or lease requirements; or
    (j) Requests relief for production from a marginal property located 
in whole or in part in a State that has determined that it will not 
allow such relief under Sec. 204.208.



Sec. 204.205  How do I obtain accounting and auditing relief?

    (a) To take cumulative reports and payments relief under Sec. 
204.202, you must notify MMS in writing by January 31 of the calendar 
year for which you begin taking your relief.
    (1) Your notification must contain:
    (i) Your company name, MMS-assigned payor code, address, phone 
number, and contact name; and

[[Page 48]]

    (ii) The specific MMS lease number and agreement number, if 
applicable.
    (2) You may file a single notification for multiple marginal 
properties.
    (b) To obtain other relief under Sec. 204.203, you must file a 
written request for relief with MMS.
    (1) Your request must contain:
    (i) Your company name, MMS-assigned payor code, address, phone 
number, and contact name;
    (ii) The MMS lease number and agreement number, if applicable; and
    (iii) A complete and detailed description of the specific accounting 
or auditing relief you seek.
    (2) You may file a single request for multiple marginal properties 
if you are requesting the same relief for all properties.



Sec. 204.206  What will MMS do when it receives my request for other relief?

    When MMS receives your request for other relief under Sec. 
204.205(b), it will notify you in writing as follows:
    (a) If your request for relief is complete, MMS may either approve, 
deny, or modify your request in writing after consultation with any 
State required under Sec. 204.207(b).
    (1) If MMS approves your request for relief, MMS will notify you of 
the effective date of your accounting or auditing relief and other 
specifics of the relief approved.
    (2) If MMS denies your relief request, MMS will notify you of the 
reasons for denial and your appeal rights under Sec. 204.6.
    (3) If MMS modifies your relief request, MMS will notify you of the 
modifications.
    (i) You have 60 days from your receipt of MMS's notice to either 
accept or reject any modification(s) in writing.
    (ii) If you reject the modification(s) or fail to respond to MMS's 
notice, MMS will deny your relief request. MMS will notify you in 
writing of the reasons for denial and your appeal rights under Sec. 
204.6.
    (b) If your request for relief is not complete, MMS will notify you 
in writing that your request is incomplete and identify any missing 
information.
    (1) You must submit the missing information within 60 days of your 
receipt of MMS's notice that your request is incomplete.
    (2) After you submit all required information, MMS may approve, 
deny, or modify your request for relief under paragraph (a) of this 
section.
    (3) If you do not submit all required information within 60 days of 
your receipt of MMS's notice that your request is incomplete, MMS will 
deny your relief request. MMS will notify you in writing of the reasons 
for denial and your appeal rights under Sec. 204.6.
    (4) You may submit a new request for relief under this subpart at 
any time after MMS returns your incomplete request.



Sec. 204.207  Who will approve, deny, or modify my request for accounting and 

auditing relief?

    (a) If there is not a State concerned for your marginal property, 
only MMS will decide whether to approve, deny, or modify your relief 
request.
    (b) If there is a State concerned for your marginal property that 
has determined in advance under Sec. 204.208 that it will allow either 
or both of the relief options under this subpart, MMS will decide 
whether to approve, deny, or modify your relief request after consulting 
with the State concerned.



Sec. 204.208  May a State decide that it will or will not allow one or both 

of the relief options under this subpart?

    (a) A State may decide in advance that it will or will not allow one 
or both of the relief options specified in this subpart for a particular 
calendar year. If a State decides that it will not consent to one or 
both of the relief options, MMS will not grant that type of marginal 
property relief.
    (b) To help States decide whether to allow one or both of the relief 
options specified in this subpart, for each calendar year MMS will send 
States a Report of Marginal Properties by October 1 preceding the 
calendar year.
    (c) If a State decides under paragraph (a) of this section that it 
will or will not allow one or both of the relief options in this subpart 
during the next calendar year, within 30 days of the State's receipt of 
the Report of Marginal Properties under paragraph (b) of this section, 
the State must:

[[Page 49]]

    (1) Notify the Associate Director for Minerals Revenue Management, 
MMS, in writing, of its intent to allow or not allow one or both of the 
relief options under this subpart; and
    (2) Specify in its notice of intent to MMS which relief option(s) it 
will allow or not allow.
    (d) If a State decides in advance under paragraph (a) of this 
section that it will not allow one or both of the relief options 
specified in this subpart, it may decide for subsequent calendar years 
that it will allow one or both of the relief options in this subpart. If 
it so decides, within 30 days of the State's receipt of the Report of 
Marginal Properties under paragraph (b) of this section, the State must:
    (1) Notify the Associate Director for Minerals Revenue Management, 
MMS, in writing, of its intent to allow one or both of the relief 
options allowed under this subpart during the next calendar year; and
    (2) Specify in its notice of intent to MMS which relief option(s) it 
will allow.
    (e) If a State does not notify MMS under paragraph (c) or (d) of 
this section, the State will be deemed to have decided not to allow 
either of the relief options under this subpart for the next calendar 
year.
    (f) MMS will publish a notice of the State s intent to allow or not 
allow certain relief options under this section in the Federal Register 
no later than 30 days before the beginning of the applicable calendar 
year.



Sec. 204.209  What if a property ceases to qualify for relief obtained under 

this subpart?

    (a) A marginal property must qualify for relief under this subpart 
for each calendar year based on production during the base period for 
that calendar year. The notice or request you provided to MMS under 
Sec. 204.205 for the first calendar year that the property qualified 
for relief remains effective for successive calendar years if the 
property continues to qualify.
    (b) If a property is no longer eligible for relief for any reason 
during a calendar year other than the reason under Sec. 204.210 or 
paragraph (c) of this section, the relief for the property terminates as 
of December 31 of that calendar year. You must notify MMS in writing by 
December 31 that the relief for the property has terminated.
    (c) If you dispose of your interest in a marginal property during 
the calendar year, your relief terminates as of the end of the sales 
month in which you disposed of the property. Report and pay royalties 
for your production using the procedures in Sec. 204.202(e).



Sec. 204.210  What if a property is approved as part of a nonqualifying 

agreement?

    If the Bureau of Land Management (BLM) or MMS's Offshore Minerals 
Management (OMM) retroactively approves a marginal property that 
qualified for relief for inclusion as part of an agreement that does not 
qualify for relief under this subpart, the property no longer qualifies 
for relief under this subpart then:
    (a) MMS will not retroactively rescind the marginal property relief 
for production from your property under Sec. 204.211;
    (b) Your marginal property relief terminates as of December 31 of 
the calendar year that you receive the BLM or OMM approval of your 
marginal property as part of a nonqualifying agreement; and
    (c) For the calendar year in which you receive the BLM or OMM 
approval, and for any previous period affected by the approval, the 
volumes on which you report and pay royalty for your lease must be 
amended to reflect all volumes produced on or allocated to your lease 
under the nonqualifying agreement as modified by BLM or OMM. Report and 
pay royalties for your production using the procedures in Sec. 
204.202(b).
    (d) If you owe additional royalties based on the retroactive 
agreement approval and do not pay your royalty by the date due in Sec. 
204.202(b), you will owe late payment interest determined under 30 CFR 
218.54 from the date your payment was due under Sec. 204.202 (b)(2) 
until the date MMS receives it.

[[Page 50]]



Sec. 204.211  When may MMS rescind relief for a property?

    (a) MMS may retroactively rescind the relief for your property if 
MMS determines that your property was not eligible for the relief 
obtained under this subpart because:
    (1) You did not submit a notice or request for relief under Sec. 
204.205;
    (2) You submitted erroneous information in the notice or request for 
relief you provided to MMS under Sec. 204.205 or in your royalty or 
production reports; or
    (3) Your property is no longer eligible for relief because 
production increased, but you failed to provide the notice required 
under Sec. 204.209(b).
    (b) MMS may rescind relief for your property if MMS decides to take 
royalty in kind.



Sec. 204.212  What if I took relief for which I was ineligible?

    If you took relief under this subpart for a period for which you 
were not eligible, you:
    (a) May owe additional royalties and late payment interest 
determined under 30 CFR 218.54 from the date your additional payments 
were due until the date MMS receives them; and
    (b) May be subject to civil penalties.



Sec. 204.213  May I obtain relief for a property that benefits from other 

Federal or State incentive programs?

    You may obtain accounting and auditing relief for production from a 
marginal property under this subpart even if the property benefits from 
other Federal or State production incentive programs.



Sec. 204.214  Is minimum royalty due on a property for which I took relief?

    (a) If you took cumulative royalty reports and payment relief on a 
property under this subpart, minimum royalty is still due for that 
property by the date prescribed in your lease and in the amount 
prescribed therein.
    (b) If you pay minimum royalty on production from a marginal 
property during a calendar year for which you are taking cumulative 
royalty reports and payment relief, and:
    (1) The annual payment you owe under this subpart is greater than 
the minimum royalty you paid, you must pay the difference between the 
minimum royalty you paid and your annual payment due under this subpart; 
or
    (2) The annual payment you owe under this subpart is less than the 
minimum royalty you paid, you are not entitled to a credit because you 
must pay at least the minimum royalty amount on your lease each year.



Sec. 204.215  Are the information collection requirements in this subpart 

approved by the Office of Management and Budget (OMB)?

    OMB has approved the information collection requirements contained 
in this subpart under 44 U.S.C. 3501 et seq., and assigned OMB control 
number 1010-0155. See 30 CFR part 210 for details concerning your 
estimated reporting burden and how you may comment on the accuracy of 
the burden estimate.



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.
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 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?

[[Page 51]]

206.108 Does MMS protect information I provide?
206.109 When may I take a transportation allowance in determining value?
206.110 How do I determine a transportation allowance under an arm's-
          length transportation contract?
206.111 How do I determine a transportation allowance if I do not have 
          an arm's-length transportation contract or arm's-length 
          tariff?
206.112 What adjustments and transportation allowances apply when I 
          value oil production from my lease using NYMEX prices or ANS 
          spot prices?
206.113 How will MMS identify market centers?
206.114 What are my reporting requirements under an arm's-length 
          transportation contract?
206.115 What are my reporting requirements under a non-arm's-length 
          transportation arrangement?
206.116 What interest and assessments apply if I improperly report a 
          transportation allowance?
206.117 What reporting adjustments must I make for transportation 
          allowances?
206.119 How are the royalty quantity and quality determined?
206.120 How are operating allowances determined?

                          Subpart D_Federal Gas

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

                          Subpart E_Indian Gas

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

                        Transportation Allowances

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

                          Processing Allowances

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

                         Subpart F_Federal Coal

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

                     Subpart G_Other Solid Minerals

206.301 Value basis for royalty computation.

                     Subpart H_Geothermal Resources

206.350 What is the purpose of this subpart?
206.351 What definitions apply to this subpart?
206.352 How do I calculate the royalty due on geothermal resources used 
          for commercial production or generation of electricity?
206.353 How do I determine transmission deductions?
206.354 How do I determine generating deductions?
206.355 How do I calculate royalty due on geothermal resources I sell at 
          arm's length to a purchaser for direct use?
206.356 How do I calculate royalty due on geothermal resources I use for 
          direct use purposes?

[[Page 52]]

206.357 How do I calculate royalty due on byproducts?
206.358 What are byproduct transportation allowances?
206.359 How do I determine byproduct transportation allowances?
206.360 What records must I keep to support my calculations of royalty 
          or fees under this subpart?
206.361 How will MMS determine whether my royalty or direct use fee 
          payments are correct?
206.362 What are my responsibilities to place production into marketable 
          condition and to market production?
206.363 When is an MMS audit, review, reconciliation, monitoring, or 
          other like process considered final?
206.364 How do I request a value or gross proceeds determination?
206.365 Does MMS protect information I provide?
206.366 What is the nominal fee that a State, tribal, or local 
          government lessee must pay for the use of geothermal 
          resources?

Subpart I--OCS Sulfur [Reserved]

                          Subpart J_Indian Coal

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

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

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



                      Subpart A_General Provisions



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 53]]

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 54]]

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 55]]

    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 56]]

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 Minerals Revenue Management or his/
her designee. The letter shall identify the valuation method to be used 
and contain a brief description of the procedure to be followed. The 
notification required by this paragraph is a one-time notification due 
no later than the end of the

[[Page 57]]

month following 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 58]]

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 59]]

(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 60]]

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 61]]

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 62]]

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 63]]

    (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,

[[Page 64]]

written agreement, or lease provision 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 10 through 50 
percent of the voting securities or instruments of ownership, or other 
forms of ownership, of another person, MMS will consider the following 
factors in determining whether there is control under the circumstances 
of a particular case:
    (i) The extent to which there are common officers or directors;
    (ii) With respect to the voting securities, or instruments of 
ownership, or other forms of ownership: the percentage of ownership or 
common ownership, the relative percentage of ownership or common 
ownership compared to the percentage(s) of ownership by other persons, 
whether a person is the greatest single owner, or whether there is an 
opposing voting bloc of greater ownership;
    (iii) Operation of a lease, plant, or other facility;
    (iv) The extent of participation by other owners in operations and 
day-to-day management of a lease, plant, or other facility; and
    (v) Other evidence of power to exercise control over or common 
control with another person.
    (3) Regardless of any percentage of ownership or common ownership, 
relatives, either by blood or marriage, are affiliates.
    ANS means Alaska North Slope (ANS).
    Area means a geographic region at least as large as the limits of an 
oil field, in which oil has similar quality, economic, and legal 
characteristics.
    Arm's-length contract means a contract or agreement between 
independent persons who are not affiliates and who have opposing 
economic interests regarding that contract. To be considered arm's 
length for any production month, a contract must satisfy this definition 
for that month, as well as when the contract was executed.
    Audit means a review, conducted under generally accepted accounting 
and auditing standards, of royalty payment compliance activities of 
lessees, designees or other persons who pay royalties, rents, or bonuses 
on Federal leases.
    BLM means the Bureau of Land Management of the Department of the 
Interior.
    Condensate means liquid hydrocarbons (normally exceeding 40 degrees 
of API gravity) recovered at the surface without processing. Condensate 
is the mixture of liquid hydrocarbons resulting from condensation of 
petroleum hydrocarbons existing initially in a gaseous phase in an 
underground reservoir.
    Contract means any oral or written agreement, including amendments 
or revisions, between two or more persons, that is enforceable by law 
and that with due consideration creates an obligation.
    Designee means the person the lessee designates to report and pay 
the lessee's royalties for a lease.
    Exchange agreement means an agreement where one person agrees to 
deliver oil to another person at a specified location in exchange for 
oil deliveries at another location. Exchange agreements may or may not 
specify prices for the oil involved. They frequently specify dollar 
amounts reflecting location, quality, or other differentials. Exchange 
agreements include buy/sell agreements, which specify prices to be paid 
at each exchange point and may appear to be two separate sales within 
the same agreement. Examples of other types of exchange agreements 
include, but are not limited to, exchanges of produced oil for specific 
types of crude oil (e.g., West

[[Page 65]]

Texas Intermediate); exchanges of produced oil for other crude oil at 
other locations (Location Trades); exchanges of produced oil for other 
grades of oil (Grade Trades); and multi-party exchanges.
    Field means a geographic region situated over one or more subsurface 
oil and gas reservoirs and encompassing at least the outermost 
boundaries of all oil and gas accumulations known within those 
reservoirs, vertically projected to the land surface. State oil and gas 
regulatory agencies usually name onshore fields and designate their 
official boundaries. MMS names and designates boundaries of OCS fields.
    Gathering means the movement of lease production to a central 
accumulation or treatment point on the lease, unit, or communitized 
area, or to a central accumulation or treatment point off the lease, 
unit, or communitized area that BLM or MMS approves for onshore and 
offshore leases, respectively.
    Gross proceeds means the total monies and other consideration 
accruing for the disposition of oil produced. Gross proceeds also 
include, but are not limited to, the following examples:
    (1) Payments for services such as dehydration, marketing, 
measurement, or gathering which the lessee must perform at no cost to 
the Federal Government;
    (2) The value of services, such as salt water disposal, that the 
producer normally performs but that the buyer performs on the producer's 
behalf;
    (3) Reimbursements for harboring or terminaling fees;
    (4) Tax reimbursements, even though the Federal royalty interest may 
be exempt from taxation;
    (5) Payments made to reduce or buy down the purchase price of oil to 
be produced in later periods, by allocating such payments over the 
production whose price the payment reduces and including the allocated 
amounts as proceeds for the production as it occurs; and
    (6) Monies and all other consideration to which a seller is 
contractually or legally entitled, but does not seek to collect through 
reasonable efforts.
    Lease means any contract, profit-share arrangement, joint venture, 
or other agreement issued or approved by the United States under a 
mineral leasing law that authorizes exploration for, development or 
extraction of, or removal of oil or gas--or the land area covered by 
that authorization, whichever the context requires.
    Lessee means any person to whom the United States issues an oil and 
gas lease, an assignee of all or a part of the record title interest, or 
any person to whom operating rights in a lease have been assigned.
    Location differential means an amount paid or received (whether in 
money or in barrels of oil) under an exchange agreement that results 
from differences in location between oil delivered in exchange and oil 
received in the exchange. A location differential may represent all or 
part of the difference between the price received for oil delivered and 
the price paid for oil received under a buy/sell exchange agreement.
    Market center means a major point MMS recognizes for oil sales, 
refining, or transshipment. Market centers generally are locations where 
MMS-approved publications publish oil spot prices.
    Marketable condition means oil sufficiently free from impurities and 
otherwise in a condition a purchaser will accept under a sales contract 
typical for the field or area.
    MMS-approved publication means a publication MMS approves for 
determining ANS spot prices or WTI differentials.
    Netting means reducing the reported sales value to account for 
transportation instead of reporting a transportation allowance as a 
separate entry on Form MMS-2014.
    NYMEX price means the average of the New York Mercantile Exchange 
(NYMEX) settlement prices for light sweet crude oil delivered at 
Cushing, Oklahoma, calculated as follows:
    (1) Sum the prices published for each day during the calendar month 
of production (excluding weekends and holidays) for oil to be delivered 
in the prompt month corresponding to each such day; and
    (2) Divide the sum by the number of days on which those prices are 
published (excluding weekends and holidays).

[[Page 66]]

    Oil means a mixture of hydrocarbons that existed in the liquid phase 
in natural underground reservoirs, remains liquid at atmospheric 
pressure after passing through surface separating facilities, and is 
marketed or used as a liquid. Condensate recovered in lease separators 
or field facilities is oil.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside of the area of lands beneath navigable waters as 
defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of 
which the subsoil and seabed appertain to the United States and are 
subject to its jurisdiction and control.
    Person means any individual, firm, corporation, association, 
partnership, consortium, or joint venture (when established as a 
separate entity).
    Prompt month means the nearest month of delivery for which NYMEX 
futures prices are published during the trading month.
    Quality differential means an amount paid or received under an 
exchange agreement (whether in money or in barrels of oil) that results 
from differences in API gravity, sulfur content, viscosity, metals 
content, and other quality factors between oil delivered and oil 
received in the exchange. A quality differential may represent all or 
part of the difference between the price received for oil delivered and 
the price paid for oil received under a buy/sell agreement.
    Rocky Mountain Region means the States of Colorado, Montana, North 
Dakota, South Dakota, Utah, and Wyoming, except for those portions of 
the San Juan Basin and other oil-producing fields in the ``Four 
Corners'' area that lie within Colorado and Utah.
    Roll means an adjustment to the NYMEX price that is calculated as 
follows:
    Roll = .6667 x (P0-P1) + .3333 x 
(P0-P2), where: P0 = the average of the 
daily NYMEX settlement prices for deliveries during the prompt month 
that is the same as the month of production, as published for each day 
during the trading month for which the month of production is the prompt 
month; P1 = the average of the daily NYMEX settlement prices 
for deliveries during the month following the month of production, 
published for each day during the trading month for which the month of 
production is the prompt month; and P2 = the average of the 
daily NYMEX settlement prices for deliveries during the second month 
following the month of production, as published for each day during the 
trading month for which the month of production is the prompt month. 
Calculate the average of the daily NYMEX settlement prices using only 
the days on which such prices are published (excluding weekends and 
holidays).
    (1) Example 1. Prices in Out Months are Lower Going Forward: The 
month of production for which you must determine royalty value is March. 
March was the prompt month (for year 2003) from January 22 through 
February 20. April was the first month following the month of 
production, and May was the second month following the month of 
production. P0 therefore is the average of the daily NYMEX 
settlement prices for deliveries during March published for each 
business day between January 22 and February 20. P1 is the 
average of the daily NYMEX settlement prices for deliveries during April 
published for each business day between January 22 and February 20. 
P2 is the average of the daily NYMEX settlement prices for 
deliveries during May published for each business day between January 22 
and February 20. In this example, assume that P0 = $28.00 per 
bbl, P1 = $27.70 per bbl, and P2 = $27.10 per bbl. 
In this example (a declining market), Roll = .6667 x ($28.00-$27.70) + 
.3333 x ($28.00-$27.10) = $.20 + $.30 = $.50. You add this number to the 
NYMEX price.
    (2) Example 2. Prices in Out Months are Higher Going Forward: The 
month of production for which you must determine royalty value is July. 
July 2003 was the prompt month from May 21 through June 20. August was 
the first month following the month of production, and September was the 
second month following the month of production. P0 therefore 
is the average of the daily NYMEX settlement prices for deliveries 
during July published for each business day between May 21 and June 20. 
P1 is the average of the daily NYMEX settlement prices for 
deliveries during August published for each business day between May 21 
and June

[[Page 67]]

20. P2 is the average of the daily NYMEX settlement prices 
for deliveries during September published for each business day between 
May 21 and June 20. In this example, assume that P0 = $28.00 
per bbl, P1 = $28.90 per bbl, and P2 = $29.50 per 
bbl. In this example (a rising market), Roll = .6667 x ($28.00-$28.90) + 
.3333 x ($28.00-$29.50) = (-$.60) + (-$.50) = -$1.10. You add this 
negative number to the NYMEX price (effectively a subtraction from the 
NYMEX price).
    Sale means a contract between two persons where:
    (1) The seller unconditionally transfers title to the oil to the 
buyer and does not retain any related rights such as the right to buy 
back similar quantities of oil from the buyer elsewhere;
    (2) The buyer pays money or other consideration for the oil; and
    (3) The parties' intent is for a sale of the oil to occur.
    Spot price means the price under a spot sales contract where:
    (1) A seller agrees to sell to a buyer a specified amount of oil at 
a specified price over a specified period of short duration;
    (2) No cancellation notice is required to terminate the sales 
agreement; and
    (3) There is no obligation or implied intent to continue to sell in 
subsequent periods.
    Tendering program means a producer's offer of a portion of its crude 
oil produced from a field or area for competitive bidding, regardless of 
whether the production is offered or sold at or near the lease or unit 
or away from the lease or unit.
    Trading month means the period extending from the second business 
day before the 25th day of the second calendar month preceding the 
delivery month (or, if the 25th day of that month is a non-business day, 
the second business day before the last business day preceding the 25th 
day of that month) through the third business day before the 25th day of 
the calendar month preceding the delivery month (or, if the 25th day of 
that month is a non-business day, the third business day before the last 
business day preceding the 25th day of that month), unless the NYMEX 
publishes a different definition or different dates on its official Web 
site, www.nymex.com, in which case the NYMEX definition will apply.
    Transportation allowance means a deduction in determining royalty 
value for the reasonable, actual costs of moving oil to a point of sale 
or delivery off the lease, unit area, or communitized area. The 
transportation allowance does not include gathering costs.
    WTI differential means the average of the daily mean differentials 
for location and quality between a grade of crude oil at a market center 
and West Texas Intermediate (WTI) crude oil at Cushing published for 
each day for which price publications perform surveys for deliveries 
during the production month, calculated over the number of days on which 
those differentials are published (excluding weekends and holidays). 
Calculate the daily mean differentials by averaging the daily high and 
low differentials for the month in the selected publication. Use only 
the days and corresponding differentials for which such differentials 
are published.
    (1) Example. Assume the production month was March 2003. Industry 
trade publications performed their price surveys and determined 
differentials during January 26 through February 25 for oil delivered in 
March. The WTI differential (for example, the West Texas Sour crude at 
Midland, Texas, spread versus WTI) applicable to valuing oil produced in 
the March 2003 production month would be determined using all the 
business days for which differentials were published during the period 
January 26 through February 25 excluding weekends and holidays (22 
days). To calculate the WTI differential, add together all of the daily 
mean differentials published for January 26 through February 25 and 
divide that sum by 22.
    (2) [Reserved]

[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24975, May 5, 2004]



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 Sec. Sec. 206.110 or 206.111. This value

[[Page 68]]

does not apply if you exercise an option to use a different value 
provided in paragraph (d)(1) or (d)(2)(i) of this section, or if one of 
the exceptions in paragraph (c) of this section applies. Use this 
paragraph (a) to value oil that:
    (1) You sell under an arm's-length sales contract; or
    (2) You sell or transfer to your affiliate or another person under a 
non-arm's-length contract and that affiliate or person, or another 
affiliate of either of them, then sells the oil under an arm's-length 
contract, unless you exercise the option provided in paragraph (d)(2)(i) 
of this section.
    (b) If you have multiple arm's-length contracts to sell oil produced 
from a lease that is valued under paragraph (a) of this section, the 
value of the oil is the volume-weighted average of the values 
established under this section for each contract for the sale of oil 
produced from that lease.
    (c) This paragraph contains exceptions to the valuation rule in 
paragraph (a) of this section. Apply these exceptions on an individual 
contract basis.
    (1) In conducting reviews and audits, if MMS determines that any 
arm's-length sales contract does not reflect the total consideration 
actually transferred either directly or indirectly from the buyer to the 
seller, MMS may require that you value the oil sold under that contract 
either under 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

[[Page 69]]

arm's length. You may not change your election more often than once 
every 2 years.
    (e) If you value oil under paragraph (a) of this section:
    (1) MMS may require you to certify that your or your affiliate's 
arm's-length contract provisions include all of the consideration the 
buyer must pay, either directly or indirectly, for the oil.
    (2) You must base value on the highest price the seller can receive 
through legally enforceable claims under the contract.
    (i) If the seller fails to take proper or timely action to receive 
prices or benefits it is entitled to, you must pay royalty at a value 
based upon that obtainable price or benefit. But you will owe no 
additional royalties unless or until the seller receives monies or 
consideration resulting from the price increase or additional benefits, 
if:
    (A) The seller makes timely application for a price increase or 
benefit allowed under the contract;
    (B) The purchaser refuses to comply; and
    (C) The seller takes reasonable documented measures to force 
purchaser compliance.
    (ii) Paragraph (e)(2)(i) of this section will not permit you to 
avoid your royalty payment obligation where a purchaser fails to pay, 
pays only in part, or pays late. Any contract revisions or amendments 
that reduce prices or benefits to which the seller is entitled must be 
in writing and signed by all parties to the arm's-length contract.



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. You must consistently apply paragraph 
(b)(1), (b)(2), or (b)(3) of this section to value all of your 
production from the same unit, communitization agreement, or lease (if 
the lease or a portion of the lease is not part of a unit or 
communitization agreement) that you cannot value under Sec. 206.102 or 
that you elect under Sec. 206.102(d) to value under this section.
    (1) If you have an MMS-approved tendering program, you must value 
oil produced from leases in the area the tendering program covers at the 
highest winning bid price for tendered volumes.
    (i) The minimum requirements for MMS to approve your tendering 
program are:
    (A) You must offer and sell at least 30 percent of your or your 
affiliates' production from both Federal and non-Federal leases in the 
area under your tendering program; and

[[Page 70]]

    (B) You must receive at least three bids for the tendered volumes 
from bidders who do not have their own tendering programs that cover 
some or all of the same area.
    (ii) If you do not have an MMS-approved tendering program, you may 
elect to value your oil under either paragraph (b)(2) or (b)(3) of this 
section. After you select either paragraph (b)(2) or (b)(3) of this 
section, you may not change to the other method more often than once 
every 2 years, unless the method you have been using is no longer 
applicable and you must apply the other paragraph. If you change 
methods, you must begin a new 2-year period.
    (2) Value is the volume-weighted average of the gross proceeds 
accruing to the seller under your or your affiliates' arm's-length 
contracts for the purchase or sale of production from the field or area 
during the production month.
    (i) The total volume purchased or sold under those contracts must 
exceed 50 percent of your and your affiliates' production from both 
Federal and non-Federal leases in the same field or area during that 
month.
    (ii) Before calculating the volume-weighted average, you must 
normalize the quality of the oil in your or your affiliates' arm's-
length purchases or sales to the same gravity as that of the oil 
produced from the lease.
    (3) Value is the NYMEX price (without the roll), adjusted for 
applicable location and quality differentials and transportation costs 
under Sec. 206.112.
    (4) If you demonstrate to MMS's satisfaction that paragraphs (b)(1) 
through (b)(3) of this section result in an unreasonable value for your 
production as a result of circumstances regarding that production, the 
MMS Director may establish an alternative valuation method.
    (c) Production from leases not located in California, Alaska, or the 
Rocky Mountain Region. (1) Value is the NYMEX price, plus the roll, 
adjusted for applicable location and quality differentials and 
transportation costs under Sec. 206.112.
    (2) If the MMS Director determines that use of the roll no longer 
reflects prevailing industry practice in crude oil sales contracts or 
that the most common formula used by industry to calculate the roll 
changes, MMS may terminate or modify use of the roll under paragraph 
(c)(1) of this section at the end of each 2-year period following July 
6, 2004, through notice published in the Federal Register not later than 
60 days before the end of the 2-year period. MMS will explain the 
rationale for terminating or modifying the use of the roll in this 
notice.
    (d) Unreasonable value. If MMS determines that the NYMEX price or 
ANS spot price does not represent a reasonable royalty value in any 
particular case, MMS may establish reasonable royalty value based on 
other relevant matters.
    (e) Production delivered to your refinery and the NYMEX price or ANS 
spot price is an unreasonable value. (1) Instead of valuing your 
production under paragraph (a), (b), or (c) of this section, you may 
apply to the MMS Director to establish a value representing the market 
at the refinery if:
    (i) You transport your oil directly to your or your affiliate's 
refinery, or exchange your oil for oil delivered to your or your 
affiliate's refinery; and
    (ii) You must value your oil under this section at the NYMEX price 
or ANS spot price; and
    (iii) You believe that use of the NYMEX price or ANS spot price 
results in an unreasonable royalty value.
    (2) You must provide adequate documentation and evidence 
demonstrating the market value at the refinery. That evidence may 
include, but is not limited to:
    (i) Costs of acquiring other crude oil at or for the refinery;
    (ii) How adjustments for quality, location, and transportation were 
factored into the price paid for other oil;
    (iii) Volumes acquired for and refined at the refinery; and
    (iv) Any other appropriate evidence or documentation that MMS 
requires.
    (3) If the MMS Director establishes a value representing market 
value at the refinery, you may not take an allowance against that value 
under

[[Page 71]]

Sec. 206.112(b) unless it is included in the Director's approval.

[65 FR 14088, Mar. 15, 2002, as amended at 67 FR 19111, Apr. 18, 2002; 
69 FR 24976, May 5, 2004]



Sec. 206.104  What publications are acceptable to MMS?

    (a) MMS periodically will publish in the Federal Register a list of 
acceptable publications for the NYMEX price and ANS spot price based on 
certain criteria, including, but not limited to:
    (1) Publications buyers and sellers frequently use;
    (2) Publications frequently mentioned in purchase or sales 
contracts;
    (3) Publications that use adequate survey techniques, including 
development of estimates based on daily surveys of buyers and sellers of 
crude oil, and, for ANS spot prices, buyers and sellers of ANS crude 
oil; and
    (4) Publications independent from MMS, other lessors, and lessees.
    (b) Any publication may petition MMS to be added to the list of 
acceptable publications.
    (c) MMS will specify the tables you must use in the acceptable 
publications.
    (d) MMS may revoke its approval of a particular publication if it 
determines that the prices or differentials published in the publication 
do not accurately represent NYMEX prices or differentials or ANS spot 
market prices or differentials.

[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24976, May 5, 2004]



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;
    (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

[[Page 72]]

    (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 Sec. Sec. 
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 NYMEX prices or ANS spot prices. If you value oil 
using NYMEX prices or ANS spot prices under Sec. 206.103, MMS will 
allow an adjustment for certain location and quality differentials 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

[[Page 73]]

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 Sec. Sec. 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.

[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24976, May 5, 2004]



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 as more fully 
explained in paragraph (b) of this section, except as provided in 
paragraphs (a)(1) and (a)(2) of this section and subject to the 
limitation in Sec. 206.109(c). You must be able to demonstrate that 
your or your affiliate's contract is at arm's length. You do not need 
MMS approval before reporting a transportation allowance for costs 
incurred under an arm's-length transportation contract.
    (1) If MMS determines that the contract reflects more than the 
consideration actually transferred either directly or indirectly from 
you or your affiliate to the transporter for the transportation, MMS may 
require that you calculate the transportation allowance under 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) You may deduct any of the following actual costs you (including 
your affiliates) incur for transporting oil. You may not use as a 
deduction any cost that duplicates all or part of any other cost that 
you use under this paragraph.
    (1) The amount that you pay under your arm's-length transportation 
contract or tariff.
    (2) Fees paid (either in volume or in value) for actual or 
theoretical line losses.
    (3) Fees paid for administration of a quality bank.
    (4) The cost of carrying on your books as inventory a volume of oil 
that the pipeline operator requires you to maintain, and that you do 
maintain, in the line as line fill. You must calculate this cost as 
follows:
    (i) Multiply the volume that the pipeline requires you to maintain, 
and that you do maintain, in the pipeline by the value of that volume 
for the

[[Page 74]]

current month calculated under Sec. 206.102 or Sec.  206.103, as 
applicable; and
    (ii) Multiply the value calculated under paragraph (b)(4)(i) of this 
section by the monthly rate of return, calculated by dividing the rate 
of return specified in Sec. 206.111(i)(2) by 12.
    (5) Fees paid to a terminal operator for loading and unloading of 
crude oil into or from a vessel, vehicle, pipeline, or other conveyance.
    (6) Fees paid for short-term storage (30 days or less) incidental to 
transportation as required by a transporter.
    (7) Fees paid to pump oil to another carrier's system or vehicles as 
required under a tariff.
    (8) Transfer fees paid to a hub operator associated with physical 
movement of crude oil through the hub when you do not sell the oil at 
the hub. These fees do not include title transfer fees.
    (9) Payments for a volumetric deduction to cover shrinkage when 
high-gravity petroleum (generally in excess of 51 degrees API) is mixed 
with lower-gravity crude oil for transportation.
    (10) Costs of securing a letter of credit, or other surety, that the 
pipeline requires you as a shipper to maintain.
    (c) You may not deduct any costs that are not actual costs of 
transporting oil, including but not limited to the following:
    (1) Fees paid for long-term storage (more than 30 days).
    (2) Administrative, handling, and accounting fees associated with 
terminalling.
    (3) Title and terminal transfer fees.
    (4) Fees paid to track and match receipts and deliveries at a market 
center or to avoid paying title transfer fees.
    (5) Fees paid to brokers.
    (6) Fees paid to a scheduling service provider.
    (7) Internal costs, including salaries and related costs, rent/space 
costs, office equipment costs, legal fees, and other costs to schedule, 
nominate, and account for sale or movement of production.
    (8) Gauging fees.
    (d) If your arm's-length transportation contract includes more than 
one liquid product, and the transportation costs attributable to each 
product cannot be determined from the contract, then you must allocate 
the total transportation costs to each of the liquid products 
transported.
    (1) Your allocation must use the same proportion as the ratio of the 
volume of each product (excluding waste products with no value) to the 
volume of all liquid products (excluding waste products with no value).
    (2) You may not claim an allowance for the costs of transporting 
lease production that is not royalty-bearing.
    (3) You may propose to MMS a cost allocation method on the basis of 
the values of the products transported. MMS will approve the method 
unless it is not consistent with the purposes of the regulations in this 
subpart.
    (e) If your arm's-length transportation contract includes both 
gaseous and liquid products, and the transportation costs attributable 
to each product cannot be determined from the contract, then you must 
propose an allocation procedure to MMS.
    (1) You may use your proposed procedure to calculate a 
transportation allowance until MMS accepts or rejects your cost 
allocation. If MMS rejects your cost allocation, you must amend your 
Form MMS-2014 for the months that you used the rejected method and pay 
any additional royalty and interest due.
    (2) You must submit your initial proposal, including all available 
data, within 3 months after first claiming the allocated deductions on 
Form MMS-2014.
    (f) If your payments for transportation under an arm's-length 
contract are not on a dollar-per-unit basis, you must convert whatever 
consideration is paid to a dollar-value equivalent.
    (g) If your arm's-length sales contract includes a provision 
reducing the contract price by a transportation factor, do not 
separately report the transportation factor as a transportation 
allowance on Form MMS-2014.
    (1) You may use the transportation factor in determining your gross 
proceeds for the sale of the product.
    (2) You must obtain MMS approval before claiming a transportation 
factor

[[Page 75]]

in excess of 50 percent of the base price of the product.

[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24976, May 5, 2004]



Sec. 206.111  How do I determine a transportation allowance if I do not have 

an arm's-length transportation contract or arm's-length tariff?

    (a) This section applies if you or your affiliate do not have an 
arm's-length transportation contract, including situations where you or 
your affiliate provide your own transportation services. Calculate your 
transportation allowance based on your or your affiliate's reasonable, 
actual costs for transportation during the reporting period using the 
procedures prescribed in this section.
    (b) Your or your affiliate's actual costs include the following:
    (1) Operating and maintenance expenses under paragraphs (d) and (e) 
of this section;
    (2) Overhead under paragraph (f) of this section;
    (3) Depreciation under paragraphs (g) and (h) of this section;
    (4) A return on undepreciated capital investment under paragraph (i) 
of this section; and
    (5) Once the transportation system has been depreciated below ten 
percent of total capital investment, a return on ten percent of total 
capital investment under paragraph (j) of this section.
    (6) To the extent not included in costs identified in paragraphs (d) 
through (j) of this section, you may also deduct the following actual 
costs. You may not use any cost as a deduction that duplicates all or 
part of any other cost that you use under this section:
    (i) Volumetric adjustments for actual (not theoretical) line losses.
    (ii) The cost of carrying on your books as inventory a volume of oil 
that the pipeline operator requires you as a shipper to maintain, and 
that you do maintain, in the line as line fill. You must calculate this 
cost as follows:
    (A) Multiply the volume that the pipeline requires you to maintain, 
and that you do maintain, in the pipeline by the value of that volume 
for the current month calculated under Sec. 206.102 or Sec.  206.103, 
as applicable; and
    (B) Multiply the value calculated under paragraph (b)(6)(ii)(A) of 
this section by the monthly rate of return, calculated by dividing the 
rate of return specified in Sec. 206.111(i)(2) by 12.
    (iii) Fees paid to a non-affiliated terminal operator for loading 
and unloading of crude oil into or from a vessel, vehicle, pipeline, or 
other conveyance.
    (iv) Transfer fees paid to a hub operator associated with physical 
movement of crude oil through the hub when you do not sell the oil at 
the hub. These fees do not include title transfer fees.
    (v) A volumetric deduction to cover shrinkage when high-gravity 
petroleum (generally in excess of 51 degrees API) is mixed with lower-
gravity crude oil for transportation.
    (vi) Fees paid to a non-affiliated quality bank administrator for 
administration of a quality bank.
    (7) You may not deduct any costs that are not actual costs of 
transporting oil, including but not limited to the following:
    (i) Fees paid for long-term storage (more than 30 days).
    (ii) Administrative, handling, and accounting fees associated with 
terminalling.
    (iii) Title and terminal transfer fees.
    (iv) Fees paid to track and match receipts and deliveries at a 
market center or to avoid paying title transfer fees.
    (v) Fees paid to brokers.
    (vi) Fees paid to a scheduling service provider.
    (vii) Internal costs, including salaries and related costs, rent/
space costs, office equipment costs, legal fees, and other costs to 
schedule, nominate, and account for sale or movement of production.
    (viii) Theoretical line losses.
    (ix) Gauging fees.
    (c) Allowable capital costs are generally those for depreciable 
fixed assets (including costs of delivery and installation of capital 
equipment) which are an integral part of the transportation system.
    (d) Allowable operating expenses include:
    (i) Operations supervision and engineering;
    (ii) Operations labor;

[[Page 76]]

    (iii) Fuel;
    (iv) Utilities;
    (v) Materials;
    (vi) Ad valorem property taxes;
    (vii) Rent;
    (viii) Supplies; and
    (ix) Any other directly allocable and attributable operating expense 
which you can document.
    (e) Allowable maintenance expenses include:
    (i) Maintenance of the transportation system;
    (ii) Maintenance of equipment;
    (iii) Maintenance labor; and
    (iv) Other directly allocable and attributable maintenance expenses 
which you can document.
    (f) Overhead directly attributable and allocable to the operation 
and maintenance of the transportation system is an allowable expense. 
State and Federal income taxes and severance taxes and other fees, 
including royalties, are not allowable expenses.
    (g) To compute depreciation, you may elect to use either a straight-
line depreciation method based on the life of equipment or on the life 
of the reserves which the transportation system services, or a unit-of-
production method. After you make an election, you may not change 
methods without MMS approval. You may not depreciate equipment below a 
reasonable salvage value.
    (h) This paragraph describes the basis for your depreciation 
schedule.
    (1) If you or your affiliate own a transportation system on June 1, 
2000, you must base your depreciation schedule used in calculating 
actual transportation costs for production after June 1, 2000, on your 
total capital investment in the system (including your original purchase 
price or construction cost and subsequent reinvestment).
    (2) If you or your affiliate purchased the transportation system at 
arm's length before June 1, 2000, you must incorporate depreciation on 
the schedule based on your purchase price (and subsequent reinvestment) 
into your transportation allowance calculations for production after 
June 1, 2000, beginning at the point on the depreciation schedule 
corresponding to that date. You must prorate your depreciation for 
calendar year 2000 by claiming part-year depreciation for the period 
from June 1, 2000 until December 31, 2000. You may not adjust your 
transportation costs for production before June 1, 2000, using the 
depreciation schedule based on your purchase price.
    (3) If you are the original owner of the transportation system on 
June 1, 2000, or if you purchased your transportation system before 
March 1, 1988, you must continue to use your existing depreciation 
schedule in calculating actual transportation costs for production in 
periods after June 1, 2000.
    (4) If you or your affiliate purchase a transportation system at 
arm's length from the original owner after June 1, 2000, you must base 
your depreciation schedule used in calculating actual transportation 
costs on your total capital investment in the system (including your 
original purchase price and subsequent reinvestment). You must prorate 
your depreciation for the year in which you or your affiliate purchased 
the system to reflect the portion of that year for which you or your 
affiliate own the system.
    (5) If you or your affiliate purchase a transportation system at 
arm's length after June 1, 2000, from anyone other than the original 
owner, you must assume the depreciation schedule of the person from whom 
you bought the system. Include in the depreciation schedule any 
subsequent reinvestment.
    (i)(1) To calculate a return on undepreciated capital investment, 
multiply the remaining undepreciated capital balance as of the beginning 
of the period for which you are calculating the transportation allowance 
by the rate of return provided in paragraph (i)(2) of this section.
    (2) The rate of return is 1.3 times the industrial bond yield index 
for Standard & Poor's BBB bond rating. Use the monthly average rate 
published in ``Standard & Poor's Bond Guide'' for the first month of the 
reporting period for which the allowance applies. Calculate the rate at 
the beginning of each subsequent transportation allowance reporting 
period.
    (j)(1) After a transportation system has been depreciated at or 
below a value equal to ten percent of your total capital investment, you 
may continue to include in the allowance calculation

[[Page 77]]

a cost equal to ten percent of your total capital investment in the 
transportation system multiplied by a rate of return under paragraph 
(i)(2) of this section.
    (2) You may apply this paragraph to a transportation system that 
before June 1, 2000, was depreciated at or below a value equal to ten 
percent of your total capital investment.
    (k) Calculate the deduction for transportation costs based on your 
or your affiliate's cost of transporting each product through each 
individual transportation system. Where more than one liquid product is 
transported, allocate costs consistently and equitably to each of the 
liquid products transported. Your allocation must use the same 
proportion as the ratio of the volume of each liquid product (excluding 
waste products with no value) to the volume of all liquid products 
(excluding waste products with no value).
    (1) You may not take an allowance for transporting lease production 
that is not royalty-bearing.
    (2) You may propose to MMS a cost allocation method on the basis of 
the values of the products transported. MMS will approve the method if 
it is consistent with the purposes of the regulations in this subpart.
    (l)(1) Where you transport both gaseous and liquid products through 
the same transportation system, you must propose a cost allocation 
procedure to MMS.
    (2) You may use your proposed procedure to calculate a 
transportation allowance until MMS accepts or rejects your cost 
allocation. If MMS rejects your cost allocation, you must amend your 
Form MMS-2014 for the months that you used the rejected method and pay 
any additional royalty and interest due.
    (3) You must submit your initial proposal, including all available 
data, within 3 months after first claiming the allocated deductions on 
Form MMS-2014.

[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24977, May 5, 2004]



Sec. 206.112  What adjustments and transportation allowances apply when I 

value oil production from my lease using NYMEX prices or ANS spot prices?

    This section applies when you use NYMEX prices or ANS spot prices to 
calculate the value of production under Sec. 206.103. As specified in 
this section, adjust the NYMEX price to reflect the difference in value 
between your lease and Cushing, Oklahoma, or adjust the ANS spot price 
to reflect the difference in value between your lease and the 
appropriate MMS-recognized market center at which the ANS spot price is 
published (for example, Long Beach, California, or San Francisco, 
California). Paragraph (a) of this section explains how you adjust the 
value between the lease and the market center, and paragraph (b) of this 
section explains how you adjust the value between the market center and 
Cushing when you use NYMEX prices. Paragraph (c) of this section 
explains how adjustments may be made for quality differentials that are 
not accounted for through exchange agreements. Paragraph (d) of this 
section gives some examples. References in this section to ``you'' 
include your affiliates as applicable.
    (a) To adjust the value between the lease and the market center:
    (1)(i) For oil that you exchange at arm's length between your lease 
and the market center (or between any intermediate points between those 
locations), you must calculate a lease-to-market center differential by 
the applicable location and quality differentials derived from your 
arm's-length exchange agreement applicable to production during the 
production month.
    (ii) For oil that you exchange between your lease and the market 
center (or between any intermediate points between those locations) 
under an exchange agreement that is not at arm's length, you must obtain 
approval from MMS for a location and quality differential. Until you 
obtain such approval, you may use the location and quality differential 
derived from that exchange agreement applicable to production during the 
production month. If MMS prescribes a different differential, you must 
apply MMS's differential to all periods for which you used

[[Page 78]]

your proposed differential. You must pay any additional royalties owed 
resulting from using MMS's differential plus late payment interest from 
the original royalty due date, or you may report a credit for any 
overpaid royalties plus interest under 30 U.S.C. 1721(h).
    (2) For oil that you transport between your lease and the market 
center (or between any intermediate points between those locations), you 
may take an allowance for the cost of transporting that oil between the 
relevant points as determined under Sec. 206.110 or Sec.  206.111, as 
applicable.
    (3) If you transport or exchange at arm's length (or both transport 
and exchange) at least 20 percent, but not all, of your oil produced 
from the lease to a market center, determine the adjustment between the 
lease and the market center for the oil that is not transported or 
exchanged (or both transported and exchanged) to or through a market 
center as follows:
    (i) Determine the volume-weighted average of the lease-to-market 
center adjustment calculated under paragraphs (a)(1) and (a)(2) of this 
section for the oil that you do transport or exchange (or both transport 
and exchange) from your lease to a market center.
    (ii) Use that volume-weighted average lease-to-market center 
adjustment as the adjustment for the oil that you do not transport or 
exchange (or both transport and exchange) from your lease to a market 
center.
    (4) If you transport or exchange (or both transport and exchange) 
less than 20 percent of the crude oil produced from your lease between 
the lease and a market center, you must propose to MMS an adjustment 
between the lease and the market center for the portion of the oil that 
you do not transport or exchange (or both transport and exchange) to a 
market center. Until you obtain such approval, you may use your proposed 
adjustment. If MMS prescribes a different adjustment, you must apply 
MMS's adjustment to all periods for which you used your proposed 
adjustment. You must pay any additional royalties owed resulting from 
using MMS's adjustment plus late payment interest from the original 
royalty due date, or you may report a credit for any overpaid royalties 
plus interest under 30 U.S.C. 1721(h).
    (5) You may not both take a transportation allowance and use a 
location and quality adjustment or exchange differential for the same 
oil between the same points.
    (b) For oil that you value using NYMEX prices, adjust the value 
between the market center and Cushing, Oklahoma, as follows:
    (1) If you have arm's-length exchange agreements between the market 
center and Cushing under which you exchange to Cushing at least 20 
percent of all the oil you own at the market center during the 
production month, you must use the volume-weighted average of the 
location and quality differentials from those agreements as the 
adjustment between the market center and Cushing for all the oil that 
you produce from the leases during that production month for which that 
market center is used.
    (2) If paragraph (b)(1) of this section does not apply, you must use 
the WTI differential published in an MMS-approved publication for the 
market center nearest your lease, for crude oil most similar in quality 
to your production, as the adjustment between the market center and 
Cushing. (For example, for light sweet crude oil produced offshore of 
Louisiana, use the WTI differential for Light Louisiana Sweet crude oil 
at St. James, Louisiana.) After you select an MMS-approved publication, 
you may not select a different publication more often than once every 2 
years, unless the publication you use is no longer published or MMS 
revokes its approval of the publication. If you are required to change 
publications, you must begin a new 2-year period.
    (3) If neither paragraph (b)(1) nor (b)(2) of this section applies, 
you may propose an alternative differential to MMS. Until you obtain 
such approval, you may use your proposed differential. If MMS prescribes 
a different differential, you must apply MMS's differential to all 
periods for which you used your proposed differential. You must pay any 
additional royalties owed resulting from using MMS's differential plus 
late payment interest from the original royalty due date, or you

[[Page 79]]

may report a credit for any overpaid royalties plus interest under 30 
U.S.C. 1721(h).
    (c)(1) If you adjust for location and quality differentials or for 
transportation costs under paragraphs (a) and (b) of this section, also 
adjust the NYMEX price or ANS spot price for quality based on premiums 
or penalties determined by pipeline quality bank specifications at 
intermediate commingling points or at the market center if those points 
are downstream of the royalty measurement point approved by MMS or BLM, 
as applicable. Make this adjustment only if and to the extent that such 
adjustments were not already included in the location and quality 
differentials determined from your arm's-length exchange agreements.
    (2) If the quality of your oil as adjusted is still different from 
the quality of the representative crude oil at the market center after 
making the quality adjustments described in paragraphs (a), (b) and 
(c)(1) of this section, you may make further gravity adjustments using 
posted price gravity tables. If quality bank adjustments do not 
incorporate or provide for adjustments for sulfur content, you may make 
sulfur adjustments, based on the quality of the representative crude oil 
at the market center, of 5.0 cents per one-tenth percent difference in 
sulfur content, unless MMS approves a higher adjustment.
    (d) The examples in this paragraph illustrate how to apply the 
requirement of this section.
    (1) Example. Assume that a Federal lessee produces crude oil from a 
lease near Artesia, New Mexico. Further, assume that the lessee 
transports the oil to Roswell, New Mexico, and then exchanges the oil to 
Midland, Texas. Assume the lessee refines the oil received in exchange 
at Midland. Assume that the NYMEX price is $30.00/bbl, adjusted for the 
roll; that the WTI differential (Cushing to Midland) is -$.10/bbl; that 
the lessee's exchange agreement between Roswell and Midland results in a 
location and quality differential of -$.08/bbl; and that the lessee's 
actual cost of transporting the oil from Artesia to Roswell is $.40/bbl. 
In this example, the royalty value of the oil is $30.00-$.10-$.08--$.40 
= $29.42/bbl.
    (2) Example. Assume the same facts as in the example in paragraph 
(1), except that the lessee transports and exchanges to Midland 40 
percent of the production from the lease near Artesia, and transports 
the remaining 60 percent directly to its own refinery in Ohio. In this 
example, the 40 percent of the production would be valued at $29.42/bbl, 
as explained in the previous example. In this example, the other 60 
percent also would be valued at $29.42/bbl.
    (3) Example. Assume that a Federal lessee produces crude oil from a 
lease near Bakersfield, California. Further, assume that the lessee 
transports the oil to Hynes Station, and then exchanges the oil to 
Cushing which it further exchanges with oil it refines. Assume that the 
ANS spot price is $20.00/bbl, and that the lessee's actual cost of 
transporting the oil from Bakersfield to Hynes Station is $.28/bbl. The 
lessee must request approval from MMS for a location and quality 
adjustment between Hynes Station and Long Beach. For example, the lessee 
likely would propose using the tariff on Line 63 from Hynes Station to 
Long Beach as the adjustment between those points. Assume that 
adjustment to be $.72, including the sulfur and gravity bank 
adjustments, and that MMS approves the lessee's request. In this 
example, the preliminary (because the location and quality adjustment is 
subject to MMS review) royalty value of the oil is $20.00-$.72-$.28 = 
$19.00/bbl. The fact that oil was exchanged to Cushing does not change 
use of ANS spot prices for royalty valuation.

[69 FR 24978, May 5, 2004]



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:

[[Page 80]]

    (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 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. 206.119  How are royalty quantity and quality determined?

    (a) Compute royalties based on the quantity and quality of oil as 
measured at the point of settlement approved by BLM for onshore leases 
or MMS for offshore leases.
    (b) If the value of oil determined under this subpart is based upon 
a quantity or quality different from the quantity or quality at the 
point of royalty settlement approved by the BLM for onshore leases or 
MMS for offshore leases, adjust the value for those differences in 
quantity or quality.
    (c) Any actual loss that you may incur before the royalty settlement 
metering or measurement point is not subject to royalty if BLM or MMS, 
as

[[Page 81]]

appropriate, determines that the loss is unavoidable.
    (d) Except as provided in paragraph (b) of this section, royalties 
are due on 100 percent of the volume measured at the approved point of 
royalty settlement. You may not claim a reduction in that measured 
volume for actual losses beyond the approved point of royalty settlement 
or for theoretical losses that are claimed to have taken place either 
before or after the approved point of royalty settlement.

[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24979, May 5, 2004]



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.



                          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 regulations in this subpart are inconsistent with:
    (1) A Federal statute;
    (2) A settlement agreement between the United States and a lessee 
resulting from administrative or judicial litigation;
    (3) A written agreement between the lessee and the MMS Director 
establishing a method to determine the value of production from any 
lease that MMS expects at least would approximate the value established 
under this subpart; or
    (4) An express provision of an oil and gas lease subject to this 
subpart; then the statute, settlement agreement, written agreement, or 
lease provision will govern to the extent of the inconsistency.
    (c) All royalty payments made to MMS are subject to audit and 
adjustment.
    (d) The regulations in this subpart are intended to ensure that the 
administration of oil and gas leases is discharged in accordance with 
the requirements of the governing mineral leasing laws and lease terms.

[61 FR 5464, Feb. 12, 1996, as amended at 70 FR 11877, Mar. 10, 2005]



Sec. 206.151  Definitions.

    For purposes of this subpart:
    Affiliate means a person who controls, is controlled by, or is under 
common control with another person. For purposes of this subpart:
    (1) Ownership or common ownership of more than 50 percent of the 
voting securities, or instruments of ownership, or other forms of 
ownership, of another person constitutes control. Ownership of less than 
10 percent constitutes a presumption of noncontrol that MMS may rebut.
    (2) If there is ownership or common ownership of 10 through 50 
percent of the voting securities or instruments of ownership, or other 
forms of ownership, of another person, MMS will consider the following 
factors in determining whether there is control under the circumstances 
of a particular case:
    (i) The extent to which there are common officers or directors;
    (ii) With respect to the voting securities, or instruments of 
ownership, or other forms of ownership: The percentage of ownership or 
common ownership, the relative percentage of ownership or common 
ownership compared to the percentage(s) of ownership by other persons, 
whether a person is the greatest single owner, or whether there is an 
opposing voting bloc of greater ownership;
    (iii) Operation of a lease, plant, pipeline, or other facility;
    (iv) The extent of participation by other owners in operations and 
day-to-day management of a lease, plant, pipeline, or other facility; 
and
    (v) Other evidence of power to exercise control over or common 
control with another person.

[[Page 82]]

    (3) Regardless of any percentage of ownership or common ownership, 
relatives, either by blood or marriage, are affiliates.
    Allowance means a deduction in determining value for royalty 
purposes. Processing allowance means an allowance for the reasonable, 
actual costs of processing gas determined under this subpart. 
Transportation allowance means an allowance for the reasonable, actual 
costs of moving unprocessed gas, residue gas, or gas plant products to a 
point of sale or delivery off the lease, unit area, or communitized 
area, or away from a processing plant. The transportation allowance does 
not include gathering costs.
    Area means a geographic region at least as large as the defined 
limits of an oil and/or gas field, in which oil and/or gas lease 
products have similar quality, economic, and legal characteristics.
    Arm's-length contract means a contract or agreement between 
independent persons who are not affiliates and who have opposing 
economic interests regarding that contract. To be considered arm's 
length for any production month, a contract must satisfy this definition 
for that month, as well as when the contract was executed.
    Audit means a review, conducted in accordance with generally 
accepted accounting and auditing standards, of royalty payment 
compliance activities of lessees or other interest holders who pay 
royalties, rents, or bonuses on Federal leases.
    BLM means the Bureau of Land Management of the Department of the 
Interior.
    Compression means the process of raising the pressure of gas.
    Condensate means liquid hydrocarbons (normally exceeding 40 degrees 
of API gravity) recovered at the surface without resorting to 
processing. Condensate is the mixture of liquid hydrocarbons that 
results from condensation of petroleum hydrocarbons existing initially 
in a gaseous phase in an underground reservoir.
    Contract means any oral or written agreement, including amendments 
or revisions thereto, between two or more persons and enforceable by law 
that with due consideration creates an obligation.
    Field means a geographic region situated over one or more subsurface 
oil and gas reservoirs encompassing at least the outermost boundaries of 
all oil and gas accumulations known to be within those reservoirs 
vertically projected to the land surface. Onshore fields are usually 
given names and their official boundaries are often designated by oil 
and gas regulatory agencies in the respective States in which the fields 
are located. Outer Continental Shelf (OCS) fields are named and their 
boundaries are designated by MMS.
    Gas means any fluid, either combustible or noncombustible, 
hydrocarbon or nonhydrocarbon, which is extracted from a reservoir and 
which has neither independent shape nor volume, but tends to expand 
indefinitely. It is a substance that exists in a gaseous or rarefied 
state under standard temperature and pressure conditions.
    Gas plant products means separate marketable elements, compounds, or 
mixtures, whether in liquid, gaseous, or solid form, resulting from 
processing gas, excluding residue gas.
    Gathering means the movement of lease production to a central 
accumulation and/or treatment point on the lease, unit or communitized 
area, or to a central accumulation or treatment point off the lease, 
unit or communitized area as approved by BLM or MMS OCS operations 
personnel for onshore and OCS leases, respectively.
    Gross proceeds (for royalty payment purposes) means the total monies 
and other consideration accruing to an oil and gas lessee for the 
disposition of the gas, residue gas, and gas plant products produced. 
Gross proceeds includes, but is not limited to, payments to the lessee 
for certain services such as dehydration, measurement, and/or gathering 
to the extent that the lessee is obligated to perform them at no cost to 
the Federal Government. Tax reimbursements are part of the gross 
proceeds accruing to a lessee even though the Federal royalty interest 
may be exempt from taxation. Monies and other consideration, including 
the forms of

[[Page 83]]

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 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.

[[Page 84]]

    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; 70 FR 11878, Mar. 
10, 2005]



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 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

[[Page 85]]

(c)(2) or (c)(3) of this section, and in accordance with the 
notification requirements of paragraph (e) of this section. When MMS 
determines that the value may be unreasonable, MMS will notify the 
lessee and give the lessee an opportunity to provide written information 
justifying the lessee's value.
    (iv) How to value over-delivered volumes under a cash-out program. 
This paragraph applies to situations where a pipeline purchases gas from 
a lessee according to a cash-out program under a transportation 
contract. For all over-delivered volumes, the royalty value is the price 
the pipeline is required to pay for volumes within the tolerances for 
over-delivery specified in the transportation contract. Use the same 
value for volumes that exceed the over-delivery tolerances even if those 
volumes are subject to a lower price under the transportation contract. 
However, if MMS determines that the price specified in the 
transportation contract for over-delivered volumes is unreasonably low, 
the lessee must value all over-delivered volumes under paragraph (c)(2) 
or (c)(3) of this section.
    (2) Notwithstanding the provisions of paragraph (b)(1) of this 
section, the value of gas sold pursuant to a warranty contract shall be 
determined by MMS, and due consideration will be given to all valuation 
criteria specified in this section. The lessee must request a value 
determination in accordance with paragraph (g) of this section for gas 
sold pursuant to a warranty contract; provided, however, that any value 
determination for a warranty contract in effect on the effective date of 
these regulations shall remain in effect until modified by MMS.
    (3) MMS may require a lessee to certify that its arm's-length 
contract provisions include all of the consideration to be paid by the 
buyer, either directly or indirectly, for the gas.
    (c) The value of gas subject to this section which is not sold 
pursuant to an arm's-length contract shall be the reasonable value 
determined in accordance with the first applicable of the following 
methods:
    (1) The gross proceeds accruing to the lessee pursuant to a sale 
under its non-arm's-length contract (or other disposition other than by 
an arm's-length contract), provided that those gross proceeds are 
equivalent to the gross proceeds derived from, or paid under, comparable 
arm's-length contracts for purchases, sales, or other dispositions of 
like-quality gas in the same field (or, if necessary to obtain a 
reasonable sample, from the same area). In evaluating the comparability 
of arm's-length contracts for the purposes of these regulations, the 
following factors shall be considered: price, time of execution, 
duration, market or markets served, terms, quality of gas, volume, and 
such other factors as may be appropriate to reflect the value of the 
gas;
    (2) A value determined by consideration of other information 
relevant in valuing like-quality gas, including gross proceeds under 
arm's-length contracts for like-quality gas in the same field or nearby 
fields or areas, posted prices for gas, prices received in arm's-length 
spot sales of gas, other reliable public sources of price or market 
information, and other information as to the particular lease operation 
or the saleability of the gas; or
    (3) A net-back method or any other reasonable method to determine 
value.
    (d)(1) Notwithstanding any other provisions of this section, except 
paragraph (h) of this section, if the maximum price permitted by Federal 
law at which gas may be sold is less than the value determined pursuant 
to this section, then MMS shall accept such maximum price as the value. 
For purposes of this section, price limitations set by any State or 
local government shall not be considered as a maximum price permitted by 
Federal law.
    (2) The limitation prescribed in paragraph (d)(1) of this section 
shall not apply to gas sold pursuant to a warranty contract and valued 
pursuant to paragraph (b)(2) of this section.
    (e)(1) Where the value is determined pursuant to paragraph (c) of 
this section, the lessee shall retain all data relevant to the 
determination of royalty value. Such data shall be subject to review and 
audit, and MMS will direct a lessee to use a different value if it 
determines that the reported value is inconsistent with the requirements 
of these regulations.

[[Page 86]]

    (2) Any Federal lessee will make available upon request to the 
authorized MMS or State representatives, to the Office of the Inspector 
General of the Department of the Interior, or other person authorized to 
receive such information, arm's-length sales and volume data for like-
quality production sold, purchased or otherwise obtained by the lessee 
from the field or area or from nearby fields or areas.
    (3) A lessee shall notify MMS if it has determined value pursuant to 
paragraph (c)(2) or (c)(3) of this section. The notification shall be by 
letter to the MMS Associate Director for Minerals Revenue Management or 
his/her designee. The letter shall identify the valuation method to be 
used and contain a brief description of the procedure to be followed. 
The notification required by this paragraph is a one-time notification 
due no later than the end of the month following the month the lessee 
first reports royalties on a Form MMS-2014 using a valuation method 
authorized by paragraph (c)(2) or (c)(3) of this section, and each time 
there is a change in a method under paragraph (c)(2) or (c)(3) of this 
section.
    (f) If MMS determines that a lessee has not properly determined 
value, the lessee shall pay the difference, if any, between royalty 
payments made based upon the value it has used and the royalty payments 
that are due based upon the value established by MMS. The lessee shall 
also pay interest on that difference computed pursuant to 30 CFR 218.54. 
If the lessee is entitled to a credit, MMS will provide instructions for 
the taking of that credit.
    (g) The lessee may request a value determination from MMS. In that 
event, the lessee shall propose to MMS a value determination method, and 
may use that method in determining value for royalty purposes until MMS 
issues its decision. The lessee shall submit all available data relevant 
to its proposal. The MMS shall expeditiously determine the value based 
upon the lessee's proposal and any additional information MMS deems 
necessary. In making a value determination MMS may use any of the 
valuation criteria authorized by this subpart. That determination shall 
remain effective for the period stated therein. After MMS issues its 
determination, the lessee shall make the adjustments in accordance with 
paragraph (f) of this section.
    (h) Notwithstanding any other provision of this section, under no 
circumstances shall the value of production for royalty purposes be less 
than the gross proceeds accruing to the lessee for lease production, 
less applicable allowances.
    (i) The lessee must place gas in marketable condition and market the 
gas for the mutual benefit of the lessee and the lessor at no cost to 
the Federal Government. Where the value established under this section 
is determined by a lessee's gross proceeds, that value will be increased 
to the extent that the gross proceeds have been reduced because the 
purchaser, or any other person, is providing certain services the cost 
of which ordinarily is the responsibility of the lessee to place the gas 
in marketable condition or to market the gas.
    (j) Value shall be based on the highest price a prudent lessee can 
receive through legally enforceable claims under its contract. If there 
is no contract revision or amendment, and the lessee fails to take 
proper or timely action to receive prices or benefits to which it is 
entitled, it must pay royalty at a value based upon that obtainable 
price or benefit. Contract revisions or amendments shall be in writing 
and signed by all parties to an arm's-length contract. If the lessee 
makes timely application for a price increase or benefit allowed under 
its contract but the purchaser refuses, and the lessee takes reasonable 
measures, which are documented, to force purchaser compliance, the 
lessee will owe no additional royalties unless or until monies or 
consideration resulting from the price increase or additional benefits 
are received. This paragraph shall not be construed to permit a lessee 
to avoid its royalty payment obligation in situations where a purchaser 
fails to pay, in whole or in part or timely, for a quantity of gas.
    (k) Notwithstanding any provision in these regulations to the 
contrary, no review, reconciliation, monitoring, or other like process 
that results in a redetermination by MMS of value under this section 
shall be considered final or

[[Page 87]]

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 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

[[Page 88]]

transportation contract. However, if MMS determines that the price 
specified in the transportation contract for over-delivered volumes is 
unreasonably low, the lessee must value all over-delivered volumes under 
paragraph (c)(2) or (c)(3) of this section.
    (2) Notwithstanding the provisions of paragraph (b)(1) of this 
section, the value of residue gas sold pursuant to a warranty contract 
shall be determined by MMS, and due consideration will be given to all 
valuation criteria specified in this section. The lessee must request a 
value determination in accordance with paragraph (g) of this section for 
gas sold pursuant to a warranty contract; provided, however, that any 
value determination for a warranty contract in effect on the effective 
date of these regulations shall remain in effect until modified by MMS.
    (3) MMS may require a lessee to certify that its arm's-length 
contract provisions include all of the consideration to be paid by the 
buyer, either directly or indirectly, for the residue gas or gas plant 
product.
    (c) The value of residue gas or any gas plant product which is not 
sold pursuant to an arm's-length contract shall be the reasonable value 
determined in accordance with the first applicable of the following 
methods:
    (1) The gross proceeds accruing to the lessee pursuant to a sale 
under its non-arm's-length contract (or other disposition other than by 
an arm's-length contract), provided that those gross proceeds are 
equivalent to the gross proceeds derived from, or paid under, comparable 
arm's-length contracts for purchases, sales, or other dispositions of 
like quality residue gas or gas plant products from the same processing 
plant (or, if necessary to obtain a reasonable sample, from nearby 
plants). In evaluating the comparability of arm's-length contracts for 
the purposes of these regulations, the following factors shall be 
considered: price, time of execution, duration, market or markets 
served, terms, quality of residue gas or gas plant products, volume, and 
such other factors as may be appropriate to reflect the value of the 
residue gas or gas plant products;
    (2) A value determined by consideration of other information 
relevant in valuing like-quality residue gas or gas plant products, 
including gross proceeds under arm's-length contracts for like-quality 
residue gas or gas plant products from the same gas plant or other 
nearby processing plants, posted prices for residue gas or gas plant 
products, prices received in spot sales of residue gas or gas plant 
products, other reliable public sources of price or market information, 
and other information as to the particular lease operation or the 
saleability of such residue gas or gas plant products; or
    (3) A net-back method or any other reasonable method to determine 
value.
    (d)(1) Notwithstanding any other provisions of this section, except 
paragraph (h) of this section, if the maximum price permitted by Federal 
law at which any residue gas or gas plant products may be sold is less 
than the value determined pursuant to this section, then MMS shall 
accept such maximum price as the value. For the purposes of this 
section, price limitations set by any State or local government shall 
not be considered as a maximum price permitted by Federal law.
    (2) The limitation prescribed by paragraph (d)(1) of this section 
shall not apply to residue gas sold pursuant to a warranty contract and 
valued pursuant to paragraph (b)(2) of this section.
    (e)(1) Where the value is determined pursuant to paragraph (c) of 
this section, the lessee shall retain all data relevant to the 
determination of royalty value. Such data shall be subject to review and 
audit, and MMS will direct a lessee to use a different value if it 
determines upon review or audit that the reported value is inconsistent 
with the requirements of these regulations.
    (2) Any Federal lessee will make available upon request to the 
authorized MMS or State representatives, to the Office of the Inspector 
General of the Department of the Interior, or other persons authorized 
to receive such information, arm's-length sales and volume data for 
like-quality residue gas and gas plant products sold, purchased or 
otherwise obtained by the lessee from the same processing plant or from 
nearby processing plants.
    (3) A lessee shall notify MMS if it has determined any value 
pursuant to paragraph (c)(2) or (c)(3) of this section.

[[Page 89]]

The notification shall be by letter to the MMS Associate Director for 
Minerals Revenue Management or his/her designee. The letter shall 
identify the valuation method to be used and contain a brief description 
of the procedure to be followed. The notification required by this 
paragraph is a one-time notification due no later than the end of the 
month following the month the lessee first reports royalties on a Form 
MMS-2014 using a valuation method authorized by paragraph (c)(2) or 
(c)(3) of this section, and each time there is a change in a method 
under paragraph (c)(2) or (c)(3) of this section.
    (f) If MMS determines that a lessee has not properly determined 
value, the lessee shall pay the difference, if any, between royalty 
payments made based upon the value it has used and the royalty payments 
that are due based upon the value established by MMS. The lessee shall 
also pay interest computed on that difference pursuant to 30 CFR 218.54. 
If the lessee is entitled to a credit, MMS will provide instructions for 
the taking of that credit.
    (g) The lessee may request a value determination from MMS. In that 
event, the lessee shall propose to MMS a value determination method, and 
may use that method in determining value for royalty purposes until MMS 
issues its decision. The lessee shall submit all available data relevant 
to its proposal. The MMS shall expeditiously determine the value based 
upon the lessee's proposal and any additional information MMS deems 
necessary. In making a value determination, MMS may use any of the 
valuation criteria authorized by this subpart. That determination shall 
remain effective for the period stated therein. After MMS issues its 
determination, the lessee shall make the adjustments in accordance with 
paragraph (f) of this section.
    (h) Notwithstanding any other provision of this section, under no 
circumstances shall the value of production for royalty purposes be less 
than the gross proceeds accruing to the lessee for residue gas and/or 
any gas plant products, less applicable transportation allowances and 
processing allowances determined pursuant to this subpart.
    (i) The lessee must place residue gas and gas plant products in 
marketable condition and market the residue gas and gas plant products 
for the mutual benefit of the lessee and the lessor at no cost to the 
Federal Government. Where the value established under this section is 
determined by a lessee's gross proceeds, that value will be increased to 
the extent that the gross proceeds have been reduced because the 
purchaser, or any other person, is providing certain services the cost 
of which ordinarily is the responsibility of the lessee to place the 
residue gas or gas plant products in marketable condition or to market 
the residue gas and gas plant products.
    (j) Value shall be based on the highest price a prudent lessee can 
receive through legally enforceable claims under its contract. Absent 
contract revision or amendment, if the lessee fails to take proper or 
timely action to receive prices or benefits to which it is entitled it 
must pay royalty at a value based upon that obtainable price or benefit. 
Contract revisions or amendments shall be in writing and signed by all 
parties to an arm's-length contract. If the lessee makes timely 
application for a price increase or benefit allowed under its contract 
but the purchaser refuses, and the lessee takes reasonable measures, 
which are documented, to force purchaser compliance, the lessee will owe 
no additional royalties unless or until monies or consideration 
resulting from the price increase or additional benefits are received. 
This paragraph shall not be construed to permit a lessee to avoid its 
royalty payment obligation in situations where a purchaser fails to pay, 
in whole or in part, or timely, for a quantity of residue gas or gas 
plant product.
    (k) Notwithstanding any provision in these regulations to the 
contrary, no review, reconciliation, monitoring, or other like process 
that results in a redetermination by MMS of value under this section 
shall be considered final or binding against the Federal Government or 
its beneficiaries until the audit period is formally closed.
    (l) Certain information submitted to MMS to support valuation 
proposals, including transportation allowances, processing allowances or 
extraordinary

[[Page 90]]

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 
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

[[Page 91]]

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 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

[[Page 92]]

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 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

[[Page 93]]

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 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.

[[Page 94]]

    (B) The MMS shall allow as a cost an amount equal to the allowable 
initial capital investment in the transportation system multiplied by 
the rate of return determined pursuant to paragraph (b)(2)(v) of this 
section. No allowance shall be provided for depreciation. This 
alternative shall apply only to transportation facilities first placed 
in service after March 1, 1988.
    (v) The rate of return must be 1.3 times the industrial rate 
associated with Standard & Poor's BBB rating. The BBB rate must be the 
monthly average rate as published in Standard & Poor's Bond Guide for 
the first month for which the allowance is applicable. The rate must be 
redetermined at the beginning of each subsequent calendar year.
    (3)(i) The deduction for transportation costs shall be determined on 
the basis of the lessee's cost of transporting each product through each 
individual transportation system. Where more than one product in a 
gaseous phase is transported, the allocation of costs to each of the 
products transported shall be made in a consistent and equitable manner 
in the same proportion as the ratio of the volume of each product 
(excluding waste products which have no value) to the volume of all 
products in the gaseous phase (excluding waste products which have no 
value). Except as provided in this paragraph, the lessee may not take an 
allowance for transporting a product which is not royalty bearing 
without MMS approval.
    (ii) Notwithstanding the requirements of paragraph (b)(3)(i), the 
lessee may propose to the MMS a cost allocation method on the basis of 
the values of the products transported. MMS shall approve the method 
unless it determines that it is not consistent with the purposes of the 
regulations in this part.
    (4) Where both gaseous and liquid products are transported through 
the same transportation system, the lessee shall propose a cost 
allocation procedure to MMS. The lessee may use the transportation 
allowance determined in accordance with its proposed allocation 
procedure until MMS issues its determination on the acceptability of the 
cost allocation. The lessee shall submit all relevant data to support 
its proposal. MMS shall then determine the transportation allowance 
based upon the lessee's proposal and any additional information MMS 
deems necessary. The lessee must submit the allocation proposal within 3 
months of claiming the allocated deduction on the Form MMS-2014.
    (5) You may apply for an exception from the requirement to compute 
actual costs under paragraphs (b)(1) through (b)(4) of this section.
    (i) The MMS will grant the exception if:
    (A) The transportation system has a tariff filed with the Federal 
Energy Regulatory Commission (FERC) or a state regulatory agency, that 
FERC or the state regulatory agency has permitted to become effective, 
and
    (B) Third parties are paying prices, including discounted prices, 
under the tariff to transport gas on the system under arm's-length 
transportation contracts.
    (ii) If MMS approves the exception, you must calculate your 
transportation allowance for each production month based on the lesser 
of the volume-weighted average of the rates paid by the third parties 
under arm's-length transportation contracts during that production month 
or the non-arm's-length payment by the lessee to the pipeline.
    (iii) If during any production month there are no prices paid under 
the tariff by third parties to transport gas on the system under arm's-
length transportation contracts, you may use the volume-weighted average 
of the rates paid by third parties under arm's-length transportation 
contracts in the most recent preceding production month in which the 
tariff remains in effect and third parties paid such rates, for up to 
five successive production months. You must use the non-arm's-length 
payment by the lessee to the pipeline if it is less than the volume-
weighted average of the rates paid by third parties under arm's-length 
contracts.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) You must 
use a separate entry on Form MMS-2014 to notify MMS of a transportation 
allowance.

[[Page 95]]

    (ii) The MMS may require you to submit arm's-length transportation 
contracts, production agreements, operating agreements, and related 
documents. Recordkeeping requirements are found at part 207 of this 
chapter.
    (iii) You may not use a transportation allowance that was in effect 
before March 1, 1988. You must use the provisions of this subpart to 
determine your transportation allowance.
    (2) Non-arm's-length or no contract. (i) You must use a separate 
entry on Form MMS-2014 to notify MMS of a transportation allowance.
    (ii) For new transportation facilities or arrangements, base your 
initial deduction on estimates of allowable gas transportation costs for 
the applicable period. Use the most recently available operations data 
for the transportation system or, if such data are not available, use 
estimates based on data for similar transportation systems. Paragraph 
(e) of this section will apply when you amend your report based on your 
actual costs.
    (iii) The MMS may require you to submit all data used to calculate 
the allowance deduction. Recordkeeping requirements are found at part 
207 of this chapter.
    (iv) If you are authorized under paragraph (b)(5) of this section to 
use an exception to the requirement to calculate your actual 
transportation costs, you must follow the reporting requirements of 
paragraph (c)(1) of this section.
    (v) You may not use a transportation allowance that was in effect 
before March 1, 1988. You must use the provisions of this subpart to 
determine your transportation allowance.
    (d) Interest and assessments. (1) If a lessee 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. You 
may include, but are not limited to (subject to the requirements of 
paragraph (g) of this section), the following costs in determining the 
arm's-length transportation allowance under paragraph (a) of this 
section or the non-arm's-length transportation allowance under paragraph 
(b) of this section. You may not

[[Page 96]]

use any cost as a deduction that duplicates all or part of any other 
cost that you use under this paragraph.
    (1) Firm demand charges paid to pipelines. You may deduct firm 
demand charges or capacity reservation fees paid to a pipeline, 
including charges or fees for unused firm capacity that you have not 
sold before you report your allowance. If you receive a payment from any 
party for release or sale of firm capacity after reporting a 
transportation allowance that included the cost of that unused firm 
capacity, or if you receive a payment or credit from the pipeline for 
penalty refunds, rate case refunds, or other reasons, you must reduce 
the firm demand charge claimed on the Form MMS-2014 by the amount of 
that payment. You must modify the Form MMS-2014 by the amount received 
or credited for the affected reporting period, and pay any resulting 
royalty and late payment interest due;
    (2) Gas supply realignment (GSR) costs. The GSR costs result from a 
pipeline reforming or terminating supply contracts with producers to 
implement the restructuring requirements of FERC Orders in 18 CFR part 
284;
    (3) Commodity charges. The commodity charge allows the pipeline to 
recover the costs of providing service;
    (4) Wheeling costs. Hub operators charge a wheeling cost for 
transporting gas from one pipeline to either the same or another 
pipeline through a market center or hub. A hub is a connected manifold 
of pipelines through which a series of incoming pipelines are 
interconnected to a series of outgoing pipelines;
    (5) Gas Research Institute (GRI) fees. The GRI conducts research, 
development, and commercialization programs on natural gas related 
topics for the benefit of the U.S. gas industry and gas customers. GRI 
fees are allowable provided such fees are mandatory in FERC-approved 
tariffs;
    (6) Annual Charge Adjustment (ACA) fees. FERC charges these fees to 
pipelines to pay for its operating expenses;
    (7) Payments (either volumetric or in value) for actual or 
theoretical losses. However, theoretical losses are not deductible in 
non-arm's-length transportation arrangements unless the transportation 
allowance is based on arm's-length transportation rates charged under a 
FERC- or state regulatory-approved tariff under paragraph (b)(5) of this 
section. If you receive volumes or credit for line gain, you must reduce 
your transportation allowance accordingly and pay any resulting 
royalties and late payment interest due;
    (8) Temporary storage services. This includes short duration storage 
services offered by market centers or hubs (commonly referred to as 
``parking'' or ``banking''), or other temporary storage services 
provided by pipeline transporters, whether actual or provided as a 
matter of accounting. Temporary storage is limited to 30 days or less; 
and
    (9) Supplemental costs for compression, dehydration, and treatment 
of gas. MMS allows these costs only if such services are required for 
transportation and exceed the services necessary to place production 
into marketable condition required under Sec. Sec. 206.152(i) and 
206.153(i) of this part.
    (10) Costs of surety. You may deduct the costs of securing a letter 
of credit, or other surety, that the pipeline requires you as a shipper 
to maintain under an arm's-length transportation contract.
    (g) Nonallowable costs in determining transportation allowances. 
Lessees may not include the following costs in determining the arm's-
length transportation allowance under paragraph (a) of this section or 
the non-arm's-length transportation allowance under paragraph (b) of 
this section:
    (1) Fees or costs incurred for storage. This includes storing 
production in a storage facility, whether on or off the lease, for more 
than 30 days;
    (2) Aggregator/marketer fees. This includes fees you pay to another 
person (including your affiliates) to market your gas, including 
purchasing and reselling the gas, or finding or maintaining a market for 
the gas production;
    (3) Penalties you incur as shipper. These penalties include, but are 
not limited to:
    (i) Over-delivery cash-out penalties. This includes the difference 
between the price the pipeline pays you for over-delivered volumes 
outside the tolerances and the price you receive for

[[Page 97]]

over-delivered volumes within the tolerances;
    (ii) Scheduling penalties. This includes penalties you incur for 
differences between daily volumes delivered into the pipeline and 
volumes scheduled or nominated at a receipt or delivery point;
    (iii) Imbalance penalties. This includes penalties you incur 
(generally on a monthly basis) for differences between volumes delivered 
into the pipeline and volumes scheduled or nominated at a receipt or 
delivery point; and
    (iv) Operational penalties. This includes fees you incur for 
violation of the pipeline's curtailment or operational orders issued to 
protect the operational integrity of the pipeline;
    (4) Intra-hub transfer fees. These are fees you pay to hub operators 
for administrative services (e.g., title transfer tracking) necessary to 
account for the sale of gas within a hub;
    (5) Fees paid to brokers. This includes fees paid to parties who 
arrange marketing or transportation, if such fees are separately 
identified from aggregator/marketer fees;
    (6) Fees paid to scheduling service providers. This includes fees 
paid to parties who provide scheduling services, if such fees are 
separately identified from aggregator/marketer fees;
    (7) Internal costs. This includes salaries and related costs, rent/
space costs, office equipment costs, legal fees, and other costs to 
schedule, nominate, and account for sale or movement of production; and
    (8) Other nonallowable costs. Any cost you incur for services you 
are required to provide at no cost to the lessor.
    (h) Other transportation cost determinations. Use this section when 
calculating transportation costs to establish value using a netback 
procedure or any other procedure that requires deduction of 
transportation costs.

[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45762, Nov. 14, 1988; 61 
FR 5465, Feb. 12, 1996; 62 FR 65762, Dec. 16, 1997; 70 FR 11878, Mar. 
10, 2005]



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

[[Page 98]]

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 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

[[Page 99]]

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.
    (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

[[Page 100]]

rate must be redetermined at the beginning of each subsequent calendar 
year.
    (3) The processing allowance for each gas plant product shall be 
determined based on the lessee's reasonable and actual cost of 
processing the gas. Allocation of costs to each gas plant product shall 
be based upon generally accepted accounting principles. The lessee may 
not take an allowance for the costs of processing lease production which 
is not royalty bearing.
    (4) A lessee may apply to MMS for an exception from the requirement 
that it compute actual costs in accordance with paragraphs (b)(1) 
through (b)(3) of this section. The MMS may grant the exception only if: 
(i) The lessee has arm's-length contracts for processing other gas 
production at the same processing plant; and (ii) at least 50 percent of 
the gas processed annually at the plant is processed pursuant to arm's-
length processing contracts; if the MMS grants the exception, the lessee 
shall use as its processing allowance the volume weighted average prices 
charged other persons pursuant to arm's-length contracts for processing 
at the same plant.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) The 
lessee must notify MMS of an allowance based on incurred costs by using 
a separate 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.

[[Page 101]]

    (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 formula shall be specified in the notice of sale and 
in the lease agreement.

[61 FR 3804, Feb. 2, 1996]



                          Subpart E_Indian Gas

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



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,

[[Page 102]]

economic, or legal characteristics. An area may be all lands within the 
boundaries of an Indian reservation.
    Arm's-length contract means a contract or agreement that has been 
arrived at in the marketplace between independent, nonaffiliated persons 
with opposing economic interests regarding that contract. For purposes 
of this subpart, two persons are affiliated if one person controls, is 
controlled by, or is under common control with another person. The 
following percentages (based on the instruments of ownership of the 
voting securities of an entity, or based on other forms of ownership) 
determine if persons are affiliated:
    (1) Ownership in excess of 50 percent constitutes control.
    (2) Ownership of 10 through 50 percent creates a presumption of 
control.
    (3) Ownership of less than 10 percent creates a presumption of 
noncontrol which MMS may rebut if it demonstrates actual or legal 
control, including the existence of interlocking directorates. 
Notwithstanding any other provisions of this subpart, contracts between 
relatives, either by blood or by marriage, are not arm's-length 
contracts. MMS may require the lessee to certify the percentage of 
ownership or control of the entity. To be considered arm's-length for 
any production month, a contract must meet the requirements of this 
definition for that production month as well as when the contract was 
executed.
    Audit means a review, conducted under generally accepted accounting 
and auditing standards, of royalty payment compliance activities of 
lessees or other persons who pay royalties, rents, or bonuses on Indian 
leases.
    BIA means the Bureau of Indian Affairs of the Department of the 
Interior.
    BLM means the Bureau of Land Management of the Department of the 
Interior.
    Compression means raising the pressure of gas.
    Condensate means liquid hydrocarbons (normally exceeding 40 degrees 
of API gravity) recovered at the surface without resorting to 
processing. Condensate is the mixture of liquid hydrocarbons that 
results from condensation of petroleum hydrocarbons existing initially 
in a gaseous phase in an underground reservoir.
    Contract means any oral or written agreement, including amendments 
or revisions thereto, between two or more persons and enforceable by law 
that with due consideration creates an obligation.
    Dedicated means a contractual commitment to deliver gas production 
(or a specified portion of production) from a lease or well when that 
production is specified in a sales contract and that production must be 
sold pursuant to that contract to the extent that production occurs from 
that lease or well.
    Drip condensate means any condensate recovered downstream of the 
facility measurement point without resorting to processing. Drip 
condensate includes condensate recovered as a result of its becoming a 
liquid during the transportation of the gas removed from the lease or 
recovered at the inlet of a gas processing plant by mechanical means, 
often referred to as scrubber condensate.
    Dual Accounting (or accounting for comparison) refers to the 
requirement to pay royalty based on a value which is the higher of the 
value of gas prior to processing less any applicable allowances as 
compared to the combined value of drip condensate, residue gas, and gas 
plant products after processing, less applicable allowances.
    Entitlement (or entitled share) means the gas production from a 
lease, or allocable to lease acreage under the terms of an AFA, 
multiplied by the operating rights owner's percentage of interest 
ownership in the lease or the acreage.
    Facility measurement point (or point of royalty settlement) means 
the point where the BLM-approved measurement device is located for 
determining the volume of gas removed from the lease. The facility 
measurement point may be on the lease or off-lease with BLM approval.
    Field means a geographic region situated over one or more subsurface 
oil and gas reservoirs encompassing at least the outermost boundaries of 
all oil and gas accumulations known to be within those reservoirs 
vertically projected to the land surface. Onshore fields are usually 
given names and

[[Page 103]]

their official boundaries are often designated by oil and gas regulatory 
agencies in the respective States in which the fields are located.
    Gas means any fluid, either combustible or noncombustible, 
hydrocarbon or nonhydrocarbon, which is extracted from a reservoir and 
which has neither independent shape nor volume, but tends to expand 
indefinitely. It is a substance that exists in a gaseous or rarefied 
state under standard temperature and pressure conditions.
    Gas plant products means separate marketable elements, compounds, or 
mixtures, whether in liquid, gaseous, or solid form, resulting from 
processing gas. However, it does not include residue gas.
    Gathering means the movement of lease production to a central 
accumulation or treatment point on the lease, unit, or communitized 
area; or a central accumulation or treatment point off the lease, unit, 
or communitized area as approved by BLM operations personnel.
    Gross proceeds (for royalty payment purposes) means the total monies 
and other consideration accruing to an oil and gas lessee for the 
disposition of unprocessed gas, residue gas, and gas plant products 
produced. Gross proceeds includes, but is not limited to, payments to 
the lessee for certain services such as compression, dehydration, 
measurement, or field gathering to the extent that the lessee is 
obligated to perform them at no cost to the Indian lessor, and payments 
for gas processing rights. Gross proceeds, as applied to gas, also 
includes but is not limited to reimbursements for severance taxes and 
other reimbursements. Tax reimbursements are part of the gross proceeds 
accruing to a lessee even though the Indian royalty interest is exempt 
from taxation. Monies and other consideration, including the forms of 
consideration identified in this paragraph, to which a lessee is 
contractually or legally entitled but which it does not seek to collect 
through reasonable efforts are also part of gross proceeds.
    Index means the calculated composite price ($/MMBtu) of spot-market 
sales published by a publication that meets MMS-established criteria for 
acceptability at the index-pricing point.
    Index-pricing point (IPP) means any point on a pipeline for which 
there is an index.
    Index zone means a field or an area with an active spot market and 
published indices applicable to that field or area that are acceptable 
to MMS under 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,

[[Page 104]]

tribal auditors acting under agreements under the Federal Oil and Gas 
Royalty Management Act of 1982, 30 U.S.C. 1701 et seq. or other 
applicable agreements.
    Minimum royalty means that minimum amount of annual royalty that the 
lessee must pay as specified in the lease or in applicable leasing 
regulations.
    Natural gas liquids (NGL's) means those gas plant products 
consisting of ethane, propane, butane, or heavier liquid hydrocarbons.
    Net-back method (or work-back method) means a method for calculating 
market value of gas at the lease under which costs of transportation, 
processing, and manufacturing are deducted from the proceeds received 
for, or the value of, the gas, residue gas, or gas plant products, and 
any extracted, processed, or manufactured products, at the first point 
at which reasonable values for any such products may be determined by a 
sale under an arm's-length contract or comparison to other sales of such 
products.
    Net output means the quantity of residue gas and each gas plant 
product that a processing plant produces.
    Net profit share means the specified share of the net profit from 
production of oil and gas as provided in the agreement.
    Operating rights owner (or working interest owner) means any person 
who owns operating rights in a lease subject to this subpart. A record 
title owner is the owner of operating rights under a lease except to the 
extent that the operating rights or a portion thereof have been 
transferred from record title (see BLM regulations at 43 CFR 3100.0-
5(d)).
    Person means any individual, firm, corporation, association, 
partnership, consortium, or joint venture (when established as a 
separate entity).
    Point of royalty measurement means the same as facility measurement 
point.
    Processing means any process designed to remove elements or 
compounds (hydrocarbon and nonhydrocarbon) from gas, including 
absorption, adsorption, or refrigeration. Field processes which normally 
take place on or near the lease, such as natural pressure reduction, 
mechanical separation, heating, cooling, dehydration, desulphurization 
(or ``sweetening''), and compression, are not considered processing. The 
changing of pressures and/or temperatures in a reservoir is not 
considered processing.
    Residue gas means that hydrocarbon gas consisting principally of 
methane resulting from processing gas.
    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

[[Page 105]]

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 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

[[Page 106]]

    (v) Easy identification in MMS's systems, such as counties or Indian 
reservations.
    (3) If market conditions change so that an index-based method for 
determining value is no longer appropriate for an index zone, MMS will 
hold a technical conference to consider disqualification of an index 
zone. MMS will publish notice in the Federal Register if an index zone 
is disqualified. If an index zone is disqualified, then production from 
leases in that index zone cannot be valued under this paragraph.
    (4) MMS periodically will publish in the Federal Register a list of 
acceptable publications based on certain criteria, including, but not 
limited to the following five criteria:
    (i) Publications buyers and sellers frequently use;
    (ii) Publications frequently referenced in purchase or sales 
contracts;
    (iii) Publications that use adequate survey techniques, including 
the gathering of information from a substantial number of sales;
    (iv) Publications that publish the range of reported prices they use 
to calculate their index; and
    (v) Publications independent from DOI, lessors, and lessees.
    (5) Any publication may petition MMS to be added to the list of 
acceptable publications.
    (6) MMS may exclude an individual index price for an index zone in 
an MMS-approved publication if MMS determines that the index price does 
not accurately reflect the value of production in that index zone. MMS 
will publish a list of excluded indices in the Federal Register.
    (7) MMS will reference which tables in the publications you must use 
for determining the associated index prices.
    (8) The index-based values determined under this paragraph are not 
subject to deductions for transportation or processing allowances 
determined under Sec. Sec. 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-

[[Page 107]]

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 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.

[[Page 108]]

    (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 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

[[Page 109]]

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.
    (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

[[Page 110]]

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 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:

[[Page 111]]

    (1) The gross proceeds accruing to you under your non-arm's-length 
contract sale (or other disposition other than by an arm's-length 
contract), provided that those gross proceeds are equivalent to the 
gross proceeds derived from, or paid under, comparable arm's-length 
contracts for purchases, sales, or other dispositions of like-quality 
gas in the same field (or, if necessary to obtain a reasonable sample, 
from the same area). For residue gas or gas plant products, the 
comparable arm's-length contracts must be for gas from the same 
processing plant (or, if necessary to obtain a reasonable sample, from 
nearby plants). In evaluating the comparability of arm's-length 
contracts for the purposes of these regulations, the following factors 
will be considered: price, time of execution, duration, market or 
markets served, terms, quality of gas, residue gas, or gas plant 
products, volume, and such other factors as may be appropriate to 
reflect the value of the gas, residue gas, or gas plant products.
    (2) A value determined by consideration of other information 
relevant in valuing like-quality gas, residue gas, or gas plant 
products, including gross proceeds under arm's-length contracts for 
like-quality gas in the same field or nearby fields or areas, or for 
residue gas or gas plant products from the same gas plant or other 
nearby processing plants. Other factors to consider include prices 
received in spot sales of gas, residue gas or gas plant products, other 
reliable public sources of price or market information, and other 
information as to the particular lease operation or the salability of 
such gas, residue gas, or gas plant products.
    (3) A net-back method or any other reasonable method to determine 
value.
    (d) Supporting data. If you determine the value of production under 
paragraph (c) of this section, you must retain all data relevant to the 
determination of royalty value.
    (1) Such data will be subject to review and audit, and MMS will 
direct you to use a different value if we determine upon review or audit 
that the value you reported is inconsistent with the requirements of 
these regulations.
    (2) You must make all such data available upon request to the 
authorized MMS or Indian representatives, to the Office of the Inspector 
General of the Department, or other authorized persons. This includes 
your arm's-length sales and volume data for like-quality gas, residue 
gas, and gas plant products that are sold, purchased, or otherwise 
obtained from the same processing plant or from nearby processing 
plants, or from the same or nearby field or area.
    (e) Improper values. If MMS determines that you have not properly 
determined value, you must pay the difference, if any, between royalty 
payments made based upon the value you used and the royalty payments 
that are due based upon the value MMS established. You also must pay 
interest computed on that difference under 30 CFR 218.54. If you are 
entitled to a credit, MMS will provide instructions on how to take that 
credit.
    (f) Value guidance. You may ask MMS for guidance in determining 
value. You may propose a valuation method to MMS. Submit all available 
data related to your proposal and any additional information MMS deems 
necessary. MMS will promptly review your proposal and provide you with a 
non-binding determination of the guidance you request.
    (g) Minimum value of production. (1) For gas, residue gas, and gas 
plant products valued under this section, under no circumstances may the 
value of production for royalty purposes be less than the gross proceeds 
accruing to the lessee (including its affiliates) for gas, residue gas 
and/or any gas plant products, less applicable transportation allowances 
and processing allowances determined under this subpart.
    (2) For gas plant products valued under this section and not valued 
under 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.

[[Page 112]]

    (B) For production in Arizona, in Colorado outside the San Juan 
Basin, Minnesota, Montana, North Dakota, Oklahoma, South Dakota, Utah, 
and Wyoming, the monthly average minimum price reported in commercial 
price bulletins for the gas plant product at Conway, Kansas, minus 7.0 
cents per gallon;
    (ii) You may use any commercial price bulletin, but you must use the 
same bulletin for all of the calendar year. If the commercial price 
bulletin you are using stops publication, you may use a different 
commercial price bulletin for the remaining part of the calendar year; 
and (iii) If you use a commercial price bulletin that is published 
monthly, the monthly average minimum price is the bulletin's minimum 
price. If you use a commercial price bulletin that is published weekly, 
the monthly average minimum price is the arithmetic average of the 
bulletin's weekly minimum prices. If you use a commercial price bulletin 
that is published daily, the monthly average minimum price is the 
arithmetic average of the bulletin's minimum prices for each Wednesday 
in the month.
    (h) Marketable condition/Marketing. You are required to place gas, 
residue gas, and gas plant products in marketable condition and market 
the gas for the mutual benefit of the lessee and the lessor at no cost 
to the Indian lessor. When your gross proceeds establish the value under 
this section, that value must be increased to the extent that the gross 
proceeds have been reduced because the purchaser, or any other person, 
is providing certain services to place the gas, residue gas, or gas 
plant products in marketable condition or to market the gas, the cost of 
which ordinarily is your responsibility.
    (i) Highest obtainable price or benefit. For gas, residue gas, and 
gas plant products valued under this section, value must be based on the 
highest price a prudent lessee can receive through legally enforceable 
claims under its contract. Absent contract revision or amendment, if you 
fail to take proper or timely action to receive prices or benefits to 
which you are entitled, you must pay royalty at a value based upon that 
obtainable price or benefit. Contract revisions or amendments must be in 
writing and signed by all parties to an arm's-length contract. If you 
make timely application for a price increase or benefit allowed under 
your contract but the purchaser refuses, and you take reasonable 
measures, which are documented, to force purchaser compliance, you will 
owe no additional royalties unless or until monies or consideration 
resulting from the price increase or additional benefits are received. 
This paragraph is not intended to permit you to avoid your royalty 
payment obligation in situations where your purchaser fails to pay, in 
whole or in part, or timely, for a quantity of gas, residue gas, or gas 
plant product.
    (j) Non-binding MMS reviews. Notwithstanding any provision in these 
regulations to the contrary, no review, reconciliation, monitoring, or 
other like process that results in an MMS redetermination of value under 
this section will be considered final or binding against the Federal 
Government or its beneficiaries until the audit period is formally 
closed.
    (k) Confidential information. Certain information submitted to MMS 
to support valuation proposals, including transportation allowances and 
processing allowances, may be exempted from disclosure under the Freedom 
of Information Act, 5 U.S.C. 552, or other Federal law. Any data 
specified by law to be privileged, confidential, or otherwise exempt, 
will be maintained in a confidential manner in accordance with 
applicable laws and regulations. All requests for information about 
determinations made under this subpart must be submitted in accordance 
with the Freedom of Information Act regulation of the Department of the 
Interior, 43 CFR part 2.

[64 FR 43515, Aug. 10, 1999, as amended at 65 FR 62614, Oct. 19, 2000]



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

[[Page 113]]

of the plant even though residue gas and/or gas plant products may be in 
temporary storage.
    (c) If you have no ownership interest in the processing plant and 
you do not operate the plant, you may use the contract volume allocation 
to determine your share of plant products.
    (d) If you have an ownership interest in the plant or if you operate 
it, use the following procedure to determine the quantity of the residue 
gas and gas plant products attributable to you for royalty payment 
purposes:
    (1) When the net output of the processing plant is derived from gas 
obtained from only one lease, the quantity of the residue gas and gas 
plant products on which you must pay royalty is the net output of the 
plant.
    (2) When the net output of a processing plant is derived from gas 
obtained from more than one lease producing gas of uniform content, the 
quantity of the residue gas and gas plant products allocable to each 
lease must be in the same proportions as the ratios obtained by dividing 
the amount of gas delivered to the plant from each lease by the total 
amount of gas delivered from all leases.
    (3) When the net output of a processing plant is derived from gas 
obtained from more than one lease producing gas of non-uniform content, 
the volumes of residue gas and gas plant products allocable to each 
lease are based on theoretical volumes of residue gas and gas plant 
products measured in the lease gas stream. You must calculate the 
portion of net plant output of residue gas and gas plant products 
attributable to each lease as follows:
    (i) First, compute the theoretical volumes of residue gas and of gas 
plant products attributable to the lease by multiplying the lease volume 
of the gas stream by the tested residue gas content (mole percentage) or 
gas plant product (GPM) content of the gas stream;
    (ii) Second, calculate the theoretical volumes of residue gas and of 
gas plant products delivered from all leases by summing the theoretical 
volumes of residue gas and of gas plant products delivered from each 
lease; and
    (iii) Third, calculate the theoretical quantities of net plant 
output of residue gas and of gas plant products attributable to each 
lease by multiplying the net plant output of residue gas, or gas plant 
products, by the ratio in which the theoretical volumes of residue gas, 
or gas plant products, is the numerator and the theoretical volume of 
residue gas, or gas plant products, delivered from all leases is the 
denominator.
    (4) You may request MMS approval of other methods for determining 
the quantity of residue gas and gas plant products allocable to each 
lease. If MMS approves a different method, it will be applicable to all 
gas production from your Indian leases that is processed in the same 
plant.
    (e) You may not take any deductions from the royalty volume or 
royalty value for actual or theoretical losses. Any actual loss of 
unprocessed gas incurred prior to the facility measurement point will 
not be subject to royalty if BLM determines that the loss was 
unavoidable.



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

[[Page 114]]

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 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)

[[Page 115]]

within 2 months of the date MMS receives your report which claims the 
allowance on the Form MMS-2014.
    (ii) When either MMS or a tribe conducts reviews and audits, they 
will examine whether or not the contract reflects more than the 
consideration actually transferred either directly or indirectly from 
you to the transporter of the transportation. If the contract reflects 
more than the total consideration, then MMS may require that the 
transportation allowance be determined under paragraph (b) of this 
section.
    (iii) If MMS determines that the consideration paid under an arm's-
length transportation contract does not reflect the value of the 
transportation because of misconduct by or between the contracting 
parties, or because you otherwise have breached your duty to the lessor 
to market the production for the mutual benefit of you and the lessor, 
then MMS will require that the transportation allowance be determined 
under paragraph (b) of this section. In these circumstances, MMS will 
notify you and give you an opportunity to provide written information 
justifying your transportation costs.
    (2) This paragraph explains how to allocate the costs to each 
product if your arm's-length transportation contract includes more than 
one product in a gaseous phase and the transportation costs attributable 
to each product cannot be determined from the contract.
    (i) If your arm's-length transportation contract includes more than 
one product in a gaseous phase and the transportation costs attributable 
to each product cannot be determined from the contract, the total 
transportation costs must be allocated in a consistent and equitable 
manner to each of the products transported. To make this allocation, use 
the same proportion as the ratio that the volume of each product 
(excluding waste products which have no value) bears to the volume of 
all products in the gaseous phase (excluding waste products which have 
no value). Except as provided in this paragraph, you cannot take an 
allowance for the costs of transporting lease production that is not 
royalty bearing without MMS approval, or without lessor approval on 
tribal leases.
    (ii) As an alternative to paragraph (a)(2)(i) of this section, you 
may propose to MMS a cost allocation method based on the values of the 
products transported. MMS will approve the method if we determine that 
it meets one of the two following requirements:
    (A) The methodology in paragraph (a)(2)(i) of this section cannot be 
applied; and
    (B) Your proposal is more reasonable than the methodology in 
paragraph (a)(2)(i) of this section.
    (3) This paragraph explains how to allocate costs to each product if 
your arm's-length transportation contract includes both gaseous and 
liquid products and the transportation costs attributable to each cannot 
be determined from the contract.
    (i) If your arm's-length transportation contract includes both 
gaseous and liquid products and the transportation costs attributable to 
each cannot be determined from the contract, you must propose an 
allocation procedure to MMS. You may use the transportation allowance 
determined in accordance with your proposed allocation procedure until 
MMS decides whether to accept your cost allocation.
    (ii) You are required to submit all relevant data to support your 
allocation proposal. MMS will then determine the gas transportation 
allowance based upon your proposal and any additional information MMS 
deems necessary.
    (4) If your payments for transportation under an arm's-length 
contract are not based on a dollar per unit price, you must convert 
whatever consideration is paid to a dollar value equivalent for the 
purposes of this section.
    (5) Where an arm's-length sales contract price includes a reduction 
for a transportation factor, MMS will not consider the transportation 
factor to be a transportation allowance. You may use the transportation 
factor to determine your gross proceeds for the sale of the product. 
However, the transportation factor may not exceed 50 percent of the base 
price of the product without MMS approval.
    (b) Determining a transportation allowance under a non-arm's-length 
or no contract. (1) This paragraph explains how to determine your 
allowance if you

[[Page 116]]

have a non-arm's-length transportation contract or no contract.
    (i) When you have a non-arm's-length transportation contract or no 
contract, including those situations where you perform transportation 
services for yourself, the transportation allowance is based upon your 
reasonable, allowable, actual costs for transportation as provided in 
this paragraph.
    (ii) All transportation allowances deducted under a non-arm's-length 
or no contract situation are subject to monitoring, review, audit, and 
adjustment. You must submit the actual cost information to support the 
allowance to MMS on Form MMS-4295, Gas Transportation Allowance Report, 
within 3 months after the end of the 12-month period to which the 
allowance applies. However, MMS may approve a longer time period. MMS 
will monitor the allowance deductions to ensure that deductions are 
reasonable and allowable. When necessary or appropriate, MMS may require 
you to modify your actual transportation allowance deduction.
    (2) This paragraph explains what actual transportation costs are 
allowable under a non-arm's-length contract or no contract situation. 
The transportation allowance for non-arm's-length or no-contract 
situations is based upon your actual costs for transportation during the 
reporting period. Allowable costs include operating and maintenance 
expenses, overhead, and either depreciation and a return on 
undepreciated capital investment (in accordance with paragraph 
(b)(2)(iv)(A) of this section), or a cost equal to the initial 
depreciable investment in the transportation system multiplied by a rate 
of return in accordance with paragraph (b)(2)(iv)(B) of this section. 
Allowable capital costs are generally those costs for depreciable fixed 
assets (including costs of delivery and installation of capital 
equipment) that are an integral part of the transportation system.
    (i) Allowable operating expenses include operations supervision and 
engineering, operations labor, fuel, utilities, materials, ad valorem 
property taxes, rent, supplies, and any other directly allocable and 
attributable operating expense that you can document.
    (ii) Allowable maintenance expenses include maintenance of the 
transportation system, maintenance of equipment, maintenance labor, and 
other directly allocable and attributable maintenance expenses that you 
can document.
    (iii) Overhead directly attributable and allocable to the operation 
and maintenance of the transportation system is an allowable expense. 
State and Federal income taxes and severance taxes and other fees, 
including royalties, are not allowable expenses.
    (iv) You may use either depreciation with a return on undepreciated 
capital investment or a return on depreciable capital investment. After 
you have elected to use either method for a transportation system, you 
may not later elect to change to the other alternative without MMS 
approval.
    (A) To compute depreciation, you may elect to use either a straight-
line depreciation method based on the life of equipment or on the life 
of the reserves that the transportation system services, or a unit of 
production method. Once you make an election, you may not change methods 
without MMS approval. A change in ownership of a transportation system 
will not alter the depreciation schedule that the original transporter/
lessee established for purposes of the allowance calculation. With or 
without a change in ownership, a transportation system may be 
depreciated only once. Equipment may not be depreciated below a 
reasonable salvage value. To compute a return on undepreciated capital 
investment, you will multiply the undepreciated capital investment in 
the transportation system by the rate of return determined under 
paragraph (b)(2)(v) of this section.
    (B) To compute a return on depreciable capital investment, you will 
multiply the initial capital investment in the transportation system by 
the rate of return determined under paragraph (b)(2)(v) of this section. 
No allowance will be provided for depreciation. This alternative will 
apply only to transportation facilities first placed in service after 
March 1, 1988.
    (v) The rate of return is the industrial rate associated with 
Standard and Poor's BBB rating. The rate of return

[[Page 117]]

is the monthly average rate as published in Standard and Poor's Bond 
Guide for the first month of the reporting period for which the 
allowance is applicable and is effective during the reporting period. 
The rate must be redetermined at the beginning of each subsequent 
transportation allowance reporting period that is determined under 
paragraph (b)(4) of this section.
    (3) This paragraph explains how to allocate transportation costs to 
each product and transportation system.
    (i) The deduction for transportation costs must be determined based 
on your cost of transporting each product through each individual 
transportation system. If you transport more than one product in a 
gaseous phase, the allocation of costs to each of the products 
transported must be made in a consistent and equitable manner. The 
allocation should be in the same proportion that the volume of each 
product (excluding waste products that have no value) bears to the 
volume of all products in the gaseous phase (excluding waste products 
that have no value). Except as provided in this paragraph, you may not 
take an allowance for transporting a product that is not royalty bearing 
without MMS approval.
    (ii) As an alternative to the requirements of paragraph (b)(3)(i) of 
this section, you may propose to MMS a cost allocation method based on 
the values of the products transported. MMS will approve the method upon 
determining that it meets one of the two following requirements:
    (A) The methodology in paragraph (b)(3)(i) of this section cannot be 
applied; and
    (B) Your proposal is more reasonable than the method in paragraph 
(b)(3)(i) of this section.
    (4) Your transportation allowance under this paragraph (b) must be 
determined based upon a calendar year or other period if you and MMS 
agree to an alternative.
    (5) If you transport both gaseous and liquid products through the 
same transportation system, you must propose a cost allocation procedure 
to MMS. You may use the transportation allowance determined in 
accordance with your proposed allocation procedure until MMS issues its 
determination on the acceptability of the cost allocation. You are 
required to submit all relevant data to support your proposal. MMS will 
then determine the transportation allowance based upon your proposal and 
any additional information MMS deems necessary.
    (c) Using the alternative transportation calculation when you have a 
non-arm's-length or no contract. (1) As an alternative to computing your 
transportation allowance under paragraph (b) of this section, you may 
use as the transportation allowance 10 percent of your gross proceeds 
but not to exceed 30 cents per MMBtu.
    (2) Your election to use the alternative transportation allowance 
calculation in paragraph (c)(1) of this section must be made at the 
beginning of a month and must remain in effect for an entire calendar 
year. Your first election will remain in effect until the end of the 
succeeding calendar year, except for elections effective January 1 that 
will be effective only for that calendar year.
    (d) Reporting your transportation allowance. (1) If MMS requests, 
you must submit all data used to determine your transportation 
allowance. The data must be provided within a reasonable period of time 
that MMS will determine.
    (2) You must report transportation allowances as a separate 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

[[Page 118]]

include, but are not limited to, the following costs in determining the 
arm's-length transportation allowance under paragraph (a) of this 
section or the non-arm's-length transportation allowance under paragraph 
(b) of this section:
    (1) Firm demand charges paid to pipelines. You must limit the 
allowable costs for the firm demand charges to the applicable rate per 
MMBtu multiplied by the actual volumes transported. You may not include 
any losses incurred for previously purchased but unused firm capacity. 
You also may not include any gains associated with releasing firm 
capacity. If you receive a payment or credit from the pipeline for 
penalty refunds, rate case refunds, or other reasons, you must reduce 
the firm demand charge claimed on the Form MMS-2014. You must modify the 
Form MMS-2014 by the amount received or credited for the affected 
reporting period.
    (2) Gas supply realignment (GSR) costs. The GSR costs result from a 
pipeline reforming or terminating supply contracts with producers to 
implement the restructuring requirements of FERC orders in 18 CFR part 
284.
    (3) Commodity charges. The commodity charge allows the pipeline to 
recover the costs of providing service.
    (4) Wheeling costs. Hub operators charge a wheeling cost for 
transporting gas from one pipeline to either the same or another 
pipeline through a market center or hub. A hub is a connected manifold 
of pipelines through which a series of incoming pipelines are 
interconnected to a series of outgoing pipelines.
    (5) Gas Research Institute (GRI) fees. The GRI conducts research, 
development, and commercialization programs on natural gas related 
topics for the benefit of the U.S. gas industry and gas customers. GRI 
fees are allowable provided such fees are mandatory in FERC-approved 
tariffs.
    (6) Annual Charge Adjustment (ACA) fees. FERC charges these fees to 
pipelines to pay for its operating expenses.
    (7) Payments (either volumetric or in value) for actual or 
theoretical losses. This paragraph does not apply to non-arm's-length 
transportation arrangements.
    (8) Temporary storage services. This includes short duration storage 
services offered by market centers or hubs (commonly referred to as 
``parking'' or ``banking''), or other temporary storage services 
provided by pipeline transporters, whether actual or provided as a 
matter of accounting. Temporary storage is limited to 30 days or less.
    (9) Supplemental costs for compression, dehydration, and treatment 
of gas. MMS allows these costs only if such services are required for 
transportation and exceed the services necessary to place production 
into marketable condition required under 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

[[Page 119]]

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.
    (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.

[[Page 120]]

    (ii) When MMS conducts reviews and audits, we will examine whether 
the contract reflects more than the consideration actually transferred 
either directly or indirectly from you to the processor for the 
processing. If the contract reflects more than the total consideration, 
then MMS may require that the processing allowance be determined under 
paragraph (b) of this section.
    (iii) If MMS determines that the consideration paid under an arm's-
length processing contract does not reflect the value of the processing 
because of misconduct by or between the contracting parties, or because 
you otherwise have breached your duty to the lessor to market the 
production for the mutual benefit of you and the lessor, then MMS will 
require that the processing allowance be determined under paragraph (b) 
of this section. In these circumstances, MMS will notify you and give 
you an opportunity to provide written information justifying your 
processing costs.
    (2) If your arm's-length processing contract includes more than one 
gas plant product and the processing costs attributable to each product 
can be determined from the contract, then the processing costs for each 
gas plant product must be determined in accordance with the contract. 
You may not take an allowance for the costs of processing lease 
production that is not royalty-bearing.
    (3) If your arm's-length processing contract includes more than one 
gas plant product and the processing costs attributable to each product 
cannot be determined from the contract, you must propose an allocation 
procedure to MMS. You may use your proposed allocation procedure until 
MMS issues its determination. You are required to submit all relevant 
data to support your proposal. MMS will then determine the processing 
allowance based upon your proposal and any additional information MMS 
deems necessary. You may not take a processing allowance for the costs 
of processing lease production that is not royalty-bearing.
    (4) If your payments for processing under an arm's-length contract 
are not based on a dollar per unit price, you must convert whatever 
consideration is paid to a dollar value equivalent for the purposes of 
this section.
    (b) Determining a processing allowance if you have a non-arm's-
length contract or no contract. (1) This paragraph applies if you have a 
non-arm's-length processing contract or no contract, including those 
situations where you perform processing for yourself.
    (i) If you have a non-arm's-length contract or no contract, the 
processing allowance is based upon your reasonable actual costs of 
processing as provided in paragraph (b)(2) of this section.
    (ii) All processing allowances deducted under a non-arm's-length or 
no-contract situation are subject to monitoring, review, audit, and 
adjustment. You must submit the actual cost information to support the 
allowance to MMS on Form MMS-4109, Gas Processing Allowance Summary 
Report, within 3 months after the end of the 12-month period for which 
the allowance applies. MMS may approve a longer time period. MMS will 
monitor the allowance deduction to ensure that deductions are reasonable 
and allowable. When necessary or appropriate, MMS may require you to 
modify your processing allowance.
    (2) The processing allowance for non-arm's-length or no-contract 
situations is based upon your actual costs for processing during the 
reporting period. Allowable costs include operating and maintenance 
expenses, overhead, and either depreciation and a return on 
undepreciated capital investment (in accordance with paragraph 
(b)(2)(iv)(A) of this section), or a cost equal to the initial 
depreciable investment in the processing plant multiplied by a rate of 
return in accordance with paragraph (b)(2)(iv)(B) of this section. 
Allowable capital costs are generally those costs for depreciable fixed 
assets (including costs of delivery and installation of capital 
equipment) that are an integral part of the processing plant.
    (i) Allowable operating expenses include operations supervision and 
engineering, operations labor, fuel, utilities, materials, ad valorem 
property taxes, rent, supplies, and any other directly allocable and 
attributable operating expense that the lessee can document.

[[Page 121]]

    (ii) Allowable maintenance expenses include maintenance of the 
processing plant, maintenance of equipment, maintenance labor, and other 
directly allocable and attributable maintenance expenses that you can 
document.
    (iii) Overhead directly attributable and allocable to the operation 
and maintenance of the processing plant is an allowable expense. State 
and Federal income taxes and severance taxes, including royalties, are 
not allowable expenses.
    (iv) You may use either depreciation with a return on undepreciable 
capital investment or a return on depreciable capital investment. After 
you elect to use either method for a processing plant, you may not later 
elect to change to the other alternative without MMS approval.
    (A) To compute depreciation, you may elect to use either a straight-
line depreciation method based on the life of equipment or on the life 
of the reserves that the processing plant services, or a unit-of-
production method. Once you make an election, you may not change methods 
without MMS approval. A change in ownership of a processing plant will 
not alter the depreciation schedule that the original processor/lessee 
established for purposes of the allowance calculation. However, for 
processing plants you or your affiliate purchase that do not have a 
previously claimed MMS depreciation schedule, you may treat the 
processing plant as a newly installed facility for depreciation 
purposes. A processing plant may be depreciated only once, regardless of 
whether there is a change in ownership. Equipment may not be depreciated 
below a reasonable salvage value. To compute a return on undepreciated 
capital investment, you must multiply the undepreciable capital 
investment in the processing plant by the rate of return determined 
under paragraph (b)(2)(v) of this section.
    (B) To compute a return on depreciable capital investment, you must 
multiply the initial capital investment in the processing plant by the 
rate of return determined under paragraph (b)(2)(v) of this section. No 
allowance will be provided for depreciation. This alternative will apply 
only to plants first placed in service after March 1, 1988.
    (v) The rate of return is the industrial rate associated with 
Standard and Poor's BBB rating. The rate of return is the monthly 
average rate as published in Standard and Poor's Bond Guide for the 
first month for which the allowance is applicable. The rate must be 
redetermined at the beginning of each subsequent calendar year.
    (3) Your processing allowance under this paragraph (b) must be 
determined based upon a calendar year or other period if you and MMS 
agree to an alternative.
    (4) The processing allowance for each gas plant product must be 
determined based on your reasonable and actual cost of processing the 
gas. You must base your allocation of costs to each gas plant product 
upon generally accepted accounting principles. You may not take an 
allowance for the costs of processing lease production that is not 
royalty-bearing.
    (c) Reporting your processing allowance. (1) If MMS requests, you 
must submit all data used to determine your processing allowance. The 
data must be provided within a reasonable period of time, as MMS 
determines.
    (2) You must report gas processing allowances as a separate 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

[[Page 122]]

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 Sec. Sec. 206.179 
and 206.180.



                         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 Minerals Management Service 
(MMS) are subject to later audit and adjustment.

[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5479, Feb. 12, 1996; 67 
FR 19111, Apr. 18, 2002]



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

[[Page 123]]

    (c) Ownership of less than 10 percent creates a presumption of 
noncontrol which MMS may rebut if it demonstrates actual or legal 
control, including the existence of interlocking directorates.

Notwithstanding any other provisions of this subpart, contracts between 
relatives, either by blood or by marriage, are not arm's-length 
contracts. The MMS may require the lessee to certify ownership control. 
To be considered arm's-length for any production month, a contract must 
meet the requirements of this definition for that production month as 
well as when the contract was executed.
    Audit means a review, conducted in accordance with generally 
accepted accounting and auditing standards, of royalty payment 
compliance activities of lessees or other interest holders who pay 
royalties, rents, or bonuses on Federal leases.
    BLM means the Bureau of Land Management of the Department of the 
Interior.
    Coal means coal of all ranks from lignite through anthracite.
    Coal washing means any treatment to remove impurities from coal. 
Coal washing may include, but is not limited to, operations such as 
flotation, air, water, or heavy media separation; drying; and related 
handling (or combination thereof).
    Contract means any oral or written agreement, including amendments 
or revisions thereto, between two or more persons and enforceable by law 
that with due consideration creates an obligation.
    Gross proceeds (for royalty payment purposes) means the total monies 
and other consideration accruing to a coal lessee for the production and 
disposition of the coal produced. Gross proceeds includes, but is not 
limited to, payments to the lessee for certain services such as 
crushing, sizing, screening, storing, mixing, loading, treatment with 
substances including chemicals or oils, and other preparation of the 
coal to the extent that the lessee is obligated to perform them at no 
cost to the Federal Government. Gross proceeds, as applied to coal, also 
includes but is not limited to reimbursements for royalties, taxes or 
fees, and other reimbursements. Tax reimbursements are part of the gross 
proceeds accruing to a lessee even though the Federal royalty interest 
may be exempt from taxation. Monies and other consideration, including 
the forms of consideration identified in this paragraph, to which a 
lessee is contractually or legally entitled but which it does not seek 
to collect through reasonable efforts are also part of gross proceeds.
    Lease means any contract, profit-share arrangement, joint venture, 
or other agreement issued or approved by the United States for a Federal 
coal resource under a mineral leasing law that authorizes exploration 
for, development or extraction of, or removal of coal--or the land 
covered by that authorization, whichever is required by the context.
    Lessee means any person to whom the United States issues a lease, 
and any person who has been assigned an obligation to make royalty or 
other payments required by the lease. This includes any person who has 
an interest in a lease as well as an operator or payor who has no 
interest in the lease but who has assumed the royalty payment 
responsibility.
    Like-quality coal means coal that has similar chemical and physical 
characteristics.
    Marketable condition means coal that is sufficiently free from 
impurities and otherwise in a condition that it will be accepted by a 
purchaser under a sales contract typical for that area.
    Mine means an underground or surface excavation or series of 
excavations and the surface or underground support facilities that 
contribute directly or indirectly to mining, production, preparation, 
and handling of lease products.
    Net-back method means a method for calculating market value of coal 
at the lease or mine. Under this method, costs of transportation, 
washing, handling, etc., are deducted from the ultimate proceeds 
received for the coal at the first point at which reasonable values for 
the coal may be determined by a sale pursuant to an arm's-length 
contract or by comparison to other sales of coal, to ascertain value at 
the mine.
    Net output means the quantity of washed coal that a washing plant 
produces.

[[Page 124]]

    Netting is the deduction of an allowance from the sales value by 
reporting a one line net sales value, instead of correctly reporting the 
deduction as a separate line item on the Form MMS-4430.
    Person means by individual, firm, corporation, association, 
partnership, consortium, or joint venture.
    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; 66 FR 45769, Aug. 
30, 2001]



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 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.

    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 Solid Minerals Production and Royalty Report, Form MMS-4430, as 
required under 30 CFR part 210.

[54 FR 1523, Jan. 13, 1989, as amended at 57 FR 52720, Nov. 5, 1992; 66 
FR 45769, Aug. 30, 2001]



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

[[Page 125]]

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 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 Sec. Sec. 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

[[Page 126]]

to a contract which the lessee demonstrates, to MMS's satisfaction, were 
not part of the total consideration paid for the purchase of coal 
production.
    (c)(1) The value of coal from leases subject to this section and 
which is not sold pursuant to an arm's-length contract shall be 
determined in accordance with this section.
    (2) If the value of the coal cannot be determined pursuant to 
paragraph (b) of this section, then the value shall be determined 
through application of other valuation criteria. The criteria shall be 
considered in the following order, and the value shall be based upon the 
first applicable criterion:
    (i) The gross proceeds accruing to the lessee pursuant to a sale 
under its non-arm's-length contract (or other disposition of produced 
coal by other than an arm's-length contract), provided that those gross 
proceeds are within the range of the gross proceeds derived from, or 
paid under, comparable arm's-length contracts between buyers and sellers 
neither of whom is affiliated with the lessee for sales, purchases, or 
other dispositions of like-quality coal produced in the area. In 
evaluating the comparability of arm's-length contracts for the purposes 
of these regulations, the following factors shall be considered: Price, 
time of execution, duration, market or markets served, terms, quality of 
coal, quantity, and such other factors as may be appropriate to reflect 
the value of the coal;
    (ii) Prices reported for that coal to a public utility commission;
    (iii) Prices reported for that coal to the Energy Information 
Administration of the Department of Energy;
    (iv) Other relevant matters including, but not limited to, published 
or publicly available spot market prices, or information submitted by 
the lessee concerning circumstances unique to a particular lease 
operation or the saleability of certain types of coal;
    (v) If a reasonable value cannot be determined using paragraphs 
(c)(2) (i), (ii), (iii), or (iv) of this section, then a net-back method 
or any other reasonable method shall be used to determine value.
    (3) When the value of coal is determined pursuant to paragraph 
(c)(2) of this section, that value determination shall be consistent 
with the provisions contained in paragraph (b)(5) of this section.
    (d)(1) Where the value is determined pursuant to paragraph (c) of 
this section, that value does not require MMS's prior approval. However, 
the lessee shall retain all data relevant to the determination of 
royalty value. Such data shall be subject to review and audit, and MMS 
will direct a lessee to use a different value if it determines that the 
reported value is inconsistent with the requirements of these 
regulations.
    (2) Any Federal lessee will make available upon request to the 
authorized MMS or State representatives, to the Inspector General of the 
Department of the Interior or other persons authorized to receive such 
information, arm's-length sales value and sales quantity data for like-
quality coal sold, purchased, or otherwise obtained by the lessee from 
the area.
    (3) A lessee shall notify MMS if it has determined value pursuant to 
paragraphs (c)(2) (ii), (iii), (iv), or (v) of this section. The 
notification shall be by letter to the Associate Director for Minerals 
Revenue Management of his/her designee. The letter shall identify the 
valuation method to be used and contain a brief description of the 
procedure to be followed. The notification required by this section is a 
one-time notification due no later than the month the lessee first 
reports royalties on the Form MMS-4430 using a valuation method 
authorized by paragraphs (c)(2) (ii), (iii), (iv), or (v) of this 
section, and each time there is a change in a method under paragraphs 
(c)(2) (iv) or (v) of this section.
    (e) If MMS determines that a lessee has not properly determined 
value, the lessee shall be liable for the difference, if any, between 
royalty payments made based upon the value it has used and the royalty 
payments that are due based upon the value established by MMS. The 
lessee shall also be liable for interest computed pursuant to 30 CFR 
218.202. If the lessee is entitled to a credit, MMS will provide 
instructions for the taking of that credit.
    (f) The lessee may request a value determination from MMS. In that 
event, the lessee shall propose to MMS a

[[Page 127]]

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 Sec. Sec. 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 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; 66 FR 45769, Aug. 30, 
2001]



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

[[Page 128]]

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 demonstrating 
that its contract is arm's-length. MMS' prior approval is not required 
before a lessee may deduct costs incurred under an arm's-length 
contract. The lessee must claim a washing allowance by reporting it as a 
separate line entry on the Form MMS-4430.
    (2) In conducting reviews and audits, MMS will examine whether the 
contract reflects more than the consideration actually transferred 
either directly or indirectly from the lessee to the washer for the 
washing. If the contract reflects more than the total consideration 
paid, then the MMS may require that the washing allowance be determined 
in accordance with paragraph (b) of this section.
    (3) If the MMS determines that the consideration paid pursuant to an 
arm's-length washing contract does not reflect the reasonable value of 
the washing because of misconduct by or between the contracting parties, 
or because the lessee otherwise has breached its duty to the lessor to 
market the production for the mutual benefit of the lessee and the 
lessor, then MMS shall require that the washing allowance be determined 
in accordance with paragraph (b) of this section. When MMS determines 
that the value of the washing may be unreasonable, MMS will notify the 
lessee and give the lessee an opportunity to provide written information 
justifying the lessee's washing costs.
    (4) Where the lessee's payments for washing under an arm's-length 
contract are not based on a dollar-per-unit basis, the lessee shall 
convert whatever consideration is paid to a dollar value equivalent. 
Washing allowances shall be expressed as a cost per ton of coal washed.
    (b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length contract or has no contract, including those situations 
where the lessee performs washing for itself, the washing allowance will 
be based upon the lessee's reasonable actual costs. All washing 
allowances deducted under a non-arm's-length or no contract situation 
are subject to monitoring, review, audit, and possible future 
adjustment. The lessee must claim a washing allowance by reporting it as 
a separate line entry on the Form MMS-4430. When necessary or 
appropriate, MMS may direct a lessee to modify its estimated or actual 
washing allowance.
    (2) The washing allowance for non-arm's-length or no contract 
situations shall be based upon the lessee's actual costs for washing 
during the reported period, including operating and maintenance 
expenses, overhead, and either depreciation and a return on 
undepreciated capital investment in accordance with paragraph (b)(2)(iv) 
(A) of this section, or a cost equal to the depreciable investment in 
the wash plant multiplied by the rate of return in accordance with 
paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are 
generally those for depreciable fixed assets (including costs of 
delivery and installation of capital equipment) which are an integral 
part of the wash plant.
    (i) Allowable operating expenses include: Operations supervision and 
engineering; operations labor; fuel; utilities; materials; ad valorem 
property

[[Page 129]]

taxes, rent; supplies; and any other directly allocable and attributable 
operating expense which the lessee can document.
    (ii) Allowable maintenance expenses include: Maintenance of the wash 
plant; maintenance of equipment; maintenance labor; and other directly 
allocable and attributable maintenance expenses which the lessee can 
document.
    (iii) Overhead attributable and allocable to the operation and 
maintenance of the wash plant is an allowable expense. State and Federal 
income taxes and severance taxes, including royalities, are not 
allowable expenses.
    (iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this 
section. After a lessee has elected to use either method for a wash 
plant, the lessee may not later elect to change to the other alternative 
without approval of the MMS.
    (A) To compute depreciation, the lessee may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the wash plant services, whichever is 
appropriate, or a unit of production method. After an election is made, 
the lessee may not change methods without MMS approval. A change in 
ownership of a wash plant shall not alter the depreciation schedule 
established by the original operator/lessee for purposes of the 
allowance calculation. With or without a change in ownership, a wash 
plant shall be depreciated only once. Equipment shall not be depreciated 
below a reasonable salvage value.
    (B) The MMS shall allow as a cost an amount equal to the allowable 
capital investment in the wash plant multiplied by the rate of return 
determined pursuant to paragraph (b)(2)(v) of this section. No allowance 
shall be provided for depreciation. This alternative shall apply only to 
plants first placed in service or acquired after March 1, 1989.
    (v) The rate of return must be the industrial rate associated with 
Standard and Poor's BBB rating. The rate of return must be the monthly 
average rate as published in Standard and Poor's Bond Guide for the 
first month for which the allowance is applicable. The rate must be 
redetermined at the beginning of each subsequent calendar year.
    (3) The washing allowance for coal shall be determined based on the 
lessee's reasonable and actual cost of washing the coal. The lessee may 
not take an allowance for the costs of washing lease production that is 
not royalty bearing.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) The 
lessee must notify MMS of an allowance based on incurred costs by using 
a separate line entry on the Form MMS-4430.
    (ii) The MMS may require that a lessee submit arm's-length washing 
contracts and related documents. Documents shall be submitted within a 
reasonable time, as determined by MMS.
    (2) Non-arm's-length or no contract. (i) The lessee must notify MMS 
of an allowance based on the incurred costs by using a separate line 
entry on the Form MMS-4430.
    (ii) For new washing facilities or arrangements, the lessee's 
initial washing deduction shall include estimates of the allowable coal 
washing costs for the applicable period. Cost estimates shall be based 
upon the most recently available operations data for the washing system 
or, if such data are not available, the lessee shall use estimates based 
upon industry data for similar washing systems.
    (iii) Upon request by MMS, the lessee shall submit all data used to 
prepare the allowance deduction. The data shall be provided within a 
reasonable period of time, as determined by MMS.
    (d) Interest and assessments. (1) If a lessee nets a washing 
allowance on the Form MMS-4430, then the lessee shall be assessed an 
amount up to 10 percent of the allowance netted not to exceed $250 per 
lease 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-4430 for each month 
during the

[[Page 130]]

allowance reporting period, the lessee shall pay additional royalties 
due plus interest computed under 30 CFR 218.202 from the date when the 
lessee took the deduction to the date the lessee repays the difference 
to MMS. If the actual washing allowance is greater than the amount the 
lessee has taken on Form MMS-4430 for each month during the allowance 
reporting period, the lessee shall be entitled to a credit without 
interest.
    (2) The lessee must submit a corrected Form MMS-4430 to reflect 
actual costs, together with any payment, in accordance with instructions 
provided by MMS.
    (f) Other washing cost determinations. The provisions of this 
section shall apply to determine washing costs when establishing value 
using a net-back valuation procedure or any other procedure that 
requires deduction of washing costs.

[54 FR 1523, Jan. 13, 1989, as amended at 57 FR 52720, Nov. 5, 1992; 61 
FR 5480, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999; 66 FR 45769, Aug. 
30, 2001]



Sec. 206.260  Allocation of washed coal.

    (a) When coal is subjected to washing, the washed coal must be 
allocated to the leases from which it was extracted.
    (b) When the net output of coal from a washing plant is derived from 
coal obtained from only one lease, the quantity of washed coal allocable 
to the lease will be based on the net output of the washing plant.
    (c) When the net output of coal from a washing plant is derived from 
coal obtained from more than one lease, unless determined otherwise by 
BLM, the quantity of net output of washed coal allocable to each lease 
will be based on the ratio of measured quantities of coal delivered to 
the washing plant and washed from each lease compared to the total 
measured quantities of coal delivered to the washing plant and washed.



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]

[[Page 131]]



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-4430.
    (2) In conducting reviews and audits, MMS will examine whether the 
contract reflects more than the consideration actually transferred 
either directly or indirectly from the lessee to the transporter for the 
transportation. If the contract reflects more than the total 
consideration paid, then the MMS may require that the transportation 
allowance be determined in accordance with paragraph (b) of this 
section.
    (3) If the MMS determines that the consideration paid pursuant to an 
arm's-length transportation contract does not reflect the reasonable 
value of the transportation because of misconduct by or between the 
contracting parties, or because the lessee otherwise has breached its 
duty to the lessor to market the production for the mutual benefit of 
the lessee and the lessor, then MMS shall require that the 
transportation allowance be determined in accordance with paragraph (b) 
of this section. When MMS determines that the value of the 
transportation may be unreasonable, MMS will notify the lessee and give 
the lessee an opportunity to provide written information justifying the 
lessee's transportation costs.
    (4) Where the lessee's payments for transportation under an arm's-
length contract are not based on a dollar-per-unit basis, the lessee 
shall convert whatever consideration is paid to a dollar value 
equivalent for the purposes of this section.
    (b) Non-arm's-length or no contract--(1) If a lessee has a non-
arm's-length contract or has no contract, including those situations 
where the lessee performs transportation services for itself, the 
transportation allowance will be based upon the lessee's reasonable 
actual costs. All transportation allowances deducted under a non-arm's-
length or no contract situation are subject to monitoring, review, 
audit, and possible future adjustment. The lessee must claim a 
transportation allowance by reporting it as a separate line entry on the 
Form MMS-4430. When necessary or appropriate, MMS may direct a lessee to 
modify its estimated or actual transportation allowance deduction.
    (2) The transportation allowance for non-arm's-length or no-contract 
situations shall be based upon the lessee's actual costs for 
transportation during the reporting period, including operating and 
maintenance expenses, overhead, and either depreciation and a return on 
undepreciated capital investment in accordance with paragraph 
(b)(2)(iv)(A) of this section, or a cost equal to the depreciable 
investment in the transportation system multiplied by the rate of return 
in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable 
capital costs are generally those for depreciable fixed assets 
(including costs of delivery and installation of capital equipment) 
which are an integral part of the transportation system.
    (i) Allowable operating expenses include: Operations supervision and 
engineering; operations labor; fuel; utilities; materials; ad valorem 
property taxes; rent; supplies; and any other directly allocable and 
attributable operating expense which the lessee can document.
    (ii) Allowable maintenance expenses include: Maintenance of the 
transportation system; maintenance of equipment; maintenance labor; and 
other directly allocable and attributable maintenance expenses which the 
lessee can document.
    (iii) Overhead attributable and allocable to the operation and 
maintenance of the transportation system is an allowable expense. State 
and Federal income taxes and severance taxes and other fees, including 
royalties, are not allowable expenses.
    (iv) A lessee may use either paragraph (b)(2)(iv)(A) or paragraph 
(b)(2)(iv)(B) of this section. After a lessee has elected to use either 
method for

[[Page 132]]

a transportation system, the lessee may not later elect to change to the 
other alternative without approval of the MMS.
    (A) To compute depreciation, the lessee may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the transportation system services, 
whichever is appropriate, or a unit of production method. After an 
election is made, the lessee may not change methods without MMS 
approval. A change in ownership of a transportation system shall not 
alter the depreciation schedule established by the original transporter/
lessee for purposes of the allowance calculation. With or without a 
change in ownership, a transportation system shall be depreciated only 
once. Equipment shall not be depreciated below a reasonable salvage 
value.
    (B) The MMS shall allow as a cost an amount equal to the allowable 
capital investment in the transportation system multiplied by the rate 
of return determined pursuant to paragraph (b)(2)(B)(v) of this section. 
No allowance shall be provided for depreciation. This alternative shall 
apply only to transportation facilities first placed in service or 
acquired after March 1, 1989.
    (v) The rate of return must be the industrial rate associated with 
Standard and Poor's BBB rating. The rate of return must be the monthly 
average rate as published in Standard and Poor's Bond Guide for the 
first month for which the allowance is applicable. The rate must be 
redetermined at the beginning of each subsequent calendar year.
    (3) A lessee may apply to MMS for exception from the requirement 
that it compute actual costs in accordance with paragraphs (b)(1) and 
(b)(2) of this section. MMS will grant the exception only if the lessee 
has a rate for the transportation approved by a Federal agency or by a 
State regulatory agency (for Federal leases). MMS shall deny the 
exception request if it determines that the rate is excessive as 
compared to arm's-length transportation charges by systems, owned by the 
lessee or others, providing similar transportation services in that 
area. If there are no arm's-length transportation charges, MMS shall 
deny the exception request if:
    (i) No Federal or State regulatory agency costs analysis exists and 
the Federal or State regulatory agency, as applicable, has declined to 
investigate under MMS timely objections upon filing; and
    (ii) The rate significantly exceeds the lessee's actual costs for 
transportation as determined under this section.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) The 
lessee must notify MMS of an allowance based on incurred costs by using 
a separate line entry on the Form MMS-4430.
    (ii) The MMS may require that a lessee submit arm's-length 
transportation contracts, production agreements, operating agreements, 
and related documents. Documents shall be submitted within a reasonable 
time, as determined by MMS.
    (2) Non-arm's-length or no contract--(i) The lessee must notify MMS 
of an allowance based on the incurred costs by using a separate line 
entry on Form MMS-4430.
    (ii) For new transportation facilities or arrangements, the lessee's 
initial deduction shall include estimates of the allowable coal 
transportation costs for the applicable period. Cost estimates shall be 
based upon the most recently available operations data for the 
transportation system or, if such data are not available, the lessee 
shall use estimates based upon industry data for similar transportation 
systems.
    (iii) Upon request by MMS, the lessee shall submit all data used to 
prepare the allowance deduction. The data shall be provided within a 
reasonable period of time, as determined by MMS.
    (iv) If the lessee is authorized to use its Federal- or State-
agency-approved rate as its transportation cost in accordance with 
paragraph (b)(3) of this section, it shall follow the reporting 
requirements of paragraph (c)(1) of this section.
    (d) Interest and assessments. (1) If a lessee nets a transportation 
allowance on Form MMS-4430, the lessee shall be assessed an amount of up 
to 10 percent of the allowance netted not to exceed $250 per lease 
selling arrangement per sales period.

[[Page 133]]

    (2) If a lessee erroneously reports a transportation allowance which 
results in an underpayment of royalties, interest shall be paid on the 
amount of that underpayment.
    (3) Interest required to be paid by this section shall be determined 
in accordance with 30 CFR 218.202.
    (e) Adjustments. (1) If the actual coal transportation allowance is 
less than the amount the lessee has taken on Form MMS-4430 for each 
month during the allowance reporting period, the lessee shall pay 
additional royalties due plus interest computed under 30 CFR 218.202 
from the date when the lessee took the deduction to the date the lessee 
repays the difference to MMS. If the actual transportation allowance is 
greater than amount the lessee has taken on Form MMS-4430 for each month 
during the allowance reporting period, the lessee shall be entitled to a 
credit without interest.
    (2) The lessee must submit a corrected Form MMS-4430 to reflect 
actual costs, together with any payments, in accordance with 
instructions provided by MMS.
    (f) Other transportation cost determinations. The provisions of this 
section shall apply to determine transportation costs when establishing 
value using a net-back valuation procedure or any other procedure that 
requires deduction of transportation costs.

[54 FR 1523, Jan. 13, 1989, as amended at 57 FR 41864, Sept. 14, 1992; 
57 FR 52720, Nov. 5, 1992; 61 FR 5481, Feb. 12, 1996; 64 FR 43288, Aug. 
10, 1999; 66 FR 45769, Aug. 30, 2001]



Sec. 206.263  [Reserved]



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.



                     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

[[Page 134]]

deem appropriate; and Provided further, That in a situation where an 
estimated value is used, the authorized officer shall require the 
payment of such additional royalties, or allow such credits or refunds 
as may be necessary to adjust royalty payment to reflect the actual 
gross value.
    (b) The lessee is required to certify that the values reported for 
royalty purposes are bona fide sales not involving considerations other 
than the sale of the mineral, and he may be required by the authorized 
officer to supply supporting information.

[43 FR 10341, Mar. 13, 1978. Redesignated at 48 FR 36588, Aug. 12, 1983, 
and amended at 48 FR 44795, Sept. 30, 1983. Further redesignated at 51 
FR 15212, Apr. 22, 1986. Redesignated at 53 FR 39461, Oct. 7, 1988]



                     Subpart H_Geothermal Resources

    Source: 72 FR 24459, May 2, 2007, unless otherwise noted.



Sec. 206.350  What is the purpose of this subpart?

    (a) This subpart applies to all geothermal resources produced from 
Federal geothermal leases issued pursuant to the Geothermal Steam Act of 
1970 (GSA), as amended by the Energy Policy Act of 2005 (EPAct) (30 
U.S.C. 1001 et seq.). The purpose of this subpart is to prescribe how to 
calculate royalties and direct use fees for geothermal production.
    (b) The MMS may audit and adjust all royalty and fee payments.
    (c) In some cases, the regulations in this subpart may be 
inconsistent with a statute, settlement agreement, written agreement, or 
lease provision. If this happens, the statute, settlement agreement, 
written agreement, or lease provision will govern to the extent of the 
inconsistency. For purposes of this paragraph, the following definitions 
apply:
    (1) ``Settlement agreement'' means a settlement agreement between 
the United States and a lessee resulting from administrative or judicial 
litigation.
    (2) ``Written agreement'' means a written agreement between the 
lessee and the MMS Director or Assistant Secretary, Land and Minerals 
Management of the Department of the Interior that:
    (i) Establishes a method to determine the royalty from any lease 
that MMS expects at least would approximate the value or royalty 
established under this subpart; and
    (ii) Includes a value or gross proceeds determination under Sec. 
206.364 of this subpart.



Sec. 206.351  What definitions apply to this subpart?

    For purposes of this subpart, the following terms have the meanings 
indicated.
    Affiliate means a person who controls, is controlled by, or is under 
common control with another person. For purposes of this subpart:
    (1) Ownership or common ownership of more than 50 percent of the 
voting securities, or instruments of ownership, or other forms of 
ownership, of another person constitutes control. Ownership of less than 
10 percent constitutes a presumption of noncontrol that MMS may rebut.
    (2) If there is ownership or common ownership of 10 through 50 
percent of the voting securities, or instruments of ownership, or other 
forms of ownership of another person, MMS will consider the following 
factors in determining whether there is control under the circumstances 
of a particular case:
    (i) The extent to which there are common officers or directors;
    (ii) With respect to the voting securities, or instruments of 
ownership, or other forms of ownership: the percentage of ownership or 
common ownership, the relative percentage of ownership or common 
ownership compared to the percentage(s) of ownership by other persons, 
whether a person is the greatest single owner, or whether there is an 
opposing voting bloc of greater ownership;
    (iii) Operation of a lease, plant, pipeline, or other facility;
    (iv) The extent of participation by other owners in operations and 
day-to-day management of a lease, plant, pipeline, or other facility; 
and
    (v) Other evidence of power to exercise control over or common 
control with another person.

[[Page 135]]

    (3) Regardless of any percentage of ownership or common ownership, 
relatives, either by blood or marriage, are affiliates.
    Allowance means a deduction in determining value for royalty 
purposes.
    Arm's-length contract means a contract or agreement between 
independent persons who are not affiliates and who have opposing 
economic interests regarding that contract. To be considered arm's 
length for any production month, a contract must satisfy this definition 
for that month, as well as when the contract was executed.
    Audit means a review, conducted in accordance with generally 
accepted accounting and auditing standards, of royalty or fee payment 
compliance activities of lessees or other interest holders who pay 
royalties, fees, rents, or bonuses on Federal geothermal leases.
    Byproducts means minerals (exclusive of oil, hydrocarbon gas, and 
helium), found in solution or in association with geothermal steam, that 
no person would extract and produce by themselves because they are worth 
less than 75 percent of the value of the geothermal steam or because 
extraction and production would be too difficult.
    Byproduct recovery facility means a facility where byproducts are 
placed in marketable condition.
    Byproduct transportation allowance means an allowance for the 
reasonable, actual costs of moving byproducts to a point of sale or 
delivery off the lease, unit area, or communitized area, or away from a 
byproduct recovery facility. The byproduct transportation allowance does 
not include gathering costs. You must report a byproduct transportation 
allowance as a separate discrete field on the Form MMS-2014.
    Class I lease means:
    (1) A lease that BLM issued before August 8, 2005, for which the 
lessee has not converted the royalty rate terms under 43 CFR 3212.25; or
    (2) A lease that BLM issued in response to an application that was 
pending on August 8, 2005, for which the lessee has not made an election 
under 43 CFR 3200.8(b).
    Class II lease means:
    A lease that BLM issued after August 8, 2005, except for a lease 
issued in response to an application that was pending on August 8, 2005, 
for which the lessee does not make an election under 43 CFR 3200.8(b).
    Class III lease means:
    A lease that BLM issued before August 8, 2005, for which the lessee 
has converted to the royalty rate or direct use fee terms under 43 CFR 
3212.25.
    Commercial production or generation of electricity means generation 
of electricity that is sold or is subject to sale, including the 
electricity or energy that is reasonably required to produce the 
resource used in production of electricity for sale or to convert 
geothermal energy into electrical energy for sale.
    Contract means any oral or written agreement, including amendments 
or revisions thereto, between two or more persons and enforceable by law 
that with due consideration creates an obligation.
    Deduction means a subtraction the lessee uses to determine the value 
of geothermal resources produced from a Class I lease that the lessee 
uses to generate electricity.
    Delivered electricity means the amount of electricity in kilowatt-
hours delivered to the purchaser.
    Direct use means the utilization of geothermal resources for 
commercial, residential, agricultural, public facilities, or other 
energy needs, other than the commercial production or generation of 
electricity.
    Direct use facility means a facility that uses the heat or other 
energy of the geothermal resource for direct use purposes.
    Electrical facility means a power plant or other facility that uses 
a geothermal resource to generate electricity.
    Field means the land surface vertically projected over a subsurface 
geothermal reservoir encompassing at least the outermost boundaries of 
all geothermal accumulations known to be within that reservoir. 
Geothermal fields are usually given names and their official boundaries 
are often designated by regulatory agencies in the respective States in 
which the fields are located.

[[Page 136]]

    Gathering means the movement of lease production from the wellhead 
to the point of utilization.
    Generating deduction means a deduction for the lessee's reasonable, 
actual costs of generating plant tailgate electricity.
    Geothermal resources means:
    (1) All products of geothermal processes, including indigenous 
steam, hot water, and hot brines;
    (2) Steam and other gases, hot water, and hot brines resulting from 
water, gas, or other fluids artificially introduced into geothermal 
formations;
    (3) Heat or other associated energy found in geothermal formations; 
and
    (4) Any byproducts.
    Gross proceeds (for royalty payment purposes) means the total monies 
and other consideration accruing to a geothermal lessee for the sale of 
electricity or geothermal resource. Gross proceeds includes, but is not 
limited to:
    (1) Payments to the lessee for certain services such as effluent 
injection, field operation and maintenance, drilling or workover of 
wells, or field gathering to the extent that the lessee is obligated to 
perform such functions at no cost to the Federal Government;
    (2) Reimbursements for production taxes and other taxes. Tax 
reimbursements are part of gross proceeds accruing to a lessee even 
though the Federal royalty interest may be exempt from taxation; and
    (3) Any monies and other consideration, including the forms of 
consideration identified in this paragraph, to which a lessee is 
contractually or legally entitled but which it does not seek to collect 
through reasonable efforts.
    Lease means a geothermal lease issued under the authority of the 
GSA, unless the context indicates otherwise.
    Lessee (you) means any person to whom the United States issues a 
geothermal lease, and any person who has been assigned an obligation to 
make royalty, fee, or other payments required by the lease. This 
includes any person who has an interest in a geothermal lease as well as 
an operator or payor who has no interest in the lease but who has 
assumed the royalty, fee, or other payment responsibility. This also 
includes any affiliate of the lessee that uses the geothermal resource 
to generate electricity, in a direct use process, or to recover 
byproducts, or any affiliate that sells or transports lease production.
    Marketable condition means lease products that are sufficiently free 
from impurities and otherwise in a condition that they will be accepted 
by a purchaser under a sales contract typical for the disposition from 
the field or area of such lease products.
    Person means any individual, firm, corporation, association, 
partnership, consortium, or joint venture (when established as a 
separate entity).
    Plant parasitic electricity means electricity used to operate a 
power plant that is used for commercial production or generation of 
electricity.
    Plant tailgate electricity means the amount of electricity in 
kilowatt-hours generated by a power plant exclusive of plant parasitic 
electricity, but inclusive of any electricity generated by the power 
plant and returned to the lease for lease operations. Plant tailgate 
electricity should be measured at, or calculated for, the high voltage 
side of the transformer in the plant switchyard.
    Point of utilization means the power plant or direct use facility in 
which the geothermal resource is utilized.
    Public purpose means a program carried out by a State, tribal, or 
local government for the purpose of providing facilities or services for 
the benefit of the public in connection with, but not limited to, public 
health, safety or welfare, other than the commercial generation of 
electricity. Use of lands or facilities for habitation, cultivation, 
trade or manufacturing is permissible only when necessary for and 
integral to (i.e., an essential part of) the public purpose.
    Public safety or welfare means a program carried out or promoted by 
a public agency for public purposes involving, directly or indirectly, 
protection, safety, and law enforcement activities, and the criminal 
justice system of a given political area. Public safety or welfare may 
include, but is not limited to, programs carried out by:
    (1) Public police departments;
    (2) Sheriffs' offices;
    (3) The courts;

[[Page 137]]

    (4) Penal and correctional institutions (including juvenile 
facilities);
    (5) State and local civil defense organizations; and
    (6) Fire departments and rescue squads (including volunteer fire 
departments and rescue squads supported in whole or in part with public 
funds).
    Reasonable alternative fuel means a conventional fuel (such as coal, 
oil, gas, or wood) that would normally be used as a source of heat in 
direct use operations.
    Secretary means the Secretary of the Interior or any person duly 
authorized to exercise the powers vested in that office.
    Transmission deduction means a deduction for the lessee's reasonable 
actual costs incurred to wheel or transmit the electricity from the 
lessee's power plant to the purchaser's delivery point.
    Wheeling means the transmission of electricity from a power plant to 
the point of delivery.



Sec. 206.352  How do I calculate the royalty due on geothermal resources used 

for commercial production or generation of electricity?

    (a) If you sold geothermal resources produced from a Class I, II, or 
III lease at arm's length that the purchaser uses to generate 
electricity, then the royalty on the geothermal resources is the gross 
proceeds accruing to you from the sale of the geothermal resource to the 
arm's-length purchaser multiplied by either:
    (1) The royalty rate in your lease; or
    (2) The royalty rate that BLM prescribes or calculates under 43 CFR 
3211.17. See Sec. 206.361 for additional provisions applicable to 
determining gross proceeds under arm's-length sales.
    (b) If you use the geothermal resource in your own power plant for 
the generation and sale of electricity, the following provisions apply
    (1) For Class I leases, you must determine the royalty on produced 
geothermal resources in accordance with the first applicable of the 
following paragraphs:
    (i) The gross proceeds accruing to you from the arm's-length sale of 
the electricity less applicable deductions determined under Sec. 
206.353 and Sec. 206.354 of this part, multiplied by the royalty rate 
in your lease. See Sec. 206.361 for additional provisions applicable to 
determining gross proceeds under arm's-length sales. Under no 
circumstances may the deductions reduce the royalty value of the 
geothermal resource to zero; or
    (ii) A royalty determined by any other reasonable method approved by 
MMS under Sec. 206.364 of this subpart.
    (2) For Class II and Class III leases, the royalty on geothermal 
resources produced is your gross proceeds from the sale of electricity 
multiplied by the royalty rate BLM prescribed for your lease under 43 
CFR 3211.17. See Sec. 206.361 for additional provisions applicable to 
determining gross proceeds under arm's-length sales. You may not reduce 
gross proceeds by any deductions.



Sec. 206.353  How do I determine transmission deductions?

    (a) If you determine the value of your geothermal resources under 
Sec. 206.352(b)(1)(i) of this subpart, you may subtract a transmission 
deduction from the gross proceeds you received for the sale of 
electricity to determine the plant tailgate value of the electricity.
    (1) The transmission deduction consists of either or both of two 
components:
    (i) Transmission line costs as determined under paragraph (b) of 
this section; and
    (ii) Wheeling costs if the electricity is transmitted across a third 
party's transmission line under an arm's-length wheeling agreement.
    (2) You may deduct the actual costs you (including your 
affiliate(s)) incur for transmitting electricity under your arm's-length 
wheeling contract.
    (b) To determine your transmission line cost, you must follow the 
requirements of paragraphs (b)(1) and (b)(2) of this section.
    (1) Your transmission line costs are your actual costs associated 
with the construction and operation of a transmission line for the 
purpose of transmitting electricity attributable and allocable to your 
power plant utilizing Federal geothermal resources.
    (i) You must determine the monthly transmission line cost component 
of

[[Page 138]]

the transmission deduction by multiplying the annual transmission line 
cost rate (in dollars per kilowatt-hour) by the amount of electricity 
delivered for the reporting month.
    (ii) You must redetermine the transmission line cost rate annually 
either at the beginning of the same month of the year in which the power 
plant was placed into service or at a time concurrent with the beginning 
of your annual corporate accounting period. The period you select must 
coincide with the same period you chose for the generating deduction 
under Sec. 206.354(b)(1). After you choose a deduction period, you may 
not later elect to use a different deduction period without MMS 
approval.
    (2) Your actual transmission line costs during the reporting period 
include:
    (i) Operating and maintenance expenses under paragraphs (d) and (e) 
of this section;
    (ii) Overhead under paragraph (f) of this section; and either
    (iii) Depreciation under paragraphs (g) and (h) of this section and 
a return on undepreciated capital investment under paragraphs (g) and 
(i) of this section or
    (iv) A return on the capital investment in the transmission line 
under paragraphs (g) and (j) of this section.
    (c)(1) Allowable capital costs under paragraph (b) of this section 
are generally those for depreciable fixed assets (including costs of 
delivery and installation of capital equipment) that are an integral 
part of the transmission line.
    (2)(i) You may include a return on capital you invested in the 
purchase of real estate for transmission facilities if:
    (A) Such purchase is necessary; and
    (B) The surface is not part of the Federal lease.
    (ii) The rate of return will be the same rate determined under 
paragraph (k) of this section.
    (d) Allowable operating expenses include:
    (1) Operations supervision and engineering;
    (2) Operations labor;
    (3) Fuel;
    (4) Utilities;
    (5) Materials;
    (6) Ad valorem property taxes;
    (7) Rent;
    (8) Supplies; and
    (9) Any other directly allocable and attributable operating or 
maintenance expense that you can document.
    (e) Allowable maintenance expenses include:
    (1) Maintenance of the transmission line;
    (2) Maintenance of equipment;
    (3) Maintenance labor; and
    (4) Other directly allocable and attributable maintenance expenses 
that you can document.
    (f) Overhead directly attributable and allocable to the operation 
and maintenance of the transmission line is an allowable expense. State 
and Federal income taxes and severance taxes and other fees, including 
royalties, are not allowable expenses.
    (g) To compute costs associated with capital investment, a lessee 
may use either depreciation with a return on undepreciated capital 
investment, or a return on capital investment in the transmission line. 
After a lessee has elected to use either method, the lessee may not 
later elect to change to the other alternative without MMS approval.
    (h)(1) To compute depreciation, you must use a straight-line 
depreciation method based on the life of the geothermal project, usually 
the term of the electricity sales contract, or other depreciation period 
acceptable to MMS. You may not depreciate equipment below a reasonable 
salvage value.
    (2) A change in ownership of a transmission line does not alter the 
depreciation schedule established by the original lessee-owner for 
purposes of computing transmission line costs.
    (3) With or without a change in ownership, you may depreciate a 
transmission line only once.
    (i) To calculate a return on undepreciated capital investment, 
multiply the remaining undepreciated capital balance as of the beginning 
of the period for which you are calculating the transmission deduction 
by the rate of return provided in paragraph (k) of this section.
    (j) To compute a return on capital investment in the transmission 
line,

[[Page 139]]

multiply the allowable capital investment in the transmission line by 
the rate of return determined pursuant to paragraph (k) of this section. 
There is no allowance for depreciation.
    (k) The rate of return must be 2.0 multiplied by the industrial rate 
associated with Standard & Poor's BBB rating. The BBB rate must be the 
monthly average rate as published in Standard & Poor's Bond Guide for 
the first month for which the allowance is applicable. Redetermine the 
rate at the beginning of each subsequent calendar year.
    (l) Calculate the deduction for transmission costs based on your 
cost of transmitting electricity through each individual transmission 
line.
    (m)(1) For new transmission facilities or arrangements, base your 
initial deduction on estimates of allowable electricity transmission 
costs for the applicable period. Use the most recently available 
operations data for the transmission line or, if such data are not 
available, use estimates based on data for similar transmission lines.
    (2) When actual cost information is available, you must amend your 
prior Form MMS-2014 reports to reflect actual transmission costs 
deductions for each month for which you reported and paid based on 
estimated transmission costs. You must pay any additional royalties due 
(together with interest computed under Sec. 218.302). You are entitled 
to a credit for or refund of any overpaid royalties.
    (n) In conducting reviews and audits, MMS may require you to submit 
arm's-length transmission contracts, production agreements, operating 
agreements, and related documents and all other data used to calculate 
the deduction. You must comply with any such requirements within the 
time MMS specifies. Recordkeeping requirements are found at part 212 of 
this chapter.
    (o) At the completion of transmission line dismantlement and salvage 
operations, you may report a credit for or request a refund of royalties 
in an amount equal to the royalty rate times the amount by which actual 
transmission line dismantlement costs exceed actual income attributable 
to salvage of the transmission line.



Sec. 206.354  How do I determine generating deductions?

    (a) If you determine the value of your geothermal resources under 
Sec. 206.352(b)(1)(i) of this subpart, you may deduct your reasonable 
actual costs incurred to generate electricity from the plant tailgate 
value of the electricity (usually the transmission-reduced value of the 
delivered electricity). You may deduct the actual costs you incur for 
generating electricity under your arm's-length power plant contract.
    (b)(1) You must base your generating costs deduction on your actual 
annual costs associated with the construction and operation of a 
geothermal power plant.
    (i) You must determine your monthly generating deduction by 
multiplying the annual generating cost rate (in dollars per kilowatt-
hour) by the amount of plant tailgate electricity measured (or computed) 
for the reporting month. The generating cost rate is determined from the 
annual amount of your plant tailgate electricity.
    (ii) You must redetermine your generating cost rate annually either 
at the beginning of the same month of the year in which the power plant 
was placed into service or at a time concurrent with the beginning of 
your annual corporate accounting period. The period you select must 
coincide with the same period chosen for the transmission deduction 
under Sec. 206.353(b)(1). After you choose a deduction period, you may 
not later elect to use a different deduction period without MMS 
approval.
    (2) Your generating costs are your actual power plant costs during 
the reporting period, including:
    (i) Operating and maintenance expenses under paragraphs (d) and (e) 
of this section;
    (ii) Overhead under paragraph (f) of this section; and either
    (iii) Depreciation under paragraphs (g) and (h) of this section and 
a return on undepreciated capital investment under paragraphs (g) and 
(i) of this section; or
    (iv) A return on capital investment in the power plant under 
paragraphs (g) and (j) of this section.

[[Page 140]]

    (c)(1) Allowable capital costs under paragraph (b) of this section 
are generally those for depreciable fixed assets (including costs of 
delivery and installation of capital equipment) that are an integral 
part of the power plant or are required by the design specifications of 
the power conversion cycle.
    (2)(i) You may include a return on capital you invested in the 
purchase of real estate for a power plant site if:
    (A) The purchase is necessary; and,
    (B) The surface is not part of the Federal lease.
    (ii) The rate of return will be the same rate determined under 
paragraph (k) of this section.
    (3) You may not deduct the costs of gathering systems and other 
production-related facilities.
    (d) Allowable operating expenses include:
    (1) Operations supervision and engineering;
    (2) Operations labor;
    (3) Auxiliary fuel and/or utilities used to operate the power plant 
during down time;
    (4) Utilities;
    (5) Materials;
    (6) Ad valorem property taxes;
    (7) Rent;
    (8) Supplies; and
    (9) Any other directly allocable and attributable operating expense.
    (e) Allowable maintenance expenses include:
    (1) Maintenance of the power plant;
    (2) Maintenance of equipment;
    (3) Maintenance labor; and
    (4) Other directly allocable and attributable maintenance expenses 
that you can document.
    (f) Overhead directly attributable and allocable to the operation 
and maintenance of the power plant is an allowable expense. State and 
Federal income taxes and severance taxes and other fees, including 
royalties, are not allowable expenses.
    (g) To compute costs associated with capital investment, a lessee 
may use either depreciation with a return on undepreciated capital 
investment, or a return on capital investment in the power plant. After 
a lessee has elected to use either method, the lessee may not later 
elect to change to the other alternative without MMS approval.
    (h)(1) To compute depreciation, you must use a straight-line 
depreciation method based on the life of the geothermal project, usually 
the term of the electricity sales contract, or other depreciation period 
acceptable to MMS. You may not depreciate equipment below a reasonable 
salvage value.
    (2) A change in ownership of the power plant does not alter the 
depreciation schedule established by the original lessee-owner for 
purposes of computing generating costs.
    (3) With or without a change in ownership, you may depreciate a 
power plant only once.
    (i) To calculate a return on undepreciated capital investment, 
multiply the remaining undepreciated capital balance as of the beginning 
of the period for which you are calculating the generating deduction 
allowance by the rate of return provided in paragraph (k) of this 
section.
    (j) To compute a return on capital investment in the power plant, 
multiply the allowable capital investment in the power plant by the rate 
of return determined pursuant to paragraph (k) of this section. There is 
no allowance for depreciation.
    (k) The rate of return must be 2.0 multiplied by the industrial rate 
associated with Standard & Poor's BBB rating. The BBB rate must be the 
monthly average rate as published in Standard & Poor's Bond Guide for 
the first month for which the allowance is applicable. You must 
redetermine the rate at the beginning of each subsequent calendar year.
    (l) Calculate the deduction for generating costs based on your cost 
of generating electricity through each individual power plant.
    (m)(1) For new power plants or arrangements, base your initial 
deduction on estimates of allowable electricity generation costs for the 
applicable period. Use the most recently available operations data for 
the power plant or, if such data are not available, use estimates based 
on data for similar power plants.
    (2) When actual cost information is available, you must amend your 
prior Form MMS-2014 reports to reflect actual generating cost deductions 
for each month for which you reported and

[[Page 141]]

paid based on estimated generating costs. You must pay any additional 
royalties due (together with interest computed under Sec. 218.302). You 
are entitled to a credit for or refund of any overpaid royalties.
    (n) In conducting reviews and audits, MMS may require you to submit 
arm's-length power plant contracts, production agreements, operating 
agreements, related documents and all other data used to calculate the 
deduction. You must comply with any such requirements within the time 
MMS specifies. Recordkeeping requirements are found at part 212 of this 
chapter.
    (o) At the completion of power plant dismantlement and salvage 
operations, you may report a credit for or request a refund of royalty 
in an amount equal to the royalty rate times the amount by which actual 
power plant dismantlement costs exceed actual income attributable to 
salvage of the power plant.



Sec. 206.355  How do I calculate royalty due on geothermal resources I sell 

at arm's length to a purchaser for direct use?

    If you sell geothermal resources produced from Class I, II, or III 
leases at arm's length to a purchaser for direct use, then the royalty 
on the geothermal resource is the gross proceeds accruing to you from 
the sale of the geothermal resource to the arm's-length purchaser 
multiplied by the royalty rate in your lease or that BLM prescribes 
under 43 CFR 3211.18. See Sec. 206.361 for additional provisions 
applicable to determining gross proceeds under arm's-length sales.



Sec. 206.356  How do I calculate royalty or fees due on geothermal resources 

I use for direct use purposes?

    If you use the geothermal resource for direct use:
    (a) For Class I leases, you must determine the royalty due on 
geothermal resources in accordance with the first applicable of the 
following three paragraphs.
    (1) The weighted average of the gross proceeds established in arm's-
length contracts for the purchase of significant quantities of 
geothermal resources to operate the lessee's same direct-use facility 
multiplied by the royalty rate in your lease. In evaluating the 
acceptability of arm's-length contracts, the following factors will be 
considered: time of execution, duration, terms, volume, quality of 
resource, and such other factors as may be appropriate to reflect the 
value of the resource.
    (2) The equivalent value of the least expensive, reasonable 
alternative energy source (fuel) multiplied by the royalty rate in your 
lease. The equivalent value of the least expensive, reasonable 
alternative energy source will be based on the amount of thermal energy 
that would otherwise be used by the direct use facility in place of the 
geothermal resource. That amount of thermal energy (in Btu) displaced by 
the geothermal resource will be determined by the equation:
[GRAPHIC] [TIFF OMITTED] TR02MY07.003


Where hin is the enthalpy in Btu/lb at the direct use 
facility inlet (based on measured inlet temperature), hout is 
the enthalpy in Btu/lb at the facility outlet (based on measured outlet 
temperature), density is in lbs/cu ft based on inlet temperature, the 
factor 0.113681 (cu ft/gal) converts gallons to cubic feet, and volume 
is the quantity of geothermal fluid in gallons produced at the wellhead 
or measured at an approved point. The efficiency factor of the 
alternative energy source will be 0.7 for coal and 0.8 for oil, natural 
gas, and other fuels derived from oil and natural gas, or an efficiency 
factor proposed by the lessee and approved by

[[Page 142]]

MMS. The methods of measuring resource parameters (temperature, volume, 
etc.) and the frequency of computing and accumulating the amount of 
thermal energy displaced will be determined and approved by BLM under 43 
CFR 3275.13-3275.17.
    (3) A royalty determined by any other reasonable method approved by 
MMS or the Assistant Secretary, Land and Minerals Management of the 
Department of the Interior, under Sec. 206.364 of this part.
    (b) For geothermal resources produced from Class II and Class III 
leases, you must multiply the appropriate fee from the schedule in 
subparagraph (b)(1) of this section by the number of gallons or pounds 
you produce from the direct use lease each month.
    (1) You must use the following fee schedule to calculate fees due 
under this section:

                                             Direct Use Fee Schedule
                                                   [Hot water]
----------------------------------------------------------------------------------------------------------------
             If your average monthly inlet temperature ( [deg]F) is                     Your fees are . . .
----------------------------------------------------------------------------------------------------------------
                                                                   But less than    ($/million      ($/million
                         At least . . .                                . . .         gallons)         pounds)
----------------------------------------------------------------------------------------------------------------
130.............................................................             140           2.524           0.307
140.............................................................             150           7.549           0.921
150.............................................................             160          12.543           1.536
160.............................................................             170          17.503           2.150
170.............................................................             180          22.426           2.764
180.............................................................             190          27.310           3.379
190.............................................................             200          32.153           3.993
200.............................................................             210          36.955           4.607
210.............................................................             220          41.710           5.221
220.............................................................             230          46.417           5.836
230.............................................................             240          51.075           6.450
240.............................................................             250          55.682           7.064
250.............................................................             260          60.236           7.679
260.............................................................             270          64.736           8.293
270.............................................................             280          69.176           8.907
280.............................................................             290          73.558           9.521
290.............................................................             300          77.876          10.136
300.............................................................             310          82.133          10.750
310.............................................................             320          86.328          11.364
320.............................................................             330          90.445          11.979
330.............................................................             340          94.501          12.593
340.............................................................             350          98.481          13.207
350.............................................................             360         102.387          13.821
----------------------------------------------------------------------------------------------------------------

    (i) For direct use geothermal resources with an average monthly 
inlet temperature of 130 [deg]F or less, you must pay only the lease 
rental.
    (ii) The MMS, in consultation with BLM, will develop and publish a 
revised fee schedule in the Federal Register, as needed.
    (iii) The MMS, in consultation with BLM, will calculate revised fees 
schedules using the following formulas:
[GRAPHIC] [TIFF OMITTED] TR02MY07.004

Where:

RV = Royalty due as a function of produced volume in the fee 
schedule, expressed as dollars per million (10\6\) gallons;

[[Page 143]]

Rm = Royalty due as a function of produced mass in the fee 
schedule, expressed as dollars per million (10\6\) pounds;
[rho][rho] = Water density at inlet temperature expressed as lbs per 
gallon;
Tin = Measured inlet temperature in [deg]F (as required by 
BLM under 43 CFR part 3275);
Tout = Established assumed outlet temperature of 130[deg] F;
e = Boiler Efficiency Factor for coal of 70 percent;
Pprbc = The 3-year historical average of Powder River Basin 
spot coal prices, as published by the Energy Information Administration, 
or other recognized authoritative reference source of coal prices, in 
dollars (per MMBtu);
Frr = The assumed Lease Royalty Rate of 10 percent.

    (2) The fee that you report is subject to monitoring, review, and 
audit.
    (3) The schedule of fees established under this paragraph will apply 
to any Class III lease with respect to any royalty payments previously 
made when the lease was a Class I lease that were due and owing, and 
were paid, on or after July 16, 2003. To use this provision, you must 
provide MMS data showing the amount of geothermal production in pounds 
or gallons of geothermal fluid to input into the fee schedule (see 43 
CFR part 3276).
    (i) If the royalties you previously paid are less than the fees due 
under this section, you must pay the difference plus interest on that 
difference computed under Sec. 218.302.
    (ii) If the royalties you previously paid are more than the fees due 
under this section, then you are entitled to a refund or credit from MMS 
of 50 percent of the overpaid royalties. You are also entitled to a 
refund or credit of any interest that you paid on the overpaid 
royalties.
    (c) For geothermal resources other than hot water, MMS will 
determine fees on a case-by-case basis.



Sec. 206.357  How do I calculate royalty due on byproducts?

    (a) If you sell byproducts, you must determine the royalty due on 
the byproducts that are royalty-bearing under:
    (1) Applicable lease terms of Class I leases and of Class III leases 
that do not elect to be subject to all of the BLM regulations 
promulgated for leases issued after August 8, 2005, under 43 CFR 
3200.7(a)(2), or
    (2) Applicable statutory provisions at 30 U.S.C. 1004(a)(2) for 
Class II leases and for Class III leases that do elect to be subject to 
all of the BLM regulations promulgated for leases issued after August 8, 
2005, under 43 CFR 3200.7(a)(2).
    (b) You must determine the royalty due on the byproducts by 
multiplying the royalty rate in your lease or that BLM prescribes under 
43 CFR 3211.19 by a value of the byproducts determined in accordance 
with the first applicable of the following subparagraphs:
    (1) The gross proceeds accruing to you from the arm's-length sale of 
the byproducts, less any applicable byproduct transportation allowances 
determined under Sec. Sec. 206.358 and 206.359. See Sec.  206.361 for 
additional provisions applicable to determining gross proceeds;
    (2) Other relevant matters including, but not limited to, published 
or publicly available spot-market prices, or information submitted by 
the lessee concerning circumstances unique to a particular lease 
operation or the saleability of certain byproducts; or
    (3) Any other reasonable valuation method approved by MMS.



Sec. 206.358  What are byproduct transportation allowances?

    (a) When you determine the value of byproducts at a point off the 
geothermal lease, unit, or participating area, you are allowed a 
deduction in determining value, for royalty purposes, for your 
reasonable, actual costs incurred to:
    (1) Transport the byproducts from a Federal lease, unit, or 
participating area to a sales point or point of delivery that is off the 
lease, unit, or participating area; or
    (2) Transport the byproducts from a Federal lease, unit, or 
participating area, or from a geothermal use facility to a byproduct 
recovery facility when that byproduct recovery facility is off the 
lease, unit, or participating area and, if applicable, from the recovery 
facility to a sales point or point of delivery off the lease, unit, or 
participating area.
    (b) Costs for transporting geothermal fluids from the lease to the 
geothermal

[[Page 144]]

use facility, whether on or off the lease, are not includible in the 
byproduct transportation allowance.
    (c)(1) When you transport byproducts from a lease, unit, 
participating area, or geothermal use facility to a byproduct recovery 
facility, you are not required to allocate transportation costs between 
the quantity of marketable byproducts and the rejected waste material. 
The byproduct transportation allowance is authorized for the total 
production that is transported. You must express byproduct 
transportation allowances as a cost per unit of marketable byproducts 
transported.
    (2) For byproducts that are extracted on the lease, unit, 
participating area, or at the geothermal use facility, the byproduct 
transportation allowance is authorized for the total byproduct that is 
transported to a point of sale off the lease, unit, or participating 
area. You must express byproduct transportation allowances as a cost per 
unit of byproduct transported.
    (3) You may deduct transportation costs only when you sell, deliver, 
or otherwise utilize the transported byproduct and report and pay 
royalties on the byproduct.
    (d) Reporting requirements. (1) You must use a discrete field on 
Form MMS-2014 to notify MMS of a transportation allowance.
    (2) In conducting reviews and audits, MMS may require you to submit 
arm's-length transportation contracts, production agreements, operating 
agreements, and related documents. You must comply with any such 
requirements within the time MMS specifies. Recordkeeping requirements 
are found at part 212 of this chapter.
    (e) Byproduct transportation allowances are subject to monitoring, 
review, and audit. If, after a review or audit, MMS determines that you 
have improperly determined a byproduct transportation allowance, you 
must pay any additional royalties due (plus interest computed under 
Sec. 218.302). You are entitled to a credit for or refund of any 
overpaid royalties.
    (f) If you commingled byproducts produced from Federal and non-
Federal leases for transportation, you may not disproportionately 
allocate transportation costs to Federal lease production.



Sec. 206.359  How do I determine byproduct transportation allowances?

    (a) For transportation costs you incur under an arm's-length 
contract, the transportation allowance will be the reasonable, actual 
costs you incurred for transporting the byproducts under that contract.
    (1) In conducting reviews and audits, MMS will examine whether the 
contract reflects more than the consideration actually transferred 
either directly or indirectly from you to the transporter for the 
transportation. If the contract reflects more than the total 
consideration you paid, MMS may require you to determine the byproduct 
transportation allowance under paragraph (b) of this section.
    (2) If MMS determines that the consideration you paid under an 
arm's-length byproduct transportation contract does not reflect the 
reasonable value of the transportation because of misconduct by or 
between the contracting parties, or because you otherwise have breached 
your duty to the lessor to market the production for the mutual benefit 
of the lessee and the lessor, MMS will require you to determine the 
byproduct transportation allowance under paragraph (b) of this section. 
When MMS determines that the value of the transportation may be 
unreasonable, MMS will notify you and give you an opportunity to provide 
written information justifying your transportation costs.
    (3) Where your payments for transportation under an arm's-length 
contract are not established on a dollars-per-unit basis, you must 
convert whatever consideration you paid to a dollar value equivalent for 
the purposes of this section.
    (b) If you transport the byproduct yourself or under a non-arm's-
length transportation arrangement, the byproduct transportation 
allowance is your reasonable actual costs for transportation during the 
reporting period, including:
    (1) Operating and maintenance expenses under paragraphs (d) and (e) 
of this section;

[[Page 145]]

    (2) Overhead under paragraph (f) of this section; and either
    (3) Depreciation under paragraphs (g) and (h) of this section and a 
return on undepreciated capital investment under paragraphs (g) and (i) 
of this section; or
    (4) A return on capital investment in the transportation system 
under paragraphs (g) and (j) of this section.
    (c)(1) Allowable capital costs under paragraph (b) of this section 
are generally those for depreciable fixed assets (including costs of 
delivery and installation of capital equipment) that are an integral 
part of the transportation system.
    (2)(i) You may include a return on capital you invested in the 
purchase of real estate to locate the byproduct transportation 
facilities if:
    (A) The purchase is necessary; and
    (B) The surface is not part of a Federal lease.
    (ii) The rate of return will be the same rate determined in 
paragraph (k) of this section.
    (3) You may not deduct the costs of gathering systems and other 
production-related facilities.
    (d) Allowable operating expenses include:
    (1) Operations supervision and engineering;
    (2) Operations labor;
    (3) Fuel;
    (4) Utilities;
    (5) Materials;
    (6) Ad valorem property taxes;
    (7) Rent;
    (8) Supplies; and
    (9) Any other directly allocable and attributable operating expense 
that you can document.
    (e) Allowable maintenance expenses include:
    (1) Maintenance of the transportation system;
    (2) Maintenance of equipment;
    (3) Maintenance labor; and
    (4) Other directly allocable and attributable maintenance expenses 
that you can document.
    (f) Overhead directly attributable and allocable to the operation 
and maintenance of the transportation system is an allowable expense. 
State and Federal income taxes and severance taxes and other fees, 
including royalties, are not allowable expenses.
    (g) To compute costs associated with capital investment, a lessee 
may use either paragraphs (h) and (i) or paragraph (j) of this section. 
After a lessee has elected to use either method for a transportation 
system, the lessee may not later elect to change to the other 
alternative without MMS approval.
    (h)(1) To compute depreciation, you must use a straight-line 
depreciation method based on either the life of the equipment or the 
life of the geothermal project which the transportation system services. 
After you choose the basis for depreciation, you may not change that 
basis without MMS approval. You may not depreciate equipment below a 
reasonable salvage value.
    (2) A change in ownership of a transportation system does not alter 
the depreciation schedule established by the original lessee-owner for 
purposes of computing transportation costs.
    (3) With or without a change in ownership, you may depreciate a 
transportation system only once.
    (i) To calculate a return on undepreciated capital investment, 
multiply the remaining undepreciated capital balance as of the beginning 
of the period for which you are calculating the transportation allowance 
by the rate of return provided in paragraph (k) of this section.
    (j) To compute a return on capital investment in the transportation 
system, the allowed cost will be the amount equal to the allowable 
capital investment in the transportation system multiplied by the rate 
of return determined pursuant to paragraph (k) of this section. There is 
no allowance for depreciation.
    (k) The rate of return must be the industrial rate associated with 
Standard & Poor's BBB rating. The BBB rate must be the monthly average 
rate as published in Standard & Poor's Bond Guide for the first month 
for which the allowance is applicable. You must redetermine the rate at 
the beginning of each subsequent calendar year.
    (l)(1) For new transportation facilities or arrangements, base your 
initial deduction on estimates of allowable byproduct transportation 
costs for the

[[Page 146]]

applicable period. Use the most recently available operations data for 
the transportation system or, if such data are not available, use 
estimates based on data for similar transportation systems.
    (2) When actual cost information is available, you must amend your 
prior Form MMS-2014 reports to reflect actual byproduct transportation 
cost deductions for each month for which you reported and paid based on 
estimated byproduct transportation costs. You must pay any additional 
royalties due (together with interest computed under Sec. 218.302). You 
are entitled to a credit for or a refund of any overpaid royalties.



Sec. 206.360  What records must I keep to support my calculations of royalty 

or fees under this subpart?

    If you determine royalties or direct use fees for your geothermal 
resource under this subpart, you must retain all data relevant to the 
determination of the royalty value or the fee you paid. Recordkeeping 
requirements are found at part 212 of this chapter.
    (a) You must be able to show:
    (1) How you calculated the royalty value or fee you reported, 
including all allowable deductions; and
    (2) How you complied with this subpart.
    (b) Upon request, you must submit all data to MMS. You must comply 
with any such requirement within the time MMS specifies.



Sec. 206.361  How will MMS determine whether my royalty or direct use fee 

payments are correct?

    (a)(1) The royalties or direct use fees that you report are subject 
to monitoring, review, and audit. The MMS may review and audit your 
data, and MMS will direct you to use a different measure of royalty 
value, gross proceeds, or fee, whichever is applicable, if it determines 
that the reported value, gross proceeds, or fee is inconsistent with the 
requirements of this subpart.
    (2) If MMS directs you to use a different royalty value, measure of 
gross proceeds, or fee, you must either pay any royalties or fees due 
(together with interest computed under Sec. 218.302) or report a credit 
for or request a refund of any overpaid royalties or fees.
    (b) When the provisions in this subpart refer to gross proceeds 
either for the sale of electricity or the sale of a geothermal resource, 
in conducting reviews and audits MMS will examine whether your sales 
contract reflects the total consideration actually transferred, either 
directly or indirectly, from the buyer to you for the geothermal 
resource or electricity. If MMS determines that a contract does not 
reflect the total consideration, or the gross proceeds accruing to you 
under a contract do not reflect reasonable consideration because of 
misconduct by or between the contracting parties, or because you 
otherwise have breached your duty to the lessor to market the production 
for the mutual benefit of the lessee and the lessor, MMS may require you 
to increase the gross proceeds to reflect any additional consideration. 
Alternatively, for Class I leases, MMS may require you to use another 
valuation method in the regulations applicable to dispositions other 
than under an arm's-length contract. The MMS will notify you to give you 
an opportunity to provide written information justifying your gross 
proceeds.
    (c) For arm's-length sales, you have the burden of demonstrating 
that your contract is arm's length.
    (d) The MMS may require you to certify that the provisions in your 
sales contract include all of the consideration the buyer paid you, 
either directly or indirectly, for the electricity or geothermal 
resource.
    (e) Notwithstanding any other provision of this subpart, under no 
circumstances will the value of production for royalty purposes under a 
Class I lease where the geothermal resources are sold before use be less 
than the gross proceeds accruing to you.
    (f) Gross proceeds for the sale of electricity or for the sale of 
the geothermal resource will be based on the highest price a prudent 
lessee can receive through legally enforceable claims under its 
contract.
    (1) Absent contract revision or amendment, if you fail to take 
proper or timely action to receive prices or benefits to which you are 
entitled, you

[[Page 147]]

must pay royalty based upon that obtainable price or benefit.
    (2) Contract revisions or amendments you make must be in writing and 
signed by all parties to the contract.
    (3) If you make timely application for a price increase or benefit 
allowed under your contract, but the purchaser refuses and you take 
reasonable measures, which are documented, to force purchaser 
compliance, you will owe no additional royalties unless or until you 
receive additional monies or consideration resulting from the price 
increase. This paragraph (f)(3) will not be construed to permit you to 
avoid your royalty payment obligation in situations where a purchaser 
fails to pay, in whole or in part or timely, for a quantity of 
geothermal resources or electricity.



Sec. 206.362  What are my responsibilities to place production into 

marketable condition and to market production?

    You must place geothermal resources and byproducts in marketable 
condition and market the geothermal resources or byproducts for the 
mutual benefit of the lessee and the lessor at no cost to the Federal 
Government. If you use gross proceeds under an arm's-length contract in 
determining royalty, you must increase those gross proceeds to the 
extent that the purchaser, or any other person, provides certain 
services that the seller normally would be responsible to perform to 
place the geothermal resources or byproducts in marketable condition or 
to market the geothermal resources or byproducts.



Sec. 206.363  When is an MMS audit, review, reconciliation, monitoring, or 

other like process considered final?

    Notwithstanding any provision in these regulations to the contrary, 
no audit, review, reconciliation, monitoring, or other like process that 
results in a redetermination by MMS of royalty or fees due under this 
subpart is considered final or binding as against the Federal Government 
or its beneficiaries until MMS formally closes the audit period in 
writing.



Sec. 206.364  How do I request a value or gross proceeds determination?

    (a) You may request a value determination from MMS regarding any 
geothermal resources produced from a Class I lease or for byproducts 
produced from a Class I, Class II, or Class III lease. You may also 
request a gross proceeds determination for a Class II or Class III 
lease. Your request must:
    (1) Be in writing;
    (2) Identify specifically all leases involved, all owners of 
interests in those leases, and the operator(s) for those leases;
    (3) Completely explain all relevant facts. You must inform MMS of 
any changes to relevant facts that occur before we respond to your 
request;
    (4) Include copies of all relevant documents;
    (5) Provide your analysis of the issue(s), including citations to 
all relevant precedents (including adverse precedents); and
    (6) Suggest your proposed gross proceeds calculation or valuation 
method.
    (b) In response to your request:
    (1) The Assistant Secretary, Land and Minerals Management, may issue 
a determination; or
    (2) The MMS may issue a determination; or
    (3) The MMS may inform you in writing that MMS will not provide a 
determination. Situations in which MMS typically will not provide any 
determination include, but are not limited to:
    (i) Requests for guidance on hypothetical situations; and
    (ii) Matters that are the subject of pending litigation or 
administrative appeals.
    (c)(1) A determination signed by the Assistant Secretary, Land and 
Minerals Management, is binding on both you and MMS until the Assistant 
Secretary modifies or rescinds it.
    (2) After the Assistant Secretary issues a determination, you must 
make any adjustments in royalty payments that follow from the 
determination and, if you owe additional royalties, pay the royalties 
owed together with late payment interest computed under Sec. 218.302.
    (3) A determination signed by the Assistant Secretary is the final 
action of

[[Page 148]]

the Department and is subject to judicial review under 5 U.S.C. 701-706.
    (d) A determination issued by MMS is binding on MMS and delegated 
States, but not on you, with respect to the specific situation addressed 
in the determination unless the MMS (for MMS-issued determinations) or 
the Assistant Secretary modifies or rescinds it.
    (1) A determination by MMS is not an appealable decision or order 
under 30 CFR part 290 subpart B.
    (2) If you receive an order requiring you to pay royalty on the same 
basis as the determination, you may appeal that order under 30 CFR part 
290 subpart B.
    (e) In making a determination, MMS or the Assistant Secretary may 
use any of the applicable criteria in this subpart.
    (f) A change in an applicable statute or regulation on which any 
determination is based takes precedence over the determination after the 
effective date of the statute or regulation, regardless of whether the 
MMS or the Assistant Secretary modifies or rescinds the determination.
    (g) The MMS or the Assistant Secretary generally will not 
retroactively modify or rescind a determination issued under paragraph 
(d) of this section, unless:
    (1) There was a misstatement or omission of material facts; or
    (2) The facts subsequently developed are materially different from 
the facts on which the guidance was based.
    (h) The MMS may make requests and replies under this section 
available to the public, subject to the confidentiality requirements 
under Sec. 206.365.



Sec. 206.365  Does MMS protect information I provide?

    Certain information you submit to MMS regarding royalties or fees on 
geothermal resources or byproducts, including deductions and allowances, 
may be exempt from disclosure. To the extent applicable laws and 
regulations permit, MMS will keep confidential any data you submit that 
is privileged, confidential, or otherwise exempt from disclosure. All 
requests for information must be submitted under the Freedom of 
Information Act regulations of the Department of the Interior at 43 CFR 
part 2.



Sec. 206.366  What is the nominal fee that a State, tribal, or local 

government lessee must pay for the use of geothermal resources?

    If a State, tribal, or local government lessee uses a geothermal 
resource without sale and for public purposes--other than commercial 
production or generation of electricity--the State, tribal, or local 
government lessee must pay a nominal fee. A nominal fee means a slight 
or de minimis fee. The MMS will determine the fee on a case-by-case 
basis.

Subpart I--OCS Sulfur [Reserved]



                          Subpart J_Indian Coal

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



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.
    (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.

[[Page 149]]

    Allowance means an approved, or an MMS-initially accepted deduction 
in determining value for royalty purposes. Coal washing allowance means 
an allowance for the reasonable, actual costs incurred by the lessee for 
coal washing, or an approved or MMS-initially accepted deduction for the 
costs of washing coal, determined pursuant to this subpart. 
Transportation allowance means an allowance for the reasonable, actual 
costs incurred by the lessee for moving coal to a point of sale or point 
of delivery remote from both the lease and mine or wash plant, or an 
approved MMS-initially accepted deduction for costs of such 
transportation, determined pursuant to this subpart.
    Area means a geographic region in which coal has similar quality and 
economic characteristics. Area boundaries are not officially designated 
and the areas are not necessarily named.
    Arm's-length contract means a contract or agreement that has been 
arrived at in the marketplace between independent, nonaffiliated persons 
with opposing economic interests regarding that contract. For purposes 
of this subpart, two persons are affiliated if one person controls, is 
controlled by, or is under common control with another person. For 
purposes of this subpart, based on the instruments of ownership of the 
voting securities of an entity, or based on other forms of ownership: 
ownership in excess of 50 percent constitutes control; ownership of 10 
through 50 percent creates a presumption of control; and ownership of 
less than 10 percent creates a presumption of noncontrol which MMS may 
rebut if it demonstrates actual or legal control, including the 
existence of interlocking directorates. Notwithstanding any other 
provisions of this subpart, contracts between relatives, either by blood 
or by marriage, are not arm's-length contracts. MMS may require the 
lessee to certify ownership control. To be considered arm's-length for 
any production month, a contract must meet the requirements of this 
definition for that production month, as well as when the contract was 
executed.
    Audit means a review, conducted in accordance with generally 
accepted accounting and auditing standards, of royalty payment 
compliance activities of lessees or other interest holders who pay 
royalties, rents, or bonuses on Indian leases.
    BIA means the Bureau of Indian Affairs of the Department of the 
Interior.
    BLM means the Bureau of Land Management of the Department of the 
Interior.
    Coal means coal of all ranks from lignite through anthracite.
    Coal washing means any treatment to remove impurities from coal. 
Coal washing may include, but is not limited to, operations such as 
flotation, air, water, or heavy media separation; drying; and related 
handling (or combination thereof).
    Contract means any oral or written agreement, including amendments 
or revisions thereto, between two or more persons and enforceable by law 
that with due consideration creates an obligation.
    Gross proceeds (for royalty payment purposes) means the total monies 
and other consideration accruing to a coal lessee for the production and 
disposition of the coal produced. Gross proceeds includes, but is not 
limited to, payments to the lessee for certain services such as 
crushing, sizing, screening, storing, mixing, loading, treatment with 
substances including chemicals or oils, and other preparation of the 
coal to the extent that the lessee is obligated to perform them at no 
cost to the Indian lessor. Gross proceeds, as applied to coal, also 
includes but is not limited to reimbursements for royalties, taxes or 
fees, and other reimbursements. Tax reimbursements are part of the gross 
proceeds accruing to a lessee even though the Indian royalty interest 
may be exempt from taxation. Monies and other consideration, including 
the forms of consideration identified in this paragraph, to which a 
lessee is contractually or legally entitled but which it does not seek 
to collect through reasonable efforts are also part of gross proceeds.
    Indian allottee means any Indian for whom land or an interest in 
land is held in trust by the United States or who holds title subject to 
Federal restriction against alienation.
    Indian Tribe means any Indian Tribe, band, nation, pueblo, 
community,

[[Page 150]]

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 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.

    For all leases subject to this subpart, the quantity of coal on 
which royalty is due shall be measured in short tons

[[Page 151]]

(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 Solid Minerals Production and Royalty Report, Form 
MMS-4430, as required under 30 CFR part 210.

[61 FR 5481, Feb. 12, 1996, as amended at 66 FR 45769, Aug. 30, 2001]



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, 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 
Sec. Sec. 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

[[Page 152]]

based on less than the gross proceeds accruing to the lessee for the 
coal production, including the additional consideration.
    (3) If MMS determines that the gross proceeds accruing to the lessee 
pursuant to an arm's-length contract do not reflect the reasonable value 
of the production because of misconduct by or between the contracting 
parties, or because the lessee otherwise has breached its duty to the 
lessor to market the production for the mutual benefit of the lessee and 
the lessor, then MMS shall require that the coal production be valued 
pursuant to paragraphs (c)(2)(ii), (c)(2)(iii), (c)(2)(iv), or (c)(2)(v) 
of this section, and in accordance with the notification requirements of 
paragraph (d)(3) of this section. When MMS determines that the value may 
be unreasonable, MMS will notify the lessee and give the lessee an 
opportunity to provide written information justifying the lessee's 
reported coal value.
    (4) MMS may require a lessee to certify that its arm's-length 
contract provisions include all of the consideration to be paid by the 
buyer, either directly or indirectly, for the coal production.
    (5) The value of production for royalty purposes shall not include 
payments received by the lessee pursuant to a contract which the lessee 
demonstrates, to MMS' satisfaction, were not part of the total 
consideration paid for the purchase of coal production.
    (c)(1) The value of coal from leases subject to this section and 
which is not sold pursuant to an arm's-length contract shall be 
determined in accordance with this section.
    (2) If the value of the coal cannot be determined pursuant to 
paragraph (b) of this section, then the value shall be determined 
through application of other valuation criteria. The criteria shall be 
considered in the following order, and the value shall be based upon the 
first applicable criterion:
    (i) The gross proceeds accruing to the lessee pursuant to a sale 
under its non-arm's-length contract (or other disposition of produced 
coal by other than an arm's-length contract), provided that those gross 
proceeds are within the range of the gross proceeds derived from, or 
paid under, comparable arm's-length contracts between buyers and sellers 
neither of whom is affiliated with the lessee for sales, purchases, or 
other dispositions of like-quality coal produced in the area. In 
evaluating the comparability of arm's-length contracts for the purposes 
of these regulations, the following factors shall be considered: price, 
time of execution, duration, market or markets served, terms, quality of 
coal, quantity, and such other factors as may be appropriate to reflect 
the value of the coal;
    (ii) Prices reported for that coal to a public utility commission;
    (iii) Prices reported for that coal to the Energy Information 
Administration of the Department of Energy;
    (iv) Other relevant matters including, but not limited to, published 
or publicly available spot market prices, or information submitted by 
the lessee concerning circumstances unique to a particular lease 
operation or the salability of certain types of coal;
    (v) If a reasonable value cannot be determined using paragraphs 
(c)(2)(i), (c)(2)(ii), (c)(2)(iii), or (c)(2)(iv) of this section, then 
a net-back method or any other reasonable method shall be used to 
determine value.
    (3) When the value of coal is determined pursuant to paragraph 
(c)(2) of this section, that value determination shall be consistent 
with the provisions contained in paragraph (b)(5) of this section.
    (d)(1) Where the value is determined pursuant to paragraph (c) of 
this section, that value does not require MMS' prior approval. However, 
the lessee shall retain all data relevant to the determination of 
royalty value. Such data shall be subject to review and audit, and MMS 
will direct a lessee to use a different value if it determines that the 
reported value is inconsistent with the requirements of these 
regulations.
    (2) An Indian lessee will make available upon request to the 
authorized MMS or Indian representatives, or to the Inspector General of 
the Department of the Interior or other persons authorized to receive 
such information, arm's-length sales and sales quantity data for like-
quality coal sold, purchased, or otherwise obtained by the lessee from 
the area.

[[Page 153]]

    (3) A lessee shall notify MMS if it has determined value pursuant to 
paragraphs (c)(2)(ii), (c)(2)(iii), (c)(2)(iv), or (c)(2)(v) of this 
section. The notification shall be by letter to the Associate Director 
for Minerals Revenue Management or his/her designee. The letter shall 
identify the valuation method to be used and contain a brief description 
of the procedure to be followed. The notification required by this 
section is a one-time notification due no later than the month the 
lessee first reports royalties on the Form MMS-4430 using a valuation 
method authorized by paragraphs (c)(2)(ii), (c)(2)(iii), (c)(2)(iv), or 
(c)(2)(v) of this section, and each time there is a change in a method 
under paragraphs (c)(2)(iv) or (c)(2)(v) of this section.
    (e) If MMS determines that a lessee has not properly determined 
value, the lessee shall be liable for the difference, if any, between 
royalty payments made based upon the value it has used and the royalty 
payments that are due based upon the value established by MMS. The 
lessee shall also be liable for interest computed pursuant to 30 CFR 
218.202. If the lessee is entitled to a credit, MMS will provide 
instructions for the taking of that credit.
    (f) The lessee may request a value determination from MMS. In that 
event, the lessee shall propose to MMS a value determination method, and 
may use that method in determining value for royalty purposes until MMS 
issues its decision. The lessee shall submit all available data relevant 
to its proposal. MMS shall expeditiously determine the value based upon 
the lessee's proposal and any additional information MMS deems 
necessary. That determination shall remain effective for the period 
stated therein. After MMS issues its determination, the lessee shall 
make the adjustments in accordance with paragraph (e) of this section.
    (g) Notwithstanding any other provisions of this section, under no 
circumstances shall the value for royalty purposes be less than the 
gross proceeds accruing to the lessee for the disposition of produced 
coal less applicable provisions of paragraph (b)(5) of this section and 
less applicable allowances determined pursuant to Sec. Sec. 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 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 Sec. Sec. 206.457 through 206.461 and Sec.  206.464 of

[[Page 154]]

this subpart, is exempted from disclosure by the Freedom of Information 
Act, 5 U.S.C. 522. Any data specified by the Act to be privileged, 
confidential, or otherwise exempt shall be maintained in a confidential 
manner in accordance with applicable law and regulations. All requests 
for information about determinations made under this part are to be 
submitted in accordance with the Freedom of Information Act regulation 
of the Department of the Interior, 43 CFR part 2. Nothing in this 
section is intended to limit or diminish in any manner whatsoever the 
right of an Indian lessor to obtain any and all information as such 
lessor may be lawfully entitled from MMS or such lessor's lessee 
directly under the terms of the lease or applicable law.

[61 FR 5481, Feb. 12, 1996, as amended at 66 FR 45769, Aug. 30, 2001]



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.
    (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

[[Page 155]]

information justifying the lessee's washing costs.
    (4) Where the lessee's payments for washing under an arm's-length 
contract are not based on a dollar-per-unit basis, the lessee shall 
convert whatever consideration is paid to a dollar value equivalent. 
Washing allowances shall be expressed as a cost per ton of coal washed.
    (b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length contract or has no contract, including those situations 
where the lessee performs washing for itself, the washing allowance will 
be based upon the lessee's reasonable actual costs. All washing 
allowances deducted under a non-arm's-length or no contract situation 
are subject to monitoring, review, audit, and possible future 
adjustment. Prior MMS approval of washing allowances is not required for 
non-arm's-length or no contract situations. However, before any 
estimated or actual deduction may be taken, the lessee must submit a 
completed Form MMS-4292 in accordance with paragraph (c)(2) of this 
section. A washing allowance may be claimed retroactively for a period 
of not more than 3 months prior to the first day of the month that Form 
MMS-4292 is filed with MMS, unless MMS approves a longer period upon a 
showing of good cause by the lessee. MMS will monitor the allowance 
deduction to ensure that deductions are reasonable and allowable. When 
necessary or appropriate, MMS may direct a lessee to modify its actual 
washing allowance.
    (2) The washing allowance for non-arm's-length or no contract 
situations shall be based upon the lessee's actual costs for washing 
during the reported period, including operating and maintenance 
expenses, overhead, and either depreciation and a return on 
undepreciated capital investment in accordance with paragraph 
(b)(2)(iv)(A) of this section, or a cost equal to the depreciable 
investment in the wash plant multiplied by the rate of return in 
accordance with paragraph (b)(2)(iv)(B) of this section. Allowable 
capital costs are generally those for depreciable fixed assets 
(including costs of delivery and installation of capital equipment) 
which are an integral part of the wash plant.
    (i) Allowable operating expenses include: Operations supervision and 
engineering; operations labor; fuel; utilities; materials; ad valorem 
property taxes; rent; supplies; and any other directly allocable and 
attributable operating expense which the lessee can document.
    (ii) Allowable maintenance expenses include: Maintenance of the wash 
plant; maintenance of equipment; maintenance labor; and other directly 
allocable and attributable maintenance expenses which the lessee can 
document.
    (iii) Overhead attributable and allocable to the operation and 
maintenance of the wash plant is an allowable expense. State and Federal 
income taxes and severance taxes, including royalties, are not allowable 
expenses.
    (iv) A lessee may use either paragraph (b)(2)(iv)(A) or 
(b)(2)(iv)(B) of this section. After a lessee has elected to use either 
method for a wash plant, the lessee may not later elect to change to the 
other alternative without approval of MMS.
    (A) To compute depreciation, the lessee may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the wash plant services, whichever is 
appropriate, or a unit of production method. After an election is made, 
the lessee may not change methods without MMS approval. A change in 
ownership of a wash plant shall not alter the depreciation schedule 
established by the original operator/lessee for purposes of the 
allowance calculation. With or without a change in ownership, a wash 
plant shall be depreciated only once. Equipment shall not be depreciated 
below a reasonable salvage value.
    (B) MMS shall allow as a cost an amount equal to the allowable 
capital investment in the wash plant multiplied by the rate of return 
determined pursuant to paragraph (b)(2)(v) of this section. No allowance 
shall be provided for depreciation. This alternative shall apply only to 
plants first placed in service or acquired after March 1, 1989.
    (v) The rate of return shall be the industrial rate associated with 
Standard

[[Page 156]]

and Poor's BBB rating. The rate of return shall be the monthly average 
rate as published in Standard and Poor's Bond Guide for the first month 
of the reporting period for which the allowance is applicable and shall 
be effective during the reporting period. The rate shall be redetermined 
at the beginning of each subsequent washing allowance reporting period 
(which is determined pursuant to paragraph (c)(2) of this section).
    (3) The washing allowance for coal shall be determined based on the 
lessee's reasonable and actual cost of washing the coal. The lessee may 
not take an allowance for the costs of washing lease production that is 
not royalty bearing.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) With the 
exception of those washing allowances specified in paragraphs (c)(1)(v) 
and (c)(1)(vi) of this section, the lessee shall submit page one of the 
initial Form MMS-4292 prior to, or at the same time, as the washing 
allowance determined pursuant to an arm's-length contract is reported on 
Form MMS-4430, Solid Minerals Production and Royalty Report. A Form MMS-
4292 received by the end of the month that the Form MMS-4430 is due 
shall be considered to be received timely.
    (ii) The initial Form MMS-4292 shall be effective for a reporting 
period beginning the month that the lessee is first authorized to deduct 
a washing allowance and shall continue until the end of the calendar 
year, or until the applicable contract or rate terminates or is modified 
or amended, whichever is earlier.
    (iii) After the initial reporting period and for succeeding 
reporting periods, lessees must submit page one of Form MMS-4292 within 
3 months after the end of the calendar year, or after the applicable 
contract or rate terminates or is modified or amended, whichever is 
earlier, unless MMS approves a longer period (during which period the 
lessee shall continue to use the allowance from the previous reporting 
period).
    (iv) MMS may require that a lessee submit arm's-length washing 
contracts and related documents. Documents shall be submitted within a 
reasonable time, as determined by MMS.
    (v) Washing allowances which are based on arm's-length contracts and 
which are in effect at the time these regulations become effective will 
be allowed to continue until such allowances terminate. For the purposes 
of this section, only those allowances that have been approved by MMS in 
writing shall qualify as being in effect at the time these regulations 
become effective.
    (vi) MMS may establish, in appropriate circumstances, reporting 
requirements that are different from the requirements of this section.
    (2) Non-arm's-length or no contract. (i) With the exception of those 
washing allowances specified in paragraphs (c)(2)(v) and (c)(2)(vii) of 
this section, the lessee shall submit an initial Form MMS-4292 prior to, 
or at the same time as, the washing allowance determined pursuant to a 
non-arm's-length contract or no contract situation is reported on Form 
MMS-4430, Solid Minerals Production and Royalty Report. A Form MMS-4292 
received by the end of the month that the Form MMS-4430 is due shall be 
considered to be timely received. The initial reporting may be based on 
estimated costs.
    (ii) The initial Form MMS-4292 shall be effective for a reporting 
period beginning the month that the lessee first is authorized to deduct 
a washing allowance and shall continue until the end of the calendar 
year, or until the washing under the non-arm's-length contract or the no 
contract situation terminates, whichever is earlier.
    (iii) For calendar-year reporting periods succeeding the initial 
reporting period, the lessee shall submit a completed Form MMS-4292 
containing the actual costs for the previous reporting period. If coal 
washing is continuing, the lessee shall include on Form MMS-4292 its 
estimated costs for the next calendar year. The estimated coal washing 
allowance shall be based on the actual costs for the previous period 
plus or minus any adjustments which are based on the lessee's knowledge 
of decreases or increases which will affect the allowance. Form MMS-4292 
must be received by MMS within 3 months after the end of the previous 
reporting period, unless MMS approves a longer period (during which 
period the lessee

[[Page 157]]

shall continue to use the allowance from the previous reporting period).
    (iv) For new wash plants, the lessee's initial Form MMS-4292 shall 
include estimates of the allowable coal washing costs for the applicable 
period. Cost estimates shall be based upon the most recently available 
operations data for the plant, or if such data are not available, the 
lessee shall use estimates based upon industry data for similar coal 
wash plants.
    (v) Washing allowances based on non-arm's-length or no contract 
situations which are in effect at the time these regulations become 
effective will be allowed to continue until such allowances terminate. 
For the purposes of this section, only those allowances that have been 
approved by MMS in writing shall qualify as being in effect at the time 
these regulations become effective.
    (vi) Upon request by MMS, the lessee shall submit all data used by 
the lessee to prepare its Forms MMS-4292. The data shall be provided 
within a reasonable period of time, as determined by MMS.
    (vii) MMS may establish, in appropriate circumstances, reporting 
requirements which are different from the requirements of this section.
    (3) MMS may establish coal washing allowance reporting dates for 
individual leases different from those specified in this subpart in 
order to provide more effective administration. Lessees will be notified 
of any change in their reporting period.
    (4) Washing allowances must be reported as a separate line on the 
Form MMS-4430, unless MMS approves a different reporting procedure.
    (d) Interest assessments for incorrect or late reports and failure 
to report. (1) If a lessee deducts a washing allowance on its Form MMS-
4430 without complying with the requirements of this section, the lessee 
shall be liable for interest on the amount of such deduction until the 
requirements of this section are complied with. The lessee also shall 
repay the amount of any allowance which is disallowed by this section.
    (2) If a lessee erroneously reports a washing allowance which 
results in an underpayment of royalties, interest shall be paid on the 
amount of that underpayment.
    (3) Interest required to be paid by this section shall be determined 
in accordance with 30 CFR 218.202.
    (e) Adjustments. (1) If the actual coal washing allowance is less 
than the amount the lessee has taken on Form MMS-4430 for each month 
during the allowance form reporting period, the lessee shall be required 
to pay additional royalties due plus interest computed pursuant to 30 
CFR 218.202, retroactive to the first month the lessee is authorized to 
deduct a washing allowance. If the actual washing allowance is greater 
than the amount the lessee has estimated and taken during the reporting 
period, the lessee shall be entitled to a credit, without interest.
    (2) The lessee must submit a corrected Form MMS-4430 to reflect 
actual costs, together with any payment, in accordance with instructions 
provided by MMS.
    (f) Other washing cost determinations. The provisions of this 
section shall apply to determine washing costs when establishing value 
using a net-back valuation procedure or any other procedure that 
requires deduction of washing costs.

[61 FR 5481, Feb. 12, 1996, as amended at 66 FR 45769, Aug. 30, 2001]



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.

[[Page 158]]



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 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

[[Page 159]]

and give the lessee an opportunity to provide written information 
justifying the lessee's transportation costs.
    (4) Where the lessee's payments for transportation under an arm's-
length contract are not based on a dollar-per-unit basis, the lessee 
shall convert whatever consideration is paid to a dollar value 
equivalent for the purposes of this section.
    (b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length contract or has no contract, including those situations 
where the lessee performs transportation services for itself, the 
transportation allowance will be based upon the lessee's reasonable 
actual costs. All transportation allowances deducted under a non-arm's-
length or no contract situation are subject to monitoring, review, 
audit, and possible future adjustment. Prior MMS approval of 
transportation allowances is not required for non-arm's-length or no 
contract situations. However, before any estimated or actual deduction 
may be taken, the lessee must submit a completed Form MMS-4293 in 
accordance with paragraph (c)(2) of this section. A transportation 
allowance may be claimed retroactively for a period of not more than 3 
months prior to the first day of the month that Form MMS-4293 is filed 
with MMS, unless MMS approves a longer period upon a showing of good 
cause by the lessee. MMS will monitor the allowance deductions to ensure 
that deductions are reasonable and allowable. When necessary or 
appropriate, MMS may direct a lessee to modify its estimated or actual 
transportation allowance deduction.
    (2) The transportation allowance for non-arm's-length or no contract 
situations shall be based upon the lessee's actual costs for 
transportation during the reporting period, including operating and 
maintenance expenses, overhead, and either depreciation and a return on 
undepreciated capital investment in accordance with paragraph 
(b)(2)(iv)(A) of this section, or a cost equal to the depreciable 
investment in the transportation system multiplied by the rate of return 
in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable 
capital costs are generally those for depreciable fixed assets 
(including costs of delivery and installation of capital equipment) 
which are an integral part of the transportation system.
    (i) Allowable operating expenses include: Operations supervision and 
engineering; operations labor; fuel; utilities; materials; ad valorem 
property taxes; rent; supplies; and any other directly allocable and 
attributable operating expense which the lessee can document.
    (ii) Allowable maintenance expenses include: Maintenance of the 
transportation system; maintenance of equipment; maintenance labor; and 
other directly allocable and attributable maintenance expenses which the 
lessee can document.
    (iii) Overhead attributable and allocable to the operation and 
maintenance of the transportation system is an allowable expense. State 
and Federal income taxes and severance taxes and other fees, including 
royalties, are not allowable expenses.
    (iv) A lessee may use either paragraph (b)(2)(iv)(A) or paragraph 
(b)(2)(iv)(B) of this section. After a lessee has elected to use either 
method for a transportation system, the lessee may not later elect to 
change to the other alternative without approval of MMS.
    (A) To compute depreciation, the lessee may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the transportation system services, 
whichever is appropriate, or a unit of production method. After an 
election is made, the lessee may not change methods without MMS 
approval. A change in ownership of a transportation system shall not 
alter the depreciation schedule established by the original transporter/
lessee for purposes of the allowance calculation. With or without a 
change in ownership, a transportation system shall be depreciated only 
once. Equipment shall not be depreciated below a reasonable salvage 
value.
    (B) MMS shall allow as a cost an amount equal to the allowable 
capital investment in the transportation system multiplied by the rate 
of return determined pursuant to paragraph

[[Page 160]]

(b)(2)(B)(v) of this section. No allowance shall be provided for 
depreciation. This alternative shall apply only to transportation 
facilities first placed in service or acquired after March 1, 1989.
    (v) The rate of return shall be the industrial rate associated with 
Standard and Poor's BBB rating. The rate of return shall be the monthly 
average as published in Standard and Poor's Bond Guide for the first 
month of the reporting period of which the allowance is applicable and 
shall be effective during the reporting period. The rate shall be 
redetermined at the beginning of each subsequent transportation 
allowance reporting period (which is determined pursuant to paragraph 
(c)(2) of this section).
    (3) A lessee may apply to MMS for exception from the requirement 
that it compute actual costs in accordance with paragraphs (b)(1) and 
(b)(2) of this section. MMS will grant the exception only if the lessee 
has a rate for the transportation approved by a Federal agency for 
Indian leases. MMS shall deny the exception request if it determines 
that the rate is excessive as compared to arm's-length transportation 
charges by systems, owned by the lessee or others, providing similar 
transportation services in that area. If there are no arm's-length 
transportation charges, MMS shall deny the exception request if:
    (i) No Federal regulatory agency cost analysis exists and the 
Federal regulatory agency has declined to investigate pursuant to MMS 
timely objections upon filing; and
    (ii) The rate significantly exceeds the lessee's actual costs for 
transportation as determined under this section.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) With the 
exception of those transportation allowances specified in paragraphs 
(c)(1)(v) and (c)(1)(vi) of this section, the lessee shall submit page 
one of the initial Form MMS-4293 prior to, or at the same time as, the 
transportation allowance determined pursuant to an arm's-length contract 
is reported on Form MMS-4430, Solid Minerals Production and Royalty 
Report.
    (ii) The initial Form MMS-4293 shall be effective for a reporting 
period beginning the month that the lessee is first authorized to deduct 
a transportation allowance and shall continue until the end of the 
calendar year, or until the applicable contract or rate terminates or is 
modified or amended, whichever is earlier.
    (iii) After the initial reporting period and for succeeding 
reporting periods, lessees must submit page one of Form MMS-4293 within 
3 months after the end of the calendar year, or after the applicable 
contract or rate terminates or is modified or amended, whichever is 
earlier, unless MMS approves a longer period (during which period the 
lessee shall continue to use the allowance from the previous reporting 
period). Lessees may request special reporting procedures in unique 
allowance reporting situations, such as those related to spot sales.
    (iv) MMS may require that a lessee submit arm's-length 
transportation contracts, production agreements, operating agreements, 
and related documents. Documents shall be submitted within a reasonable 
time, as determined by MMS.
    (v) Transportation allowances that are based on arm's-length 
contracts and which are in effect at the time these regulations become 
effective will be allowed to continue until such allowances terminate. 
For the purposes of this section, only those allowances that have been 
approved by MMS in writing shall qualify as being in effect at the time 
these regulations become effective.
    (vi) MMS may establish, in appropriate circumstances, reporting 
requirements that are different from the requirements of this section.
    (2) Non-arm's-length or no contract. (i) With the exception of those 
transportation allowances specified in paragraphs (c)(2)(v) and 
(c)(2)(vii) of this section, the lessee shall submit an initial Form 
MMS-4293 prior to, or at the same time as, the transportation allowance 
determined pursuant to a non-arm's-length contract or no contract 
situation is reported on Form MMS-4430, Solid Minerals Production and 
Royalty Report. The initial report may be based on estimated costs.
    (ii) The initial Form MMS-4293 shall be effective for a reporting 
period beginning the month that the lessee first

[[Page 161]]

is authorized to deduct a transportation allowance and shall continue 
until the end of the calendar year, or until the transportation under 
the non-arm's-length contract or the no contract situation terminates, 
whichever is earlier.
    (iii) For calendar-year reporting periods succeeding the initial 
reporting period, the lessee shall submit a completed Form MMS-4293 
containing the actual costs for the previous reporting period. If the 
transportation is continuing, the lessee shall include on Form MMS-4293 
its estimated costs for the next calendar year. The estimated 
transportation allowance shall be based on the actual costs for the 
previous reporting period plus or minus any adjustments that are based 
on the lessee's knowledge of decreases or increases that will affect the 
allowance. Form MMS-4293 must be received by MMS within 3 months after 
the end of the previous reporting period, unless MMS approves a longer 
period (during which period the lessee shall continue to use the 
allowance from the previous reporting period).
    (iv) For new transportation facilities or arrangements, the lessee's 
initial Form MMS-4293 shall include estimates of the allowable 
transportation costs for the applicable period. Cost estimates shall be 
based upon the most recently available operations data for the 
transportation system, or, if such data are not available, the lessee 
shall use estimates based upon industry data for similar transportation 
systems.
    (v) Non-arm's-length contract or no contract-based transportation 
allowances that are in effect at the time these regulations become 
effective will be allowed to continue until such allowances terminate. 
For purposes of this section, only those allowances that have been 
approved by MMS in writing shall qualify as being in effect at the time 
these regulations become effective.
    (vi) Upon request by MMS, the lessee shall submit all data used to 
prepare its Form MMS-4293. The data shall be provided within a 
reasonable period of time, as determined by MMS.
    (vii) MMS may establish, in appropriate circumstances, reporting 
requirements that are different from the requirements of this section.
    (viii) If the lessee is authorized to use its Federal-agency-
approved rate as its transportation cost in accordance with paragraph 
(b)(3) of this section, it shall follow the reporting requirements of 
paragraph (c)(1) of this section.
    (3) MMS may establish reporting dates for individual lessees 
different than those specified in this paragraph in order to provide 
more effective administration. Lessees will be notified as to any change 
in their reporting period.
    (4) Transportation allowances must be reported as a separate line 
item on Form MMS-4430, unless MMS approves a different reporting 
procedure.
    (d) Interest assessments for incorrect or late reports and failure 
to report. (1) If a lessee deducts a transportation allowance on its 
Form MMS-4430 without complying with the requirements of this section, 
the lessee shall be liable for interest on the amount of such deduction 
until the requirements of this section are complied with. The lessee 
also shall repay the amount of any allowance which is disallowed by this 
section.
    (2) If a lessee erroneously reports a transportation allowance which 
results in an underpayment of royalties, interest shall be paid on the 
amount of that underpayment.
    (3) Interest required to be paid by this section shall be determined 
in accordance with 30 CFR 218.202.
    (e) Adjustments. (1) If the actual transportation allowance is less 
than the amount the lessee has taken on Form MMS-4430 for each month 
during the allowance form reporting period, the lessee shall be required 
to pay additional royalties due plus interest, computed pursuant to 30 
CFR 218.202, retroactive to the first month the lessee is authorized to 
deduct a transportation allowance. If the actual transportation 
allowance is greater than the amount the lessee has estimated and taken 
during the reporting period, the lessee shall be entitled to a credit, 
without interest.
    (2) The lessee must submit a corrected Form MMS-4430 to reflect 
actual costs, together with any payment,

[[Page 162]]

in accordance with instructions provided by MMS.
    (f) Other transportation cost determinations. The provisions of this 
section shall apply to determine transportation costs when establishing 
value using a net-back valuation procedure or any other procedure that 
requires deduction of transportation costs.

[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999; 66 
FR 45769, Aug. 30, 2001]



Sec. 206.462  [Reserved]



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 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

[[Page 163]]

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.



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.

[[Page 164]]

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.
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).

[[Page 165]]

    DOI means the Department of the Interior, including the Secretary or 
his or her delegate(s).
    Eligible refiner means a refiner of crude oil that meets the 
following criteria for eligibility to purchase royalty oil:
    (1) For the purchase of royalty oil from onshore leases, it means a 
refiner that qualifies as a small and independent refiner as those terms 
are defined in sections 3(3) and 3(4) of the Emergency Petroleum 
Allocation Act, 15 U.S.C. 751 et seq., except that the time period for 
determination contained in section 3(3)(A) would be the calendar quarter 
immediately preceding the date of the applicable ``Notice of 
Availability of Royalty Oil.'' A refiner that, together with all persons 
controlled by, in control of, under common control with, or otherwise 
affiliated with the refiner, inputs a volume of domestic crude oil from 
its own production exceeding 30 percent of its total refinery input of 
crude oil is ineligible to participate in royalty oil sales under this 
part. Crude oil received in exchange for such refiner's own production 
is considered to be that refiner's own production for purposes of this 
section.
    (2) For the purchase of royalty oil from leases on the OCS, it means 
a refiner that qualifies as a small business enterprise under the rules 
of the Small Business Administration (13 CFR part 121).
    Entitlement means the volume of royalty oil from the Federal 
Government's share of production from a Federal lease which a purchaser 
is entitled to receive under a royalty oil contract.
    Exchange agreement means a written agreement between the purchaser 
and another person for the exchange of royalty oil purchased under this 
part for other oil on a volume or equivalent value basis.
    Fair market value means the value of oil--(1) Computed at a unit 
price equivalent to the average unit price at which oil was sold 
pursuant to a lease during the period for which any royalty or net 
profit share is accrued or reserved to the United States pursuant to 
such lease, or
    (2) If there were no such sales, or if the Secretary finds that 
there were an insufficient number of such sales to equitably determine 
such value, computed at the average unit price at which oil was sold 
pursuant to other leases in the same region of the OCS during such 
period, or
    (3) If there were no sales of oil from such region during such 
period, or if the Secretary finds that there are an insufficient number 
of such sales to equitably determine such value, at an appropriate price 
determined by the Secretary.
    Federal lease means a contractual agreement with the Federal 
Government which authorizes the exploration, development, and production 
of oil and gas on Federal lands onshore or on the OCS.
    Interim sale means a sale conducted as a result of substantial 
additional royalty oil becoming available in a specific area prior to 
the scheduled expiration date of royalty oil contracts in effect for 
that area.
    Lessee means any person to whom the United States issues a lease, or 
any person who has been assigned an obligation to make royalty or other 
payments required by the lease.
    MMS means the Minerals Management Service of the Department of the 
Interior.
    Notice of Availability of Royalty Oil means a notice published by 
DOI in the Federal Register (and in other printed media when 
appropriate, such as a newspaper or magazine of general or specialized 
circulation) to advise interested parties of the availability of royalty 
oil for purchase by eligible refiners and the approximate volume of 
royalty oil available to the applicants.
    OCS means the Outer Continental Shelf, as defined in 43 U.S.C. 
1331(a).
    OCSLA means the Outer Continental Shelf Lands Act (43 U.S.C. 1331 et 
seq., as amended by 43 U.S.C. 1801 et seq.).
    Oil means a mixture of hydrocarbons that existed in the liquid phase 
in natural underground reservoirs and remains liquid at atmospheric 
pressure after passing through surface separating facilities and is 
marketed or used as such. Condensate recovered in lease separators or 
field facilities is considered to be oil.
    Operator means any person, including a lessee, who has control of or 
who

[[Page 166]]

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.
    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.

[[Page 167]]

    (3) An eligible refiner must have a representative at a sale in 
order to participate. The Secretary may, at his or her discretion, 
establish purchase limitations and withhold any royalty oil from any 
offering.
    (c) Upon a determination by the Secretary under paragraph (a) of 
this section that eligible refiners do have access to adequate supplies 
of crude oil at equitable prices, MMS will not take royalties in kind 
from oil and gas leases for exclusive sale to such refiners. Such 
determinations may be made on a regional basis.
    (d) Interim sales. The MMS generally will not conduct interim sales. 
However, interim sales may be held at the discretion of the Secretary if 
substantial addition royalty oil becomes available. The potentially 
eligible refiners, individually or collectively, must submit 
documentation demonstrating that adequate supplies of crude oil at 
equitable prices are not available for purchase. Although sufficient 
documentation must be submitted, it is not mandatory for each 
potentially eligible refiner to participate in a submission of such 
documentation to be determined eligible. The documentation must be 
submitted to MMS for a determination as to whether an interim sale is 
needed.

[52 FR 41913, Oct. 30, 1987, as amended at 66 FR 28657, May 24, 2001]



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.

[[Page 168]]

    (4) Identification of the locations (area/region and State) where 
the applicant proposes to purchase royalty oil, the volume of oil 
requested, and the specific refineries in which the oil will be refined.
    (5) A certification from the applicant that it is an eligible 
refiner for the purchase of Government royalty oil, as defined in 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

[[Page 169]]

October 1969 or from section 6 leases at a delivery point to be 
designated by the lessee. If the delivery point is on or immediately 
adjacent to the lease, the royalty oil will be delivered without cost to 
the Federal Government as an undivided portion of production in 
marketable condition at pipeline connections or other facilities 
provided by the lessee, unless other arrangements are approved by MMS. 
If the delivery point is not on or immediately adjacent to the lease, 
MMS will reimburse the lessee for the reasonable cost of transportation 
to such point in an amount not to exceed the transportation allowance 
determined pursuant to 30 CFR part 206. The MMS will include such 
transportation costs in the price charged for the oil taken in kind to 
reflect the value of the oil at the delivery point. Arrangements for 
delivery of the royalty oil from, or exchange of the oil at, the 
delivery point, and related transportation costs, are the responsibility 
of the purchaser of the royalty oil. In addition, quality differentials 
between the royalty oil to which a purchaser is entitled and the oil 
which is made available at the delivery point are matters to be resolved 
between the purchaser and the operator.
    (c) When the purchaser has physical access to the royalty oil at the 
delivery point, the lessee shall deliver such oil in marketable 
condition at pipeline connections or other facilities designated by MMS. 
If the lessee is unable to provide the royalty portion of actual 
production from the lease, the lessee must provide crude oil to the 
purchaser which is equivalent in volume or value to the royalty oil to 
which the purchaser is entitled. The lessee will deliver the royalty oil 
to the purchaser during normal operating hours and in reasonable 
quantities and intervals. The lessee will make available and the 
purchaser will accept delivery of the royalty oil entitlement no later 
than the last day of the calendar month immediately following the 
calendar month in which the oil was produced. Failure to accept 
deliveries shall constitute grounds for the termination of the contract.
    (d) Upon termination of deliveries under a royalty oil contract, the 
transportation allowance and delivery point designation authorized by 
this section no longer will remain in effect.



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

[[Page 170]]

royalty oil deliveries will be discontinued on terminated contracts.
    (e) A purchaser cannot transfer, assign, or sell its rights or 
interest in a royalty oil contract without written approval of the 
Director, MMS. If the purchaser changes ownership or its assets are sold 
or liquidated for any reason, it cannot transfer, assign, or sell its 
rights or interest in the royalty oil contract without written approval 
of the Director, MMS. Without express written consent from MMS for a 
change in ownership, the royalty oil contract shall be terminated. The 
successor company must meet the definition of an eligible refiner in 
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

[[Page 171]]

are the result of the payor's late or underreporting, or for adjustments 
reported by the payor, or made as a result of audit, reconciliation, or 
other procedures. The interest for late payment and underpayment will be 
assessed pursuant to 30 CFR 218.54.
    (c) If payment for royalty oil is not received by the due date 
specified in the contract, a notice of nonreceipt will be sent to the 
purchaser by certified mail. If payment is not received by MMS within 15 
days from the date of such notice, MMS may cancel the contract and 
collect under the MMS-specified surety instrument. See 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.

[[Page 172]]

Subpart C--Federal and Indian Oil [Reserved]

Subpart D--Federal and Indian Gas [Reserved]

                    Subpart E_Solid Minerals, General

210.200 What is the purpose of this subpart?
210.201 How do I submit Form MMS-4430, Solid Minerals Production and 
          Royalty Report?
210.202 How do I submit sales summaries?
210.203 How do I submit sales contracts?
210.204 How do I submit facility data?
210.205 Will I need to submit additional documents or evidence to MMS?
210.206 How will information submissions be kept confidential?

Subpart F--Coal [Reserved]

Subpart G--Other Solid Minerals [Reserved]

                     Subpart H_Geothermal Resources

210.350 Definitions.
210.351 Required recordkeeping.
210.352 Special forms and reports.
210.353 Monthly report of sales and royalty.
210.354 Reporting instructions.

Subpart I--OCS Sulfur [Reserved]

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



                      Subpart A_General Provisions



Sec. 210.10  Information collection.

    (a) Forms--This section identifies required MMS Minerals Revenue 
Management 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-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 day   1010-0040
 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-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-4430 and annually thereafter if the allowance does not
 change.....................................................
MMS-4293--Coal Transportation Allowance Report--Due prior to   1010-0074
 or at the same time that the allowance is first reported on
 Form MMS-4430 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...........
MMS-4430--Solid Minerals Production and Royalty Report--Due    1010-0120
 by the end of the month following the month of production
 or sale and for other lease financial obligations no later
 than the payment date specified in your lease..............
Facility Data--Due monthly or as requested for specific        1010-0120
 solid mineral products and lease types; see Sec.  210.204.
Sales Contracts--Due semi-annually or as requested on          1010-0120
 certain solid mineral products and lease types; see Sec.
 210.203....................................................

[[Page 173]]

 
Sales Summaries--Due monthly or as requested for specific      1010-0120
 solid mineral products and lease types; see Sec.  210.202.
------------------------------------------------------------------------


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 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, Minerals Revenue Management, P.O. Box 
5760, Denver, Colorado 80217-5760. The completed Form MMS-2014 should be 
mailed to the Minerals Management Service, Minerals Revenue Management, 
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 should be addressed to the Minerals 
Management Service, Minerals Revenue Management, 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, or MMS-4061 should be 
addressed to the Minerals Management Service, Minerals Revenue 
Management, 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, Minerals Revenue Management, P.O. 
Box 25165, Denver, Colorado 80225-0165. The completed allowance forms 
should be mailed to the Minerals Management Service, Minerals Revenue 
Management, P.O. Box 5200, Denver, Colorado 80217-5200.
    (5) Requests for Form MMS-4280 should be addressed to the Minerals 
Management Service, Minerals Revenue Management, 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) If you are not reporting Form MMS-4430 electronically, you may 
request blank copies of the form by calling 1-888-201-6416. You must 
submit completed Forms MMS-4430 to the address given in Sec. 
210.201(c).
    (7) If you are not reporting solid minerals sales contracts, sales 
summaries, and facility data electronically, you must submit paper 
copies to the address given in Sec. 210.202(c).
    (8) Reports for oil, gas, and geothermal leases sent by special 
courier or overnight mail (excluding U.S. Postal Service Express Mail) 
should be addressed to: Minerals Management Service, Minerals Revenue 
Management, Building 85, Room A-614, Denver Federal Center, 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

[[Page 174]]

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 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-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.
    (5) 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.
    (6) 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.
    (7) 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.
    (8) 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.
    (9) MMS-4058--Submitted monthly by operators of the facilities and 
measurement points where production from a Federal or Indian lease is 
commingled

[[Page 175]]

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.
    (10) 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.
    (11) 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.
    (12) 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.
    (13) 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.
    (14) 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, 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.
    (15) MMS-4293--Used to claim an allowance for the reasonable, actual

[[Page 176]]

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.
    (16) 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.
    (17) 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.
    (18) MMS-4430--Submitted monthly to report production from and 
royalty due on all Federal and Indian solid minerals leases (see Sec. 
210.201). MMS uses the data to distribute payments to appropriate 
recipients and to determine if lessees properly paid lease obligations. 
Public reporting burden is estimated to be 20 minutes per month per 
reporter. Comments relating to this information collection should 
reference OMB Control Number 1010-0120.
    (19) Facility data--Submitted monthly by operators of wash plant, 
refining, ore concentration, or other processing facilities for specific 
solid minerals produced from specific Federal and Indian lease types or 
when otherwise requested by MMS (see Sec. 210.204). MMS uses the data 
to assure that Federal or Indian lease processed production (the output 
of process plants) is consistent with the input of raw production. 
Public reporting burden is estimated to be approximately 15 minutes per 
reporter per month to compile in-house formatted information and submit 
that information electronically. Comments relating to this information 
collection should reference OMB Control Number 1010-0120.
    (20) Sales contracts--Submitted semi-annually by producers of 
specific solid mineral products on specific Federal and Indian lease 
types or when otherwise requested by MMS (see Sec. 210.203). MMS uses 
contracts, agreements and contract amendments for compliance purposes 
including, but not limited to, identifying valuation issues and 
establishing selling arrangement relationships. Public reporting burden 
is estimated to be 2 hours per reporter per year to compile and submit 
contracts and contract amendments. Comments relating to this information 
collection should reference OMB Control Number 1010-0120.
    (21) Sales summaries--Submitted monthly by producers of specific 
solid minerals from specific Federal and Indian lease types or when 
otherwise requested by MMS (see Sec. 210.202). The MMS uses these data 
for compliance purposes including, but not limited to, assuring that 
sales volumes and values

[[Page 177]]

are properly attributed or allocated to Federal or Indian leases. Public 
reporting burden is estimated to be 15 minutes per month for each 
reporter to compile in-house formatted sales information and submit that 
information electronically. Comments relating to this information 
collection should reference OMB Control Number 1010-0120.
    (d) Comments on burden estimates. Send comments on the accuracy of 
this burden estimate or suggestions on reducing this burden to the 
Minerals Management Service, Attention: Information Collection Clearance 
Officer, (OMB Control Number 1010-0120 (insert appropriate OMB Control 
Number), Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240. An 
agency may not conduct or sponsor, and a person is not required to 
respond to, a collection of information unless it displays a currently 
valid OMB Control Number.

[57 FR 41864, Sept. 14, 1992, as amended at 64 FR 38122, July 15, 1999; 
66 FR 45769, Aug. 30, 2001]



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 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;

[[Page 178]]

    (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]



               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

[[Page 179]]

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 
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: 66 FR 45771, Aug. 30, 2001, unless otherwise noted.



Sec. 210.200  What is the purpose of this subpart?

    This subpart explains your reporting requirements if you produce 
coal or other solid minerals from Federal or Indian leases. Included are 
your requirements for reporting production, sales, and royalties.



Sec. 210.201  How do I submit Form MMS-4430, Solid Minerals Production and 

Royalty Report?

    (a) What to submit. (1) You must submit a completed Form MMS-4430 
for--

[[Page 180]]

    (i) Production of all coal and other solid minerals from any Federal 
or Indian lease;
    (ii) Sale of any such mineral;
    (iii) Any such mineral held in stockpile or inventory; and
    (iv) Payment of rents (other than those for which you receive from 
MMS a Courtesy Notice as defined in Sec. 218.51(a) of this chapter), 
minimum royalty, deferred bonus, advance royalty, minimum royalty 
payable in advance, settlements, recoupments, and other financial 
obligations.
    (2) You must submit a completed Form MMS-4430 for any product you 
sell from a remote storage site. If you sell from five or fewer remote 
storage sites, you must report sales from each site on separate Forms 
MMS-4430. If you sell from more than five remote storage sites, you must 
total the data from all sites and report the summarized data on one Form 
MMS-4430.
    (3) Instructions for completing and submitting Form MMS-4430 are 
available on our Internet reporting web site or you may contact us toll 
free at 1-888-201-6416.
    (b) When to submit. (1) Unless your lease terms specify a different 
frequency for royalty payments, you must submit your Form MMS-4430 on or 
before the end of the month following the month in which you produce any 
solid mineral, sell any solid mineral, or hold any solid mineral 
production in stockpile or inventory. However, if the last day of the 
month falls on a weekend or holiday, your Form MMS-4430 is due on the 
next business day.
    (2) If your lease terms specify a different frequency for royalty 
payment, then you must submit your Form MMS-4430 on or before the date 
on which you must pay royalty under the terms of the lease.
    (3) You must submit your Form MMS-4430 for payment of rents (other 
than those for which you receive from MMS a Courtesy Notice as defined 
in Sec. 218.51(a) of this chapter), minimum royalty, deferred bonus, 
advance royalty, minimum royalty payable in advance, settlements, 
recoupments, and other financial obligations on or before the date on 
which you must pay those obligations under the terms of the lease.
    (4) If the information on a previously reported Form MMS-4430 is no 
longer correct, you must submit a revised Form MMS-4430 by the last day 
of the month in which you learn that the previously reported information 
is no longer correct, except when the last day of the month falls on a 
weekend or holiday. If the last day of the month falls on a weekend or 
holiday, your revised Form MMS-4430 is due on the first business day of 
the following month.
    (c) How to submit. (1) You must submit Form MMS-4430 electronically 
using our Internet reporting web site unless you meet the conditions in 
paragraph (c)(2). We will provide written instructions and a valid login 
and password before you begin reporting.
    (2) You are not required to report electronically if you are a small 
business as defined by the U.S. Small Business Administration (13 CFR 
121.201) and you have no computer, no plans to purchase a computer, and 
no contract with an electronic reporting service.
    (3) If you do not report electronically, you must submit the 
completed Form MMS-4430 to us at one of the following addresses, unless 
MMS publishes notice in the Federal Register giving a different address:
    (i) For U.S. Postal Service regular mail or Express Mail: Minerals 
Management Service, Minerals Revenue Management, P.O. Box 5810, Denver, 
Colorado 80217-5810; or
    (ii) For courier service or overnight mail (excluding Express Mail): 
Minerals Management Service, Minerals Revenue Management, Building 85, 
Denver Federal Center, Room A-614, Denver, Colorado 80225.

[66 FR 45771, Aug. 30, 2001; 66 FR 50827, Oct. 5, 2001]



Sec. 210.202  How do I submit sales summaries?

    (a) What to submit. (1) You must submit sales summaries for all coal 
and other solid minerals produced from Federal and Indian leases and for 
any remote storage site from which you sell Federal or Indian solid 
minerals. You do not have to submit a sales summary for those months in 
which you do not sell any Federal or Indian production.

[[Page 181]]

    (2) If you sell from five or fewer remote storage sites, you must 
submit a sales summary for each site. If you sell from more than five 
remote storage sites, you may total the data from all sites and submit 
the summarized data as one sales summary. The details you report on the 
sales summary are for the same sales reported on Form MMS-4430.
    (3) Use the following table to determine the time frames for 
submitting sales summaries and the data elements you must include. Your 
submitted sales summaries must include the following data but may be 
internally generated documents from your own records. You do not need to 
re-format them before submitting them to us:

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                        All other leases
                                                                                                                     All other leases      with no ad
          Data element                    Coal           Sodium/potassium   Western  phosphate        Metals          with ad valorem    valorem royalty
                                                                                                                       royalty terms          terms
--------------------------------------------------------------------------------------------------------------------------------------------------------
(i) Purchaser Name or Unique      Monthly............  Monthly............  Monthly...........  Monthly...........  Monthly...........  As Requested
 Identification.
(ii) Sales Units................  Monthly............  Monthly............  Monthly...........  Monthly...........  Monthly...........  Monthly
(iii) Gross Proceeds............  Monthly............  Monthly............  Not Required......  Monthly...........  Monthly...........  Not Required
(iv) Processing or washing costs  Monthly............  Monthly............  Not Required......  Monthly...........  Monthly...........  Not Required
(v) Transportation costs........  Monthly............  Monthly............  Not Required......  Monthly...........  Monthly...........  Not Required
(vi) Name of product type sold..  Not Required.......  Monthly............  Not Required......  Monthly...........  Monthly...........  As Requested
(vii) Btu/lb....................  Monthly............  Not Required.......  Not Required......  Not Required......  Not Required......  Not Required
(viii) Ash %....................  Monthly............  Not Required.......  Not Required......  Not Required......  Not Required......  Not Required
(ix) Sulfur %...................  Monthly............  Not Required.......  Not Required......  Not Required......  Not Required......  Not Required
(x) lbs SO2.....................  Monthly............  Not Required.......  Not Required......  Not Required......  Not Required......  Not Required
(xi) Moisture %.................  Monthly............  Not Required.......  Monthly...........  Not Required......  Not Required......  Not Required
(xii) By-product Units..........  Not Required.......  As Requested.......  Monthly...........  As Requested......  As Requested......  Not Required
(xiii) P2O5 %...................  Not Required.......  Not Required.......  Monthly...........  Not Required......  Not Required......  Not Required
(xiv) Size......................  Not Required.......  Not Required.......  Not Required......  Not Required......  As Requested......  Not Required
(xv) Net Smelter Return data....  Not Required.......  Not Required.......  Not Required......  Monthly...........  Not Required......  Not Required
(xvi) Other Data e.g., Royalty    As Requested.......  Monthly............  As Requested......  As Requested......  As Requested......  As Requested.
 Calculation Worksheet.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    (b) When to submit. (1) For leases with ad valorem royalty terms 
(that is, leases for which royalty is a percentage of the value of 
production), you must submit your sales summaries monthly at the same 
time you submit Form MMS-4430. You do not have to submit a sales summary 
for any month in which you did not sell Federal or Indian production.
    (2) For leases with no ad valorem royalty terms (that is, leases in 
which the royalty due is not a function of the value of production, such 
as cents-per-ton or dollars-per-unit), you must submit monthly sales 
summaries only if we specifically request you to do so.
    (c) How to submit. (1) You should provide the sales summary data via 
electronic mail where possible. We will provide instructions and the 
proper email address for these submissions.
    (2) If you submit sales summaries by paper copy, mail them to one of 
the following addresses, unless MMS publishes notice in the Federal 
Register giving a different address:
    (i) For U.S. Postal Service regular mail or Express Mail: Minerals 
Management Service, Minerals Revenue Management, Solid Minerals and 
Geothermal Compliance and Asset Management, P.O. Box 25165, MS 390G1, 
Denver, Colorado 80225-0165.
    (ii) For courier service or overnight mail (excluding Express Mail): 
Minerals Management Service, Solid Minerals and Geothermal Compliance 
and Asset Management, 12600 West Colfax Avenue, Suite C-100, Lakewood, 
Colorado 80215.



Sec. 210.203  How do I submit sales contracts?

    (a) What to submit. You must submit sales contracts, agreements, and 
contract amendments for the sale of all coal and other solid minerals 
produced

[[Page 182]]

from Federal and Indian leases with ad valorem royalty terms.
    (b) When to submit. (1) For coal and metal production, you must 
submit the required documents semi-annually, no later than March 30 and 
September 30 of each year.
    (2) For sodium, potassium, and phosphate production, and production 
from any other lease with ad valorem royalty terms, you must submit the 
required documents only if you are specifically requested to do so.
    (c) How to submit. You must submit complete copies of the sales 
contracts and amendments to us at the applicable address given in Sec. 
210.202(c)(2), unless MMS publishes notice in the Federal Register 
giving a different address.



Sec. 210.204  How do I submit facility data?

    (a) What to submit. (1) You must submit facility data if you operate 
a wash plant, refining, ore concentration, or other processing facility 
for any coal, sodium, potassium, metals, or other solid minerals 
produced from Federal or Indian leases with ad valorem royalty terms, 
regardless of whether the facility is located on or off the lease.
    (2) You do not have to submit facility data for those months in 
which you do not process solid minerals produced from Federal or Indian 
leases and do not have any such minerals in stockpile inventory.
    (3) You must include in your facility data all production processed 
in the facility from all properties, not just production from Federal 
and Indian leases.
    (4) Facility data submissions must include the following minimum 
information:
    (i) Identification of your facility;
    (ii) Mines served;
    (iii) Input quantity;
    (iv) Input quality or ore grade (except for coal);
    (v) Output quantity; and
    (vi) Output quality or product grades.
    (5) Your submitted facility data may be internally generated 
documents from your own records. You do not need to re-format them 
before submitting them to us.
    (b) When to submit. You must submit your facility data monthly at 
the same time you submit your Form MMS-4430.
    (c) How to submit. (1) You should provide the facility data via 
electronic mail where possible. We will provide instructions and the 
proper email address for these submissions before you begin reporting.
    (2) If you submit facility data by paper copy, send it to the 
applicable address given in Sec. 210.202(c)(2).



Sec. 210.205  Will I need to submit additional documents or evidence to MMS?

    (a) Federal and Indian lease terms allow us to request detailed 
statements, documents, or other evidence necessary to verify compliance 
with lease terms and conditions and applicable rules.
    (b) We will request this additional information as we need it, not 
as a regular submission.



Sec. 210.206  How will information submissions be kept confidential?

    Information submitted under this part that constitutes trade secrets 
or commercial and financial information that is identified as privileged 
or confidential, or that is exempt from disclosure under the Freedom of 
Information Act, 5 U.S.C. 552, shall not be available for public 
inspection or made public or disclosed without the consent of the 
lessee, except as otherwise provided by law or regulation.

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

[[Page 183]]

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  Special forms and reports.

    The MMS may require submission of additional information on special 
forms or reports. When special forms or reports other than those 
referred to in this subpart are necessary, MMS will give instructions 
for the filing of such forms or reports. Requests for the submission of 
such forms will be made in conformity with the requirements of the 
Paperwork Reduction Act of 1980 and other applicable laws.

[56 FR 57286, Nov. 8, 1991. Redesignated at 72 FR 24467, May 2, 2007]



Sec. 210.353  Monthly report of sales and royalty.

    A completed Report of Sales and Royalty Remittance (Form MMS-2014) 
must be submitted each month once sales or utilization of production 
occur, even though sales may be intermittent, unless otherwise 
authorized by MMS. This report is due on or before the last day of the 
month following the month in which production was sold or utilized, 
together with the royalties due the United States.

[56 FR 57286, Nov. 8, 1991. Redesignated at 72 FR 24467, May 2, 2007]



Sec. 210.354  Reporting instructions.

    Specific guidance on how to prepare and submit required information 
collection reports and forms to MMS is contained in the publication 
titled Minerals Revenue Reporter Handbook--Oil, Gas, and Geothermal 
Resources, which is available from the Minerals Management Service, 
Minerals Revenue Management, Financial Management, P.O. Box 25165, Mail 
Stop 350B1, Denver, CO 80225-0165. For copies from the MMS Web site, go 
to http://www.mrm.mms.gov/. Click Reporting Information and select the 
topic.

[72 FR 24467, May 2, 2007]

Subpart I--OCS Sulfur [Reserved]



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

Subpart A--General Provisions [Reserved]



               Subpart B_Oil, Gas, and OCS Sulphur_General



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 184]]

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).
    (b) Period for keeping records. Lessees, operators, revenue payors, 
or other persons required to keep records under this section shall 
maintain and preserve them for 6 years from the day on which the 
relevant transaction recorded occurred unless the Secretary notifies the 
record holder of an audit or investigation involving the records and 
that they must be maintained for a longer period. When an audit or 
investigation is underway, records shall be maintained until the 
recordholder is released in writing from the obligation to maintain the 
records. Lessees, operators, revenue payors, or other persons shall 
maintain the records generated during the period for which they have 
paying or operating responsibility on the lease for a period of 6 years.
    (c) Inspection of records. The lessee, operator, revenue payor, or 
other person required to keep records shall be responsible for making 
the records available for inspection. Records shall be provided at a 
business location of the lessee, operator, revenue payor, or other 
person during normal business hours upon the request of any officer, 
employee or other party authorized by the Secretary. Lessees, operators, 
revenue payors, and other persons will be given a reasonable period of 
time to produce historical records.

[49 FR 37345, Sept. 21, 1984; 49 FR 40576, Oct. 17, 1984, as amended at 
67 FR 19111, Apr. 18, 2002]



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 185]]



                     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.
    (b) Period for keeping records. All records pertaining to Federal 
geothermal leases shall be maintained by a lessee, operator, revenue 
payor, or other person for 6 years after the records are generated 
unless the recordholder is notified, in writing, before the expiration 
of that 6-year period that records must be maintained for a longer 
period for purposes of audit or investigation. When an audit or 
investigation is underway, records shall be maintained until the 
recordholder is released by written notice of the obligation to maintain 
records.
    (c) Access to records. The Associate Director for Minerals Revenue 
Management shall have access to all records in the possession of the 
lessee, operator, revenue payor, or other person pertaining to 
compliance with royalty obligations under Federal geothermal leases 
(regardless of whether such records were generated more than 6 years 
before a request or order to produce them and they otherwise were not 
disposed of), including, but not limited to:
    (1) Qualities and quantities of all products extracted, processed, 
sold, delivered, or used by the operator/lessee;
    (2) Prices received for products, prices paid for like or similar 
products, and internal transfer prices; and
    (3) Costs of extraction, power generation, electrical transmission, 
and byproduct transportation.
    (d) Inspection of Records. The lessee, operator, revenue payor, or 
other person required to keep records shall be responsible for making 
the records available for inspection. Records shall be made available at 
a business location of the lessee, operator, revenue payor, or other 
person during normal business hours upon the request of any officer, 
employee, or other party authorized by the Secretary. Lessees, 
operators, revenue payors, and other persons will be given a reasonable 
period of time to produce records.

[56 FR 57286, Nov. 8, 1991, as amended at 67 FR 19111, Apr. 18, 2002]

Subpart I--OCS Sulfur [Reserved]

          PART 215_ACCOUNTING AND AUDITING STANDARDS [RESERVED]



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.

[[Page 186]]

216.57 Stripper royalty rate reduction notification.

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

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

Subpart E--Solid Minerals, General [Reserved]

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 or gas 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, as amended at 66 FR 45773, Aug. 30, 2001]



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.).
    Associate Director means the Associate Director for Minerals Revenue 
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).
    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

[[Page 187]]

of oil or gas--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.
    Measurement device means a mechanical or electrical device that is 
used to measure production of oil or gas for sales, transfers, and/or 
royalty determination.
    Mineral leasing law means any Federal law administered by the 
Secretary authorizing the disposition under lease of oil or gas.
    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 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 or gas 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.
    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 production 
report or form to the MMS.
    Secretary means the Secretary of the Interior or his/her designee.

[51 FR 8175, Mar. 7, 1986, as amended at 58 FR 45254, Aug. 27, 1993; 66 
FR 45773, Aug. 30, 2001; 67 FR 19111, Apr. 18, 2002]



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]



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 the 
production reporter handbook. The production reporter handbook is 
available from the Minerals Management Service, Minerals Revenue 
Management, P.O. Box 17110, Denver, Colorado 80217-0110.
    (b) Production reporters should refer to the handbook 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 handbook.

[53 FR 16412, May 9, 1988, as amended at 57 FR 41867, Sept. 14, 1992; 58 
FR 64903, Dec. 10, 1993; 67 FR 19111, Apr. 18, 2001]



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 Minerals 
Management Service, Minerals Revenue Management, 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, Minerals Revenue

[[Page 188]]

Management, 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; 67 FR 19111, Apr. 18, 2002]



Sec. 216.20  Applicability.

    The requirements of this part shall apply to all oil and gas 
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, as amended at 66 FR 45773, Aug. 30, 2001]



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 reporter handbook. Copies 
of the handbook are available from the MMS.

[51 FR 8175, Mar. 7, 1986, as amended at 67 FR 19111, Apr. 18, 2002]



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.



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 1995, and are expected to involve less than 
10 respondents annually.

[51 FR 8175, Mar. 7, 1986, as amended at 67 FR 19112, Apr. 18, 2002]



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

[[Page 189]]

MMS-4056), and Production Allocation Schedule Report (Form MMS-4058).
    (d) 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.
    (e) An assessment under this section shall not be shared with a 
State, Indian tribe, Indian allottee, or Alaska Native Corporation.
    (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 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; 66 FR 45773, Aug. 30, 2001]



                     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.
    (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

[[Page 190]]

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.
------------------------------------------------------------------------

    (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.
    (e)(1) Notwithstanding the provisions of paragraph (c) of this 
section and Sec. 216.50, the due date for submittal of the Oil and Gas 
Operations Report (Form MMS-4054) or Monthly Report of Operations (Form 
MMS-3160) for the production months of July, August, and September 2005 
for Federal offshore and onshore oil and gas leases by oil and gas 
lessees or operators who make the certification required under paragraph 
(e)(2) of this section is extended to December 15, 2005 (if you do not 
file electronically) or December 27, 2005 (if you file electronically).
    (2) The extended due dates in paragraph (e)(1) of this section will 
apply to Oil and Gas Operations Reports (Form MMS-4054) and Monthly 
Reports of Operations (Form MMS-3160) by any lessee or operator who 
certifies that a hurricane that struck the Gulf of Mexico coast of the 
United States in August or September 2005 disrupted the lessee's or 
operator's operations to the extent that it prevented the lessee or 
operator from submitting an accurate Form MMS-4054 or MMS-3160.
    (3) Paragraphs (e)(1) and (e)(2) of this section do not apply to 
Indian leases or

[[Page 191]]

to Federal leases for minerals other than oil and gas.
    (4) Certifications under paragraph (e)(2) of this section should be 
submitted either:
    (i) By mail to: Robert Prael, Financial Manager, Minerals Management 
Service, Minerals Revenue Management, P.O. Box 25165, MS 350B1, Denver, 
CO 80225-0165, or
    (ii) By e-mail to [email protected].
    (f)(1) A lessee or operator who submits a certification required 
under paragraph (e)(2) of this section may rely on the extended due 
dates prescribed in paragraph (e)(1) of this section unless and until 
MMS notifies the lessee or operator that MMS does not accept the 
certification.
    (2) If MMS notifies a lessee or operator that MMS does not accept 
the lessee's or operator's certification under paragraph (e)(2) of this 
section, the due date for the Oil and Gas Operations Report or Monthly 
Report of Operations will be the date specified in the notice.

[64 FR 38124, July 15, 1999, as amended at 70 FR 56852, Sept. 29, 2005]



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:

[[Page 192]]

    (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 
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 [Reserved]

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 Resources

217.300 Audits or review of records.
217.301 Lease account reconciliations.
217.302 Definitions.

Subpart H--Indian Lands [Reserved]

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

[[Page 193]]

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 Minerals Revenue Management. The audit 
shall be performed by a qualified independent certified public 
accountant or by an independent public accountant licensed by a State, 
territory, or insular possession of the United States or the District of 
Columbia, and at the expense of the operator/lessee. The operator/lessee 
shall furnish, free of charge, duplicate copies of audit reports that 
express opinions on such compliance to the Associate Director for 
Minerals Revenue Management within 30 days after the completion of each 
audit. Where such audits are required, the Associate Director for 
Minerals Revenue Management will specify the purpose and scope of the 
audit and the information which is to be verified or obtained.

[47 FR 33195, July 30, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, 
as amended at 67 FR 19112, Apr. 18, 2002]



                     Subpart F_Other Solid Minerals



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 Resources

    Source: 72 FR 24468, May 2, 2007, unless otherwise noted.



Sec. 217.300  Audit or review of records.

    The Secretary, or his/her authorized representative, will initiate 
and conduct audits or reviews relating to the scope, nature, and extent 
of compliance by lessees, operators, revenue payors, and other persons 
with rental, royalty, fees, and other payment requirements on a Federal 
geothermal lease. Audits or reviews will also relate to compliance with 
applicable regulations and orders. All audits or reviews will be 
conducted in accordance with this part.

[[Page 194]]



Sec. 217.301  Lease account reconciliations.

    Specific lease account reconciliations will be performed with 
priority being given to reconciling those lease accounts specifically 
identified by a State as having significant potential for underpayment.



Sec. 217.302  Definitions.

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

Subpart H--Indian Lands [Reserved]



PART 218_COLLECTION OF ROYALTIES, RENTALS, BONUSES AND OTHER MONIES DUE THE 

FEDERAL GOVERNMENT AND CREDITS AND INCENTIVES DUE LESSEES--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 Rental fees.
218.152 Fishermen's Contingency Fund.
218.153 [Reserved]
218.154 Effect of suspensions on royalty and rental.
218.155 Method of payment.
218.156 Definitions.

                    Subpart E_Solid Minerals_General

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

                     Subpart F_Geothermal Resources

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

Subpart G--Indian Lands [Reserved]

              Subpart H_Service of Official Correspondence

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

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

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

[[Page 195]]



                      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 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 assessments discussed in this section, a report 
is defined as follows:
    (1) For coal and other solid mineral leases, a report is each line 
on the Solid Minerals Production and Royalty Report, Form MMS-4430.
    (2) For oil and gas and geothermal leases, a report is each line on 
the Report of Sales and Royalty Remittance, Form MMS-2014.
    (d) An assessment under this section shall not be shared with a 
State, Indian tribe, or Indian allottee.
    (e) The amount of the assessment to be imposed pursuant to 
paragraphs (a) and (b) of this section shall be established periodically 
by MMS. The assessment amount for each violation will be based on MMS's 
experience with costs and improper reporting. The MMS will publish a 
Notice of the assessment amount to be applied in the Federal Register.

[49 FR 37346, Sept. 21, 1984. Redesignated and amended at 51 FR 15767, 
Apr. 28, 1986; 52 FR 27546, July 22, 1987; 52 FR 37452, Oct. 7, 1987; 57 
FR 52720, Nov. 5, 1992; 59 FR 38906, Aug. 1, 1994; 66 FR 45773, Aug. 30, 
2001]



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)

[[Page 196]]

and (b) of this section shall be established periodically by MMS. The 
assessment amount will be based on MMS' experience with costs and 
improper reporting and/or payment as specified in this section. The MMS 
will publish a Notice in the Federal Register of the assessment amount 
to be applied with the effective date.

[58 FR 45438, Aug. 30, 1993]



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.
    (d)(1) Notwithstanding the provisions of paragraph (a) of this 
section and corresponding lease terms and 30 CFR 210.52, the due date 
for submittal of royalty payments and Reports of Sales and Royalty 
Remittance (Form MMS-2014) for the production months of July, August, 
September, and October 2005 for Federal offshore and onshore oil and gas 
leases by oil and gas lessees

[[Page 197]]

or royalty payors who make the certification required under paragraph 
(d)(2) of this section is extended until January 3, 2006.
    (2) The extended due dates in paragraph (d)(1) of this section will 
apply to royalty payments and Reports of Sales and Royalty Remittance 
(Form MMS-2014) by any lessee or royalty payor who certifies that a 
hurricane that struck the Gulf of Mexico coast of the United States in 
August or September 2005 disrupted the lessee's or payor's operations to 
the extent that it prevented the lessee or royalty payor from making an 
accurate royalty payment or submitting an accurate Form MMS-2014.
    (3) A lessee's or royalty payor's certification under paragraph 
(d)(2) of this section that it is unable to generate and submit either 
an accurate royalty report or an accurate royalty payment will extend 
the due date for both royalty reporting and royalty payment.
    (4) Paragraphs (d)(1) through (d)(3) of this section do not apply to 
Indian leases or to Federal leases for minerals other than oil and gas.
    (5) Certifications under paragraph (d)(2) of this section should be 
submitted either:
    (i) By mail to: Robert Prael, Financial Manager, Minerals Management 
Service, Minerals Revenue Management, P.O. Box 25165, MS 350B1, Denver, 
CO 80225-0165, or
    (ii) By e-mail to [email protected].
    (e)(1) A lessee or royalty payor who submits a certification 
required under paragraph (d)(2) of this section may rely on the extended 
due dates prescribed in paragraph (d)(1) of this section unless and 
until MMS notifies the lessee or royalty payor or operator that MMS does 
not accept the certification.
    (2) If MMS notifies the lessee or royalty payor that MMS does not 
accept the lessee's or royalty payor's certification under paragraph 
(d)(2) of this section, the due date for royalty payments and Reports of 
Sales and Royalty Remittance will be the date specified in the notice.

[49 FR 37346, Sept. 21, 1984, as amended at 70 FR 56853, Sept. 29, 2005]



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.
    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

[[Page 198]]

    (vi) Federal Reserve check.
    (5) You must include your payor code on all payments.
    (6) You must pay in U.S. dollars.
    (c) How to complete a non-EFT payment. (1) Make any payment on a 
Federal lease payable to: ``Department of the Interior-Minerals 
Management Service'' or ``DOI-MMS.''
    (2) For an Indian allottee payment, send a separate payment for each 
Bureau of Indian Affairs (BIA) agency or area office represented by the 
leases on your report or invoice document. You must include the name of 
the applicable BIA agency or area office on your payment. Make your 
payment document payable to: ``Department of the Interior-Minerals 
Management Service for BIA [Name] Agency (allotted)'' or ``DOI-MMS for 
BIA [Name] Agency (allotted).''
    (3) For an Indian tribal payment other than a lockbox payment, send 
a separate payment for each tribe represented by the leases on your 
report or invoice document. You must include the name of the Indian 
tribe on your payment. Make it payable to: ``Department of the Interior-
Minerals Management Service for BIA [Name of Tribe]'' or ``DOI-MMS for 
BIA [Name of Tribe].''
    (4) For an Indian tribal lockbox payment, follow the instructions 
MMS provides you on how to report and make the lockbox payment. These 
instructions are specific to each tribe's lockbox written agreement with 
the bank authorized to receive payments on the tribe's mineral leases. 
You will receive these instructions from MMS when you are required to 
use a tribal lockbox for reports and payments.
    (d) Where to send a non-EFT payment when you use the U.S. Postal 
Service. (1) For a payment to an Indian tribal lockbox, send your 
payment to the appropriate tribal lockbox address.
    (2) For a Federal nonproducing lease rental or deferred bonus 
payment, send it to:

Minerals Management Service, Minerals Revenue Management, P.O. Box 5640, 
Denver, CO 80217-5640.

    (3) For all other Federal and Indian lease payments other than those 
going to an Indian tribal lockbox, send them to:

Minerals Management Service, Minerals Revenue Management, P.O. Box 5810, 
Denver, CO 80217-5810.

    (e) Where to send a non-EFT payment when you use a courier or 
overnight delivery service. You should send this type of payment to:

Minerals Management Service, Minerals Revenue Management, Building 85, 
Denver Federal Center, Room A-614, Denver, CO 80225-0165.

    (f) How to prepare and what to include on your payment document. (1) 
For Form MMS-2014 payments, you must include both your payor code (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

[[Page 199]]

according to part 243 of this chapter. If you file an appeal, and the 
requirement to submit payment is suspended, the original payment due 
date for purposes such as calculating late payment interest is not 
changed.
    (2) If you use the U.S. Postal Service, courier, or overnight mail 
to send your payment, it is due at the MMS addresses in paragraphs (d) 
and (e) of this section before 4 p.m. Mountain Time on the due date, 
regardless of when you sent it.
    (3) If you use EFT to send your payment, it is due in the MMS 
account by the payment due date. You are responsible for your actions or 
your bank's actions that cause a late or incorrect payment. You will not 
be held responsible for mechanical or system failures of EFT payments.
    (h) What happens if payments are late or overdue? (1) If MMS 
receives your payment late, MMS will impose a late-payment interest 
charge under 30 CFR 218.54.
    (2) If you do not pay an amount you owe, MMS may assess civil 
penalties under part 241 of this chapter or other applicable 
regulations.

[62 FR 19498, Apr. 22, 1997, as amended at 66 FR 45773, Aug. 30, 2001; 
67 FR 19112, Apr. 18, 2002]



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;
    (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

[[Page 200]]

copy of the tribe's written permission must be furnished to MMS pursuant 
to instructions for reporting recoupments in the MMS revenue reporter 
handbook. See part 210 of this chapter. Recouping overpayments on one 
allotted lease from royalties paid to another allotted lease is 
specifically prohibited.
    (c) Overpayments subject to recoupment under this section include 
all payments made in excess of the required payment for royalty, rental, 
bonus, or other amounts owed as specified by statute, regulation, order, 
or terms of an Indian mineral lease.
    (d) The MMS Director or his/her designee may order any payor to not 
recoup any amount for such reasonable period of time as may be necessary 
for MMS to review the nature and amount of any claimed overpayment.

[60 FR 3087, Jan. 13, 1995, as amended at 67 FR 19112, Apr. 18, 2002]



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]



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.

[[Page 201]]

    (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 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

[[Page 202]]

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 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,

[[Page 203]]

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. 
Payments received at the specified MMS addresses after 4 p.m. mountain 
time are considered received the following business day.
    (c) Late payment charges apply to all underpayments and payments 
received after the date due. The charges include production and minimum 
royalties; assessments for liquidated damages; administrative fees and 
payments by purchasers of royalty taken-in-kind; or any other payments, 
fees, or assessments that a lessee/operator/permittee/payor/royalty 
taken-in-kind purchaser is required to pay by a specified date. The 
failure to pay past due amounts, including late-payment charges, will 
result in the initiation of other enforcement proceedings.
    (d) An overpayment on a lease or leases may be offset against an 
underpayment on a different lease or leases to determine a net 
underpayment on which interest is due pursuant to conditions specified 
in 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; 67 FR 19112, Apr. 18, 2002]



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

[[Page 204]]

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. 
Payments received at the specified MMS addresses after 4 p.m. mountain 
time are considered received the following business day.
    (d) Late payment charges apply to all underpayments and payments 
received after the date due. These charges include production and 
minimum royalties; assessments for liquidated damages; administrative 
fees and payments by purchasers of royalty taken-in-kind; or any other 
payments, fees, or assessments that a lessee/operator/payor/permittee/
royalty taken-in-kind purchaser is required to pay by a specified date. 
The failure to pay past due amounts, including late payment charges, 
will result in the initiation of other enforcement proceedings.
    (e) An overpayment on a lease or leases, excluding rental payments, 
may be offset against an underpayment on a different lease or leases to 
determine a net underpayment on which interest is due pursuant to 
conditions specified in 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; 67 FR 19112, 
Apr. 18, 2002]



Sec. 218.151  Rental fees.

    The annual rental paid in any year is in addition to, and is not 
credited against, any royalties due from production. The lessee must pay 
an annual rental as shown in paragraphs (a), (b), and (c) of this 
section. Discovery means one or more wells on the lease that meet the 
requirements in 250, subpart A of this title.
    (a) This paragraph applies to any lease not covered by paragraph (b) 
or paragraph (c) of this section.

------------------------------------------------------------------------
                                   Issued as a
             For--               result of a sale   The lessee must pay
                                      held--              rental--
------------------------------------------------------------------------
(1) An oil and gas lease......  Before March 26,   On or before the
                                 2001.              first day of each
                                                    lease year before
                                                    the discovery of oil
                                                    or gas on the lease.

[[Page 205]]

 
(2) An oil and gas lease......  After March 26,    On or before the
                                 2001.              first day of each
                                                    lease year before
                                                    the discovery of oil
                                                    or gas on the lease,
                                                    then on or before
                                                    the last day of each
                                                    lease year in any
                                                    full year in which
                                                    royalties on
                                                    production are not
                                                    due.
(3) A mineral lease for other   Before March 26,   On or before the
 than oil or gas.                2001.              first day of each
                                                    lease year before
                                                    the discovery of
                                                    paying quantities.
(4) A mineral lease for other   After March 26,    On or before the
 than oil or gas.                2001.              first day of each
                                                    lease year before
                                                    the date the first
                                                    royalty payment is
                                                    due on the lease,
                                                    then on or before
                                                    the last day of each
                                                    lease year in any
                                                    full year in which
                                                    royalties on
                                                    production are not
                                                    due.
------------------------------------------------------------------------

    (b) This paragraph applies to any lease created by segregating a 
portion of a producing lease when there is no actual or allocated 
production on the segregated portion. The lessee must pay an annual 
rental for the segregated portion at the rate specified in the lease. 
The lessee must pay the rental as shown in the following table.

------------------------------------------------------------------------
    If the lease results from a
           segregation--                The lessee must pay rental--
------------------------------------------------------------------------
(1) Before March 26, 2001.........  On or before the first day of each
                                     lease year before the discovery of
                                     oil or gas on the segregated
                                     portion.
(2) After March 26, 2001..........  On or before the first day of each
                                     lease year before the discovery of
                                     oil or gas on the lease, then on or
                                     before the last day of each lease
                                     year in any full year in which
                                     royalties on production are not
                                     due.
------------------------------------------------------------------------

    (c) For leases issued subject to the net profit sharing provisions, 
annual rental payments shall be due and payable in advance, on the first 
day of each lease year which commences prior to the date the first 
profit share payment becomes due. The owner of any lease created by the 
segregation of a portion of a lease subject to net profit sharing 
provisions, shall pay an annual rental for such segregated portion at 
the rate per acre or hectare specified in the lease. This rental shall 
be payable each year following the year in which the segregation becomes 
effective and shall continue to be due and payable, in advance, on the 
first day of each year which commences prior to the date the first 
profit share payment becomes due.

[44 FR 38276, June 29, 1979, as amended at 45 FR 69175, Oct. 17, 1980; 
47 FR 25972, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982, 
and at 48 FR 35641, Aug. 5, 1983; 66 FR 11518, Feb. 23, 2001; 67 FR 
19112, Apr. 18, 2002]



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

[[Page 206]]

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.

[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. 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.

[[Page 207]]

    (4) Payments received at the MMS addresses after 4 p.m. mountain 
time are considered received the following business day.
    (e) Miscellaneous payments. Payments shall be made to the manager of 
the appropriate Outer Continental Shelf field office by cash, check or 
bank draft payable to ``Department of the Interior--MMS'' for 
miscellaneous payments such as:
    (1) Pipeline rights-of-way application filing fees and rentals, 
pipeline accessory site rentals and application fees, and other related 
costs.
    (2) Filing and approval fees for transfers of interest in leases.

[49 FR 8605, Mar. 8, 1984, as amended at 52 FR 23815, June 25, 1987; 53 
FR 43201, Oct. 26, 1988; 57 FR 41868, Sept. 14, 1992; 62 FR 19499, Apr. 
22, 1997; 67 FR 19112, Apr. 18, 2002]



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.

    You must tender all payments in accordance with Sec. 218.51, except 
as follows:
    (a) For purposes of this section, report means the Solid Minerals 
Production and Royalty Report, Form MMS-4430, rather than the Form MMS-
2014.
    (b) For Form MMS-4430 payments, include both your customer 
identification and your customer document identification numbers on your 
payment document, rather than the information required under Sec. 
218.51(f)(1).
    (c) For a rental payment that is not reported on Form MMS-4430, 
include the MMS Courtesy Notice when provided or write your customer 
identification number and Government-assigned lease number on the 
payment document, rather than the information required under Sec. 
218.51(f)(4)(iii).

[66 FR 45773, Aug. 30, 2001]



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 Sec. 218.51. 
Payments received at the specified MMS addresses after 4 p.m. mountain 
time are considered received the following business day.
    (c) Late payment charges are calculated on the basis of a percentage 
assessment rate. In the absence of a specific lease, permit, license or 
contract provision prescribing a different rate, this percentage 
assessment rate is prescribed by the Department of the Treasury as the 
``Treasury Current Value of Funds Rate.''
    (d) This rate is available in the Treasury Fiscal Requirements 
Manual Bulletins that are published prior to the first day of each 
calendar quarter for application to overdue payments or underpayments in 
the new calendar quarter. The rate is also published in the Notices 
section of the Federal Register and indexed under ``Fiscal Service/
Notices/Funds Rate; Treasury Current Value.''
    (e) Late payment charges apply to all underpayments and payments 
received

[[Page 208]]

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, as amended at 57 FR 41868, Sept. 14, 1992; 57 FR 62207, Dec. 
30, 1992; 59 FR 14559, Mar. 29, 1994; 65 FR 55189, Sept. 13, 2000; 67 FR 
19112, Apr. 18, 2002]



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-4430 against the current month's royalties or other revenues owed on 
the same lease. However, for any month a payor may not recoup more than 
50 percent of the royalties or other revenues owed in that month under 
an individual allotted lease or more than 100 percent of the royalties 
or other revenues owed in that month under a tribal lease.
    (b) With written permission authorized by tribal statute or 
resolution, a payor may recoup an overpayment against royalties or other 
revenues owed in that month under other leases for which that tribe is 
the lessor. A copy of the tribe's written permission must be furnished 
to MMS for reporting recoupments. Call 1-888-201-6416 for instructions. 
Recouping overpayments on one allotted lease from royalties paid to 
another allotted lease is specifically prohibited.
    (c) Overpayments subject to recoupment under this section include 
all payments made in excess of the required payment for royalty, rental, 
bonus, or other amounts owed as specified by statute, regulation, order, 
or terms of an Indian mineral lease.
    (d) The MMS Director or his/her designee may order any payor to not 
recoup any amount for such reasonable period of time as may be necessary 
for MMS to review the nature and amount of any claimed overpayment.

[60 FR 3087, Jan. 13, 1995, as amended at 66 FR 45773, Aug. 30, 2001; 66 
FR 50827, Oct. 5, 2001]



                     Subpart F_Geothermal Resources



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. 
Payments received at the specified MMS addresses after 4 p.m. Mountain 
Time are considered received the following business day.
    (c) Late payment charges are calculated on the basis of a percentage 
assessment rate. In the absence of a specific lease, permit, license or 
contract

[[Page 209]]

provision prescribing a different rate, this percentage assessment rate 
is prescribed by the Department of the Treasury as the ``Treasury 
Current Value of Funds Rate.''
    (d) This rate is available in the Treasury Fiscal Requirements 
Manual Bulletins that are published prior to the first day of each 
calendar quarter for application to overdue payments or underpayments in 
the new calendar quarter. The rate is also published in the Notices 
section of the Federal Register and indexed under ``Fiscal Service/
Notices/Funds Rate; Treasury Current Value.''
    (e) Late payment charges apply to all underpayments and payments 
received after the date due. These charges include production, minimum, 
and compensatory royalties; assessments for liquidated damages; 
administrative fees and payments by purchasers of royalty taken-in-kind; 
or any other payments, fees, or assessments that a lessee/operator/
payor/royalty taken-in-kind purchaser is required to pay by a specified 
date. The failure to pay past due payments, including late payment 
charges, will result in the initiation of other enforcement proceedings.
    (f) An overpayment on a lease or leases may be offset against an 
underpayment on a different lease or leases to determine a net 
underpayment on which interest is due pursuant to conditions specified 
in 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, as amended at 57 FR 41868, Sept. 14, 1992; 57 FR 62207, 
Dec. 30, 1992; 59 FR 14559, Mar. 29, 1994; 65 FR 55189, Sept. 13, 2000; 
67 FR 19112, Apr. 18, 2002]



Sec. 218.303  May I credit rental towards royalty?

    (a)(1) For Class II leases as defined in 30 CFR 206.351, and for 
Class III leases as defined in that section that elect under 43 CFR 
3200.7(a)(2) to be subject to all of the BLM regulations promulgated for 
leases issued after August 8, 2005 you may credit the annual rental that 
you paid before the first day of the year for which the annual rental is 
owed against the royalty due for the lease year for which the rental was 
paid. You may not apply any annual rental paid in excess of the royalty 
due for a particular lease year as a credit against any royalty due in 
any subsequent lease year.
    (2) For purposes of this section, the term ``royalty'' includes any 
advanced royalty payable under 30 U.S.C. 1004(f) for a cessation of 
production.
    (b) If portions of your lease are located both within and outside of 
a participating area, you may credit against royalty under paragraph (a) 
only that percentage of the rental you paid that corresponds to the 
percentage of the lease within the participating area on a per-acre 
basis.

[72 FR 24468, May 2, 2007]



Sec. 218.304  May I credit rental towards direct use fees?

    You may not credit annual rental toward direct use fees you are 
required to pay that year under Sec. 206.356(b). You must pay the 
direct use fees in addition to the annual rental due.

[72 FR 24468, May 2, 2007]



Sec. 218.305  How do I pay advanced royalties I owe under BLM regulations?

    If you pay advanced royalties under 43 CFR 3212.15(a)(1) to retain 
your lease:
    (a) You must pay an advanced royalty monthly equal to the average 
monthly royalty you paid under 30 CFR part 206, subpart H (including the 
amount against which you applied the annual rental as a credit) for the 
last 3 years the lease was producing. If your lease has been producing 
for less than 3 years, then use the average monthly royalty payment for 
the entire period your lease has been producing continuously;
    (b) The MMS must receive your advanced royalty payment before the 
end of each full calendar month in which no production occurs;
    (c) You may credit any advanced royalty you pay against production 
royalties you owe after your lease resumes production. You may not 
reduce the amount of any production royalty paid for any year below 
zero.

[72 FR 24468, May 2, 2007]

[[Page 210]]



Sec. 218.306  May I receive a credit against production royalties for in-kind 

deliveries of electricity I provide under contract to a State or county 

government?

    (a) You may receive a credit against royalties for in-kind 
deliveries of electricity you provide under contract to a State or 
county government if:
    (1) The State or county to which you provide electricity would 
receive a portion of the royalties you paid in money for the lease under 
30 U.S.C. 191 or 30 U.S.C. 1019, except as otherwise provided under the 
Mineral Leasing Act for Acquired Lands, 30 U.S.C. 355, because your 
lease is located in that State or county. If your lease is located in 
more than one State or county, the revenues are paid to the respective 
States or counties based on their proportionate shares of the total 
acres in the lease;
    (2) The MMS approves in advance your contract with the State or 
county to which you are providing in-kind electricity; and
    (3) Your contract provides that you will use the wholesale value of 
the electricity for the area where your lease is located to establish 
the specific methodology to determine the amount of the credit; and
    (b) The maximum credit you may take under this section is equal to 
the portion of the royalty revenue that MMS would have paid to the State 
or county that is a party to the contract had you paid royalty in money 
on all of the electricity you delivered to the State or county based on 
the wholesale value of the electricity. You must pay in money any 
royalty amount that is not offset by the credit allowed under this 
section, calculated based on the wholesale value of the electricity.
    (c) The electricity the State or county government receives from you 
satisfies the Secretary's payment obligation to the State or county 
under 30 U.S.C. 191 or 30 U.S.C. 1019.

[72 FR 24468, May 2, 2007]



Sec. 218.307  How do I pay royalties due for my existing leases that qualify 

for near-term production incentives under BLM regulations?

    If you qualify for a production incentive under BLM regulations at 
43 CFR subpart 3212, your royalty due on the production BLM determines 
to be qualified for a production incentive under 43 CFR 3212.23 and 
3212.24 is 50 percent of the amount of the total royalty that would 
otherwise be due under 30 CFR part 206, subpart H.

[72 FR 24468, May 2, 2007]

Subpart G--Indian Lands [Reserved]



              Subpart H_Service of Official Correspondence

    Source: 71 FR 51751, Aug. 31, 2006, unless otherwise noted.



Sec. 218.500  What is the purpose of this subpart?

    This subpart contains instructions for designating a specific 
addressee of record for service of official correspondence using Form 
MMS-4444, Addressee of Record Designation for Service of Official 
Correspondence.



Sec. 218.520  What definitions apply to this subpart?

    Address of record is the address to which official correspondence is 
served.
    Addressee of record for service of official correspondence is the 
person or position to whom official correspondence is served, as 
specified on Form MMS-4444, or in the absence of such a form, as 
established in Sec. 218.540(b)(2). The addressee of record in a part 
290, subpart B, appeal will be the person or representative making the 
appeal.
    Official correspondence is all correspondence from MMS or our 
delegates, served on companies related to matters such as: forms 
reporting, audit and compliance, enforcement notices, rental courtesy 
notices, and invoices.



Sec. 218.540  How does MMS serve official correspondence?

    MMS will serve all Notices of Noncompliance or Civil Penalty 
following the procedures in part 241. We will serve all other documents 
following the procedures in this section.
    (a) Method of service. MMS will serve all official correspondence to 
the addressee of record by one of the following methods:

[[Page 211]]

    (1) U.S. Postal Service mail;
    (2) Personal delivery made pursuant to the law of the State in which 
the service is effected; or
    (3) Private mailing service (e.g., United Parcel Service, or Federal 
Express), with signature and date upon delivery, acknowledging the 
addressee of record's receipt of the official correspondence document.
    (b) Selection of addressee of record information. (1) We will 
address official correspondence to the party shown on the most recently 
received Form MMS-4444 for the type of correspondence at issue. The 
company or reporting entity is responsible for notifying MMS of any name 
or address changes on Form MMS-4444. The addressee of record in a part 
290, subpart B, appeal will be the person or representative making the 
appeal.
    (2) If we do not receive addressee of record information from you on 
Form MMS-4444, we may use the individual name and address, position 
title, or department name and address in our database, based on previous 
formal or informal communications or correspondence for the type of 
official correspondence at issue. Alternately, we may obtain contact 
information from public records and send correspondence to:
    (i) The registered agent;
    (ii) Any corporate officer; or
    (iii) The addressee of record shown in the files of any State 
Secretary; Corporate Commission; Federal or state agency that keeps 
official records of business entities or corporations; or other 
appropriate public records for individuals, business entities, or 
corporations.
    (c) Dates of service. Except as provided in paragraph (d) of this 
section, MMS considers official correspondence as served on the date 
that it is received at the address of record. A receipt, signed and 
dated by any person at that address, is evidence of service and of the 
date of service. If official correspondence is served in more than one 
manner and the dates differ, the date of the earliest service is 
used[smc1].
    (d) Constructive service. If we cannot make delivery to the 
addressee of record after making a reasonable effort, we deem official 
correspondence as constructively served 7 days after the date that we 
mail the document. This provision covers situations such as those where 
no delivery occurs because:
    (1) The addressee of record has moved without filing a forwarding 
address;
    (2) The forwarding order has expired;
    (3) Delivery was expressly refused; or
    (4) The document was unclaimed and the attempt to deliver is 
substantiated by either:
    (i) The U.S. Postal Service;
    (ii) A private mailing service, as described in this section; or
    (iii) The person who attempted to make delivery using some other 
method of service.



Sec. 218.560  How do I submit Form MMS-4444?

    A copy of Form MMS-4444 and instructions may be obtained from MMS. 
It will also be posted on the MMS Web site. Submit the completed, signed 
form to the address designated on the Form MMS-4444 instructions.



Sec. 218.580  When do I submit Form MMS-4444?

    Initially, you must submit MMS Form-4444 by November 29, 2006, and 
subsequently, within 2 weeks of any change of your address.



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.

[[Page 212]]

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, Minerals Revenue Management, P.O. Box 5760, 
Denver, Colorado 80217-5760.

[57 FR 41868, Sept. 14, 1992, as amended at 58 FR 64903, Dec. 10, 1993; 
67 FR 19112, Apr. 18, 2002]



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 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.

[[Page 213]]



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 further redesignated 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 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.

[[Page 214]]

    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.
    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

[[Page 215]]

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.



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.

[[Page 216]]

    (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 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

[[Page 217]]

benefits defined in this paragraph shall be excluded. In determining 
actual cost experience of an employee benefit plan, any dividend or 
refunds received that are applicable to insurance or annuity policies 
shall be used to reduce the cost of such policies.
    (c) Materiel. (1) Materiel purchased or furnished by a lessee as 
NPSL property shall be charged or credited at amounts specified in 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:
    (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

[[Page 218]]

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.
  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

[[Page 219]]

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.
    (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

[[Page 220]]

the NPSL tract by the Director shall be considered sufficient approval 
for these other costs provided they are separately identified in said 
plan of development and production. Such separate identification shall 
note the nature of these other costs and may include an estimate of 
their magnitude. Any cost approvals under this paragraph for which the 
specific amounts have not been itemized are presumed to be approved 
provided they fall within the limits for a prudent operator. Approval of 
costs under this paragraph shall be approval solely for the purposes of 
determining allowable costs and shall not preclude a subsequent 
adjustment at audit of the amount of such costs.
    (p) Other credits. Credit shall be given to the NPSL capital 
account, depending on when it is incurred, for NPSL property leased or 
used in non-NPSL operations, for the sale of information derived from 
test wells and G & G, and for any and all amounts earned or otherwise 
due lessee as a result of NPSL operations.

[45 FR 36800, May 30, 1980. Redesignated at 48 FR 1182, Jan. 11, 1983, 
and at 48 FR 35642, Aug. 5, 1983, as amended at 67 FR 19112, Apr. 18, 
2002]



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;
    (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

[[Page 221]]

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.
    (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

[[Page 222]]

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 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

[[Page 223]]

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 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

[[Page 224]]

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.
    (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.

[[Page 225]]

    (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 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

[[Page 226]]

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




                   Delegation of MMS Royalty Functions

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

                          Delegation Proposals

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

                             Hearing Process

227.105 What are the hearing procedures?

                           Delegation Process

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

                          Existing Delegations

227.111 Do existing delegation agreements remain in effect?

                              Compensation

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

         States' Responsibilities To Perform Delegated Functions

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

                           Performance Review

227.800 How will MMS monitor a State's performance of delegated 
          functions?
227.801 What if a State does not adequately perform a delegated 
          function?

[[Page 227]]

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
    (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

[[Page 228]]

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 Minerals Revenue Management. MMS will provide you with technical 
assistance and information to help you prepare your delegation proposal. 
Your proposal must contain the following minimum information:
    (a) The name and title of the State official authorized to submit 
the delegation proposal and execute the delegation agreement;
    (b) The name, address, and telephone number of the State contact for 
the proposal;
    (c) A copy of the legislation, State Attorney General opinion or 
other document that:
    (1) States which State entity or entities are responsible for 
performing delegated functions, and if more than one entity is delegated 
such responsibility, the position of the highest ranking State official 
having ultimate authority over the collection of royalties from leases 
on Federal lands within the State;
    (2) Demonstrates the State's authority to:
    (i) Accept a delegation from MMS; and
    (ii) Receive State or Federal appropriations to perform delegated 
functions;
    (d) The date you propose to begin performing delegated functions;
    (e) A detailed statement of the delegable functions that you propose 
to perform. For each function, describe the resources available in your 
State to perform each function, the procedures you will use to perform 
each function, and how you will assure that you will meet all Federal 
laws, lease terms, regulations and relevant performance standards. As 
evidence that you have or will have the resources to perform each 
delegable function, provide the following information:
    (1) A description of the personnel you have available to perform 
delegated functions, including:

[[Page 229]]

    (i) How many persons you will assign full-time and part-time to each 
delegated function;
    (ii) The technical qualifications of the key personnel you will 
assign to each function, including academic field and degree, 
professional credentials, and quality and amount of experience with 
similar functions; and
    (iii) Whether these persons are currently State employees. If not, 
explain how you propose to hire these persons or obtain their services, 
and when you expect to have those persons available to perform delegated 
functions;
    (2) A description of the facilities you will use to perform 
delegated functions, including:
    (i) Whether you currently have the facilities in which you will 
physically locate the personnel and equipment you will need to perform 
the functions you propose to assume. If not, how you propose to acquire 
such facilities, and when you expect to have such facilities available; 
and
    (ii) How much office space is available;
    (3) Describe the equipment you will use to perform delegated 
functions, including:
    (i) Hardware and software you will use to perform each delegated 
function, including equipment for:
    (A) Document processing, including compatibility with MMS automated 
systems, electronic commerce capabilities, and data storage 
capabilities;
    (B) Accessing reference data;
    (C) Contacting production or royalty reporters;
    (D) Issuing demands;
    (E) Maintaining accounting records;
    (F) Performing automated verification;
    (G) Maintaining security of confidential and proprietary 
information; and
    (H) Providing data to other Federal agencies;
    (ii) Whether you currently have the equipment you will need to 
perform the functions you propose to assume. If not, how you propose to 
acquire such equipment and when you expect to have such equipment 
available;
    (f) Your estimates of the costs to fund the following resources 
necessary to perform the delegation:
    (1) Personnel, including hiring, employee salaries and benefits, 
travel and training;
    (2) Facilities, including acquisition, upgrades, operation, and 
maintenance; and
    (3) Equipment, including acquisition, operation, and maintenance;
    (g) Your plans to fund the resources under paragraph (f) of this 
section, including any items you will ask MMS to fund under the 
delegation agreement;
    (h) A statement identifying any areas where State law, including 
State appropriation law, may limit your ability to perform delegated 
functions, and an explanation of how you propose to remove any such 
limitation;
    (i) A statement that in accordance with section 203 of the Act (30 
U.S.C. 1733) persons who have access to information received under 
delegated functions are subject to the same provisions of law regarding 
confidentiality and disclosure of that information as Federal employees. 
Applicable laws include the Freedom of Information Act (FOIA), the Trade 
Secrets Act, and relevant Executive Orders. In addition, your statement 
must acknowledge that all documents produced, received, and maintained 
as part of any delegation functions are agency records for purposes of 
FOIA. Therefore, persons who have access to information received under 
delegated functions may not use such information or provide such 
information to any other person, including State personnel, for purposes 
other than performing delegated functions. However, this limitation does 
not apply if the person submitting the information consents in writing 
to its use for other State purposes.

[62 FR 43084, Aug. 12, 1997, as amended at 67 FR 19112, Apr. 18, 2002]



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

[[Page 230]]

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 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.

[[Page 231]]



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 Minerals Revenue Management as follows:
    (1) If you do not want to change the terms of your delegation 
agreement for the renewal period, you need only ask to extend your 
existing agreement for the 3-year renewal period. MMS will not schedule 
a hearing unless you request one;
    (2) If you want to change the terms of your delegation agreement for 
the renewal period, you must submit a new delegation proposal under this 
part.
    (c) The MMS Director may approve your renewal request only if MMS 
determines that you are meeting the requirements of the applicable 
standards and regulations. If the MMS Director denies your renewal 
request, MMS will state the reasons for denial. MMS also will inform you 
in writing of the conditions you must meet to receive approval. You may 
submit a new renewal request any time after denial.
    (d) After the 3-year renewal period for your delegation agreement 
ends, if you wish to continue performing one or more delegated 
functions, you must request a new delegation agreement from MMS under 
this part. MMS will schedule a hearing on your request, if MMS 
determines a hearing is appropriate. As part of the decision whether to 
approve your request for a new delegation, the MMS Director will 
consider whether you are meeting the requirements of the applicable 
standards and regulations under your existing delegation agreement.
    (e) If you do not request a hearing under paragraphs (b)(1) or (d) 
of this section, any other affected person may submit a written request 
for a hearing under those paragraphs to the MMS Associate Director for 
Minerals Revenue Management.

[62 FR 43084, Aug. 12, 1997, as amended at 67 FR 19112, Apr. 18, 2002]

                          Existing Delegations



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 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.

[[Page 232]]

                              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;
    (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:

[[Page 233]]

    (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 Sec. Sec. 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;
    (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

[[Page 234]]

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 
production reporter handbook, 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.

[62 FR 43084, Aug. 12, 1997, as amended at 67 FR 19112, Apr. 18, 2002]



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 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;

[[Page 235]]

    (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 
in a timely manner as provided in the Standards and 30 CFR part 219; and
    (d) Comply with the procedures for appealed demands or orders, 
including meeting timeframes, supplying information, and using the 
appropriate format.

[62 FR 43064, Aug. 12, 1997, as amended at 67 FR 19112, Apr. 18, 2002]



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
    (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.

[[Page 236]]



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;
    (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

[[Page 237]]

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:
    (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

[[Page 238]]

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.
    (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

[[Page 239]]

U.S.C. 1702. In addition, the following definition shall apply:
    Audit means an examination of the financial accounting and lease 
related records of the lessee and other interest holders, who by lease 
or contract pay royalties or are obligated to pay royalties, rents, 
bonuses or other payments on Federal or Indian leases. An examination is 
to be conducted in accordance with generally accepted audit standards as 
adopted by the American Institute of Certified Public Accountants. 
Activities to be examined which are considered to be an audit function 
include reconciliation of lease accounts under the Royalty Accounting 
System; records of lease activities related to Federal leases located 
within the boundaries of the State entering into a cooperative 
agreement; records of lease activities related to leases located on 
Indian lands, and the review and resolution of exceptions processed by 
the official accounting systems for royalty reporters and payors 
maintained by the MMS.

[49 FR 37348, Sept. 21, 1984, as amended at 67 FR 19112, Apr. 18, 2002]



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 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

[[Page 240]]

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.
    (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;

[[Page 241]]

    (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.



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.

[[Page 242]]

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.).

                      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

[[Page 243]]

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);
    (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

[[Page 244]]

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 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

[[Page 245]]

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--
    (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

[[Page 246]]

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 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.

[[Page 247]]



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 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.

[[Page 248]]

    (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 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

[[Page 249]]

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 [RESERVED]

                  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?

                           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]


[[Page 250]]


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

Subpart A--General Provisions [Reserved]



      Subpart B_Penalties for Federal and Indian Oil and Gas Leases

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

                               Definitions



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 serve the Notice of Noncompliance by registered mail or 
personal service using your address of record as specified under subpart 
H of part 218.

[64 FR 26251, May 13, 1999, as amended at 71 FR 51752, Aug. 31, 2006]



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, 801 North Quincy 
Street, Arlington, Virginia 22203. You may do this regardless of whether 
you correct the violations identified in the Notice of Noncompliance.

[64 FR 26251, May 13, 1999, as amended at 67 FR 19112, Apr. 18, 2002]



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.

[[Page 251]]

    (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. 241.56  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, 801 
North Quincy Street, Arlington, Virginia 22203.

[64 FR 26251, May 13, 1999, as amended at 67 FR 19113, Apr. 18, 2002]

                  Penalties Without a Period To Correct



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 any violation, without a period to correct, by 
issuing a Notice of Noncompliance and Civil Penalty explaining the 
violation, how to correct it, and the penalty assessment. We will serve 
the Notice of Noncompliance and Civil Penalty by registered mail or 
personal service using your address of record as specified under subpart 
H of part 218.

[71 FR 51752, Aug. 31, 2006]



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

[[Page 252]]

Interior, 801 North Quincy Street, Arlington, Virginia 22203. You may do 
this regardless of whether you correct the violations identified in the 
Notice of Noncompliance.

[64 FR 26251, May 13, 1999, as amended at 67 FR 19113, Apr. 18, 2002]



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 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, 801 
North Quincy Street, Arlington, Virginia 22203.

[64 FR 26251, May 13, 1999, as amended at 67 FR 19113, Apr. 18, 2002]

                           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 Sec. Sec. 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

[[Page 253]]

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 Sec. Sec. 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.
    (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]

[[Page 254]]

Subpart I--OCS Sulfur [Reserved]

                       PART 242_ORDERS [RESERVED]



PART 243_SUSPENSIONS PENDING APPEAL AND BONDING_MINERALS REVENUE MANAGEMENT--

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?
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 Minerals 
Revenue Management or an official to whom the Associate Director 
delegates that responsibility.

[[Page 255]]

    MMS-specified surety instrument means an MMS-specified 
administrative appeal bond, an MMS-specified irrevocable letter of 
credit, a Treasury book-entry bond or note, or a financial institution 
book-entry certificate of deposit.
    Notice of order means the notice that MMS or a delegated State 
issues to a lessee that informs the lessee that MMS or the delegated 
State has issued an order to the lessee's designee.
    Order means an order appealable under 30 CFR part 290 in effect 
prior to May 13, 1999 and contained in the 30 CFR, parts 200 to 699, 
edition revised as of July 1, 1998, under 30 CFR part 290 subpart B, or 
under 30 CFR part 208.
    Person means any individual, firm, corporation, association, 
partnership, consortium, or joint venture.

[64 FR 26254, May 13, 1999, as amended at 67 FR 19113, Apr. 18, 2002]



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

[[Page 256]]

MMS for OCS leases, as collateral for the obligation; or
    (2) If the amount under appeal is $10,000 or more, MMS will suspend 
your obligation to comply with that order if you:
    (i) Submit an MMS-specified surety instrument under subpart B of 
this part within a time period MMS prescribes; or
    (ii) Demonstrate financial solvency under subpart C.
    (b) Indian leases.Subject to paragraph (d) of this section, if you 
appeal an order regarding the payment and reporting of royalties and 
other payments due from Indian mineral leases subject to this part, and:
    (1) If the amount under appeal is less than $1,000 or does not 
require payment, MMS will suspend your obligation to comply with the 
order. MMS will use the lease surety posted with the Bureau of Indian 
Affairs as collateral for the obligation; or
    (2) If the amount under appeal is $1,000 or more, MMS will suspend 
your obligation to comply with that order if you submit an MMS-specified 
surety instrument under subpart B of this part within a time period MMS 
prescribes.
    (c) Nothing in this part prohibits you from paying any demanded 
amount or complying with any other requirement pending appeal. However, 
voluntarily paying any demanded amount or otherwise complying with any 
other requirement when suspension of an order is otherwise available 
under these rules does not create judicially reviewable final agency 
action under 5 U.S.C. 704.
    (d) Regardless of the amount under appeal, MMS may inform you that 
it will not suspend your obligation to comply with the order under 
paragraph (a) or (b) of this section because suspension would harm the 
interests of the United States or the Indian lessor.



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

[[Page 257]]

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.



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

[[Page 258]]

    (2) Courier or overnight delivery at MS 3031, Denver Federal Center, 
Bldg. 85, Room A-212, Denver, CO 80225-0165.
    (b) You must submit an audited consolidated balance sheet annually, 
and, if requested, additional annual tax returns on the date MMS first 
determined that you demonstrated financial solvency as long as you have 
active appeals, or whenever MMS requests.
    (c) If you demonstrate financial solvency in the current calendar 
year, you are not required to redemonstrate financial solvency for new 
appeals of orders during that calendar year unless you file for 
protection under any provision of the U.S. Bankruptcy Code (Title 11 of 
the United States Code), or MMS notifies you that you must redemonstrate 
financial solvency.



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 
Sec. Sec. 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

[[Page 259]]

other MMS-specified surety instrument under subpart B.

[[Page 260]]



                          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?

                                  Fees

250.125 Service fees.
250.126 General payment instructions.

                        Inspection of Operations

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

                            Disqualification

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

                       Special Types of Approvals

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

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

250.150 How do I name facilities and wells in the Gulf of Mexico Region?
250.151 How do I name facilities in the Pacific Region?
250.152 How do I name facilities in the Alaska Region?
250.153 Do I have to rename an existing facility or well?
250.154 What identification signs must I display?

                        Right-of-Use and Easement

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

[[Page 261]]

250.166 If I have a State lease, what surety bond must I have for a 
          right-of-use and easement?

                               Suspensions

250.168 May operations or production be suspended?
250.169 What effect does suspension have on my lease?
250.170 How long does a suspension last?
250.171 How do I request a suspension?
250.172 When may the Regional Supervisor grant or direct an SOO or SOP?
250.173 When may the Regional Supervisor direct an SOO or SOP?
250.174 When may the Regional Supervisor grant or direct an SOP?
250.175 When may the Regional Supervisor grant an SOO?
250.176 Does a suspension affect my royalty payment?
250.177 What additional requirements may the Regional Supervisor order 
          for a suspension?

      Primary Lease Requirements, Lease Term Extensions, and Lease 
                              Cancellations

250.180 What am I required to do to keep my lease term in effect?
250.181 When may the Secretary cancel my lease and when am I compensated 
          for cancellation?
250.182 When may the Secretary cancel a lease at the exploration stage?
250.183 When may MMS or the Secretary extend or cancel a lease at the 
          development and production stage?
250.184 What is the amount of compensation for lease cancellation?
250.185 When is there no compensation for a lease cancellation?

                 Information and Reporting Requirements

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

                               References

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

                     Subpart B_Plans and Information

                           General Information

250.200 Definitions.
250.201 What plans and information must I submit before I conduct any 
          activities on my lease or unit?
250.202 What criteria must the Exploration Plan (EP), Development and 
          Production Plan (DPP), or Development Operations Coordination 
          Document (DOCD) meet?
250.203 Where can wells be located under an EP, DPP, or DOCD?
250.204 How must I protect the rights of the Federal government?
250.205 Are there special requirements if my well affects an adjacent 
          property?
250.206 How do I submit the EP, DPP, or DOCD?

                          Ancillary Activities

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

                   Contents of Exploration Plans (EP)

250.211 What must the EP include?
250.212 What information must accompany the EP?
250.213 What general information must accompany the EP?
250.214 What geological and geophysical (G&G) information must accompany 
          the EP?
250.215 What hydrogen sulfide (H2S) information must 
          accompany the EP?
250.216 What biological, physical, and socioeconomic information must 
          accompany the EP?
250.217 What solid and liquid wastes and discharges information and 
          cooling water intake information must accompany the EP?
250.218 What air emissions information must accompany the EP?
250.219 What oil and hazardous substance spills information must 
          accompany the EP?

[[Page 262]]

250.220 If I propose activities in the Alaska OCS Region, what planning 
          information must accompany the EP?
250.221 What environmental monitoring information must accompany the EP?
250.222 What lease stipulations information must accompany the EP?
250.223 What mitigation measures information must accompany the EP?
250.224 What information on support vessels, offshore vehicles, and 
          aircraft you will use must accompany the EP?
250.225 What information on the onshore support facilities you will use 
          must accompany the EP?
250.226 What Coastal Zone Management Act (CZMA) information must 
          accompany the EP?
250.227 What environmental impact analysis (EIA) information must 
          accompany the EP?
250.228 What administrative information must accompany the EP?

                 Review and Decision Process for the EP

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

   Contents of Development and Production Plans (DPP) and Development 
                Operations Coordination Documents (DOCD)

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

             Review and Decision Process for the DPP or DOCD

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

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

250.280 How must I conduct activities under the approved EP, DPP, or 
          DOCD?
250.281 What must I do to conduct activities under the approved EP, DPP, 
          or DOCD?
250.282 Do I have to conduct post-approval monitoring?

[[Page 263]]

250.283 When must I revise or supplement the approved EP, DPP, or DOCD?
250.284 How will MMS require revisions to the approved EP, DPP, or DOCD?
250.285 How do I submit revised and supplemental EPs, DPPs, or DOCDs?

                    Deepwater Operations Plans (DWOP)

250.286 What is a DWOP?
250.287 For what development projects must I submit a DWOP?
250.288 When and how must I submit the Conceptual Plan?
250.289 What must the Conceptual Plan contain?
250.290 What operations require approval of the Conceptual Plan?
250.291 When and how must I submit the DWOP?
250.292 What must the DWOP contain?
250.293 What operations require approval of the DWOP?
250.294 May I combine the Conceptual Plan and the DWOP?
250.295 When must I revise my DWOP?

                Conservation Information Documents (CID)

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

               Subpart C_Pollution Prevention and Control

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

                Subpart D_Oil and Gas Drilling Operations

                          General Requirements

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

                     Applying for a Permit To Drill

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

                    Casing and Cementing Requirements

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

                      Diverter System Requirements

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

               Blowout Preventer (BOP) System Requirements

250.440 What are the general requirements for BOP systems and system 
          components?

[[Page 264]]

250.441 What are the requirements for a surface BOP stack?
250.442 What are the requirements for a subsea BOP stack?
250.443 What associated systems and related equipment must all BOP 
          systems include?
250.444 What are the choke manifold requirements?
250.445 What are the requirements for kelly valves, inside BOPs, and 
          drill-string safety valves?
250.446 What are the BOP maintenance and inspection requirements?
250.447 When must I pressure test the BOP system?
250.448 What are the BOP pressure tests requirements?
250.449 What additional BOP testing requirements must I meet?
250.450 What are the recordkeeping requirements for BOP tests?
250.451 What must I do in certain situations involving BOP equipment or 
          systems?

                       Drilling Fluid Requirements

250.455 What are the general requirements for a drilling fluid program?
250.456 What safe practices must the drilling fluid program follow?
250.457 What equipment is required to monitor drilling fluids?
250.458 What quantities of drilling fluids are required?
250.459 What are the safety requirements for drilling fluid-handling 
          areas?

                       Other Drilling Requirements

250.460 What are the requirements for conducting a well test?
250.461 What are the requirements for directional and inclination 
          surveys?
250.462 What are the requirements for well-control drills?
250.463 Who establishes field drilling rules?

            Applying for a Permit To Modify and Well Records

250.465 When must I submit an Application for Permit to Modify (AMP) or 
          an End of Operations Report to MMS?
250.466 What records must I keep?
250.467 How long must I keep records?
250.468 What well records am I required to submit?
250.469 What other well records could I be required to submit?

                            Hydrogen Sulfide

250.490 Hydrogen sulfide.

            Subpart E_Oil and Gas Well-Completion Operations

250.500 General requirements.
250.501 Definition.
250.502 Equipment movement.
250.503 Emergency shutdown system.
250.504 Hydrogen sulfide.
250.505 Subsea completions.
250.506 Crew instructions.
250.507-250.508 [Reserved]
250.509 Well-completion structures on fixed platforms.
250.510 Diesel engine air intakes.
250.511 Traveling-block safety device.
250.512 Field well-completion rules.
250.513 Approval and reporting of well-completion operations.
250.514 Well-control fluids, equipment, and operations.
250.515 Blowout prevention equipment.
250.516 Blowout preventer system tests, inspections, and maintenance.
250.517 Tubing and wellhead equipment.

             Subpart F_Oil and Gas Well-Workover Operations

250.600 General requirements.
250.601 Definitions.
250.602 Equipment movement.
250.603 Emergency shutdown system.
250.604 Hydrogen sulfide.
250.605 Subsea workovers.
250.606 Crew instructions.
250.607-250.608 [Reserved]
250.609 Well-workover structures on fixed platforms.
250.610 Diesel engine air intakes.
250.611 Traveling-block safety device.
250.612 Field well-workover rules.
250.613 Approval and reporting for well-workover operations.
250.614 Well-control fluids, equipment, and operations.
250.615 Blowout prevention equipment.
250.616 Blowout preventer system testing, records, and drills.
250.617 Tubing and wellhead equipment.
250.618 Wireline operations.

Subpart G [Reserved]

             Subpart H_Oil and Gas Production Safety Systems

250.800 General requirements.
250.801 Subsurface safety devices.
250.802 Design, installation, and operation of surface production-safety 
          systems.
250.803 Additional production system requirements.
250.804 Production safety-system testing and records.
250.805 Safety device training.
250.806 Safety and pollution prevention equipment quality assurance 
          requirements.
250.807 Hydrogen sulfide.

[[Page 265]]

                   Subpart I_Platforms and Structures

                   General Requirements for Platforms

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

                        Platform Approval Program

250.904 What is the Platform Approval Program?
250.905 How do I get approval for the installation, modification, or 
          repair of my platform?
250.906 What must I do to obtain approval for the proposed site of my 
          platform?
250.907 Where must I locate foundation boreholes?
250.908 What are the minimum structural fatigue design requirements?

                      Platform Verification Program

250.909 What is the Platform Verification Program?
250.910 Which of my facilities are subject to the Platform Verification 
          Program?
250.911 If my platform is subject to the Platform Verification Program, 
          what must I do?
250.912 What plans must I submit under the Platform Verification 
          Program?
250.913 When must I resubmit Platform Verification Program plans?
250.914 How do I nominate a CVA?
250.915 What are the CVA's primary responsibilities?
250.916 What are the CVA's primary duties during the design phase?
250.917 What are the CVA's primary duties during the fabrication phase?
250.918 What are the CVA's primary duties during the installation phase?

          Inspection, Maintenance, and Assessment of Platforms

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

             Subpart J_Pipelines and Pipeline Rights-of-Way

250.1000 General requirements.
250.1001 Definitions.
250.1002 Design requirements for DOI pipelines.
250.1003 Installation, testing and repair requirements for DOI 
          pipelines.
250.1004 Safety equipment requirements for DOI pipelines.
250.1005 Inspection requirements for DOI pipelines.
250.1006 Abandonment and out-of-service requirements for DOI pipelines.
250.1007 What to include in applications.
250.1008 Reports.
250.1009 Requirements to obtain pipeline right-of-way grants.
250.1010 General requirements for pipeline right-of-way holders.
250.1011 Bond requirements for pipeline right-of-way holders.
250.1012 Required payments for pipeline right-of-way holders.
250.1013 Grounds for forfeiture of pipeline right-of-way grants.
250.1014 When pipeline right-of-way grants expire.
250.1015 Applications for pipeline right-of-way grants.
250.1016 Granting pipeline rights-of-way.
250.1017 Requirements for construction under pipeline right-of-way 
          grants.
250.1018 Assignment of pipeline right-of-way grants.
250.1019 Relinquishment of pipeline right-of-way grants.

                 Subpart K_Oil and Gas Production Rates

250.1100 Definitions for production rates.
250.1101 General requirements and classification of reservoirs.
250.1102 Oil and gas production rates.
250.1103 Well production testing.
250.1104 Bottomhole pressure survey.
250.1105 Flaring or venting gas and burning liquid hydrocarbons.
250.1106 Downhole commingling.
250.1107 Enhanced oil and gas recovery operations.

 Subpart L_Oil and Gas Production Measurement, Surface Commingling, and 
                                Security

250.1200 Question index table.
250.1201 Definitions.
250.1202 Liquid hydrocarbon measurement.
250.1203 Gas measurement.
250.1204 Surface commingling.
250.1205 Site security.

                          Subpart M_Unitization

250.1300 What is the purpose of this subpart?
250.1301 What are the requirements for unitization?
250.1302 What if I have a competitive reservoir on a lease?
250.1303 How do I apply for voluntary unitization?
250.1304 How will MMS require unitization?

[[Page 266]]

         Subpart N_Outer Continental Shelf (OCS) Civil Penalties

250.1400 How does MMS begin the civil penalty process?
250.1401 Index table.
250.1402 Definitions.
250.1403 What is the maximum civil penalty?
250.1404 Which violations will MMS review for potential civil penalties?
250.1405 When is a case file developed?
250.1406 When will MMS notify me and provide penalty information?
250.1407 How do I respond to the letter of notification?
250.1408 When will I be notified of the Reviewing Officer's decision?
250.1409 What are my appeal rights?

          Subpart O_Well Control and Production Safety Training

250.1500 Definitions.
250.1501 What is the goal of my training program?
250.1502 Is there a transition period for complying with the regulations 
          in this subpart?
250.1503 What are my general responsibilities for training?
250.1504 May I use alternative training methods?
250.1505 Where may I get training for my employees?
250.1506 How often must I train my employees?
250.1507 How will MMS measure training results?
250.1508 What must I do when MMS administers written or oral tests?
250.1509 What must I do when MMS administers or requires hands-on, 
          simulator, or other types of testing?
250.1510 What will MMS do if my training program does not comply with 
          this subpart?

                      Subpart P_Sulphur Operations

250.1600 Performance standard.
250.1601 Definitions.
250.1602 Applicability.
250.1603 Determination of sulphur deposit.
250.1604 General requirements.
250.1605 Drilling requirements.
250.1606 Control of wells.
250.1607 Field rules.
250.1608 Well casing and cementing.
250.1609 Pressure testing of casing.
250.1610 Blowout preventer systems and system components.
250.1611 Blowout preventer systems tests, actuations, inspections, and 
          maintenance.
250.1612 Well-control drills.
250.1613 Diverter systems.
250.1614 Mud program.
250.1615 Securing of wells.
250.1616 Supervision, surveillance, and training.
250.1617 Application for permit to drill.
250.1618 Application for permit to modify.
250.1619 Well records.
250.1620 Well-completion and well-workover requirements.
250.1621 Crew instructions.
250.1622 Approvals and reporting of well-completion and well-workover 
          operations.
250.1623 Well-control fluids, equipment, and operations.
250.1624 Blowout prevention equipment.
250.1625 Blowout preventer system testing, records, and drills.
250.1626 Tubing and wellhead equipment.
250.1627 Production requirements.
250.1628 Design, installation, and operation of production systems.
250.1629 Additional production and fuel gas system requirements.
250.1630 Safety-system testing and records.
250.1631 Safety device training.
250.1632 Production rates.
250.1633 Production measurement.
250.1634 Site security.

                  Subpart Q_Decommissioning Activities

                                 General

250.1700 What do the terms ``decommissioning'', ``obstructions'', and 
          ``facility'' mean?
250.1701 Who must meet the decommissioning obligations in this subpart?
250.1702 When do I accrue decommissioning obligations?
250.1703 What are the general requirements for decommissioning?
250.1704 When must I submit decommissioning applications and reports?

                       Permanently Plugging Wells

250.1710 When must I permanently plug all wells on a lease?
250.1711 When will MMS order me to permanently plug a well?
250.1712 What information must I submit before I permanently plug a well 
          or zone?
250.1713 Must I notify MMS before I begin well plugging operations?
250.1714 What must I accomplish with well plugs?
250.1715 How must I permanently plug a well?
250.1716 To what depth must I remove wellheads and casings?
250.1717 After I permanently plug a well, what information must I 
          submit?

                        Temporary Abandoned Wells

250.1721 If I temporarily abandon a well that I plan to re-enter, what 
          must I do?

[[Page 267]]

250.1722 If I install a subsea protective device, what requirements must 
          I meet?
250.1723 What must I do when it is no longer necessary to maintain a 
          well in temporary abandoned status?

                 Removing Platforms and Other Facilities

250.1725 When do I have to remove platforms and other facilities?
250.1726 When must I submit an initial platform removal application and 
          what must it include?
250.1727 What information must I include in my final application to 
          remove a platform or other facility?
250.1728 To what depth must I remove a platform or other facility?
250.1729 After I remove a platform or other facility, what information 
          must I submit?
250.1730 When might MMS approve partial structure removal or toppling in 
          place?

        Site Clearance for Wells, Platforms, and Other Facilities

250.1740 How must I verify that the site of a permanently plugged well, 
          removed platform, or other removed facility is clear of 
          obstructions?
250.1741 If I drag a trawl across a site, what requirements must I meet?
250.1742 What other methods can I use to verify that a site is clear?
250.1743 How do I certify that a site is clear of obstructions?

                        Pipeline Decommissioning

250.1750 When may I decommission a pipeline in place?
250.1751 How do I decommission a pipeline in place?
250.1752 How do I remove a pipeline?
250.1753 After I decommission a pipeline, what information must I 
          submit?
250.1754 When must I remove a pipeline decommissioned in place?

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

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

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



                            Subpart A_General

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

                    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
------------------------------------------------------------------------
                                          Refer to  30 CFR 250  subpart
         For information about                          or
------------------------------------------------------------------------
(1) Applications for permit to drill...  D.
(2) Development and Production Plans     B.
 (DPP).
(3) Downhole commingling...............  K.
(4) Exploration Plans (EP).............  B.

[[Page 268]]

 
(5) Flaring............................  K.
(6) Gas measurement....................  L.
(7) Off-lease geological and             30 CFR 251.
 geophysical permits.
(8) Oil spill financial responsibility   30 CFR 253.
 coverage.
(9) Oil and gas production safety        H.
 systems.
(10) Oil spill response plans..........  30 CFR 254.
(11) Oil and gas well-completion         E.
 operations.
(12) Oil and gas well-workover           F.
 operations.
(13) Decommissioning Activities........  Q.
(14) Platforms and structures..........  I.
(15) Pipelines and Pipeline Rights-of-   J.
 Way.
(16) Sulphur operations................  P.
(17) Training..........................  O.
(18) Unitization.......................  M.
------------------------------------------------------------------------


[64 FR 72775, Dec. 28, 1999, as amended at 67 FR 35405, May 17, 2002; 68 
FR 8422, Feb. 20, 2003; 70 FR 51500, Aug. 30, 2005; 72 FR 25198, May 4, 
2007]



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:
    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

[[Page 269]]

include, but is not limited to, identification of lithologic and fossil 
content, core analysis, laboratory analyses of physical and chemical 
properties, well logs or charts, results from formation fluid tests, and 
descriptions of hydrocarbon occurrences or hazardous conditions.
    Ancillary activities means those activities on your lease or unit 
that you:
    (1) Conduct to obtain data and information to ensure proper 
exploration or development of your lease or unit; and
    (2) Can conduct without MMS approval of an application or permit.
    Archaeological interest means capable of providing scientific or 
humanistic understanding of past human behavior, cultural adaptation, 
and related topics through the application of scientific or scholarly 
techniques, such as controlled observation, contextual measurement, 
controlled collection, analysis, interpretation, and explanation.
    Archaeological resource means any material remains of human life or 
activities that are at least 50 years of age and that are of 
archaeological interest.
    Attainment area means, for any air pollutant, an area that is shown 
by monitored data or that is calculated by air quality modeling (or 
other methods determined by the Administrator of EPA to be reliable) not 
to exceed any primary or secondary ambient air quality standards 
established by EPA.
    Best available and safest technology (BAST) means the best available 
and safest technologies that the Director determines to be economically 
feasible wherever failure of equipment would have a significant effect 
on safety, health, or the environment.
    Best available control technology (BACT) means an emission 
limitation based on the maximum degree of reduction for each air 
pollutant subject to regulation, taking into account energy, 
environmental and economic impacts, and other costs. The Regional 
Director will verify the BACT on a case-by-case basis, and it may 
include reductions achieved through the application of processes, 
systems, and techniques for the control of each air pollutant.
    Coastal environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the terrestrial ecosystem 
from the shoreline inward to the boundaries of the coastal zone.
    Coastal zone means the coastal waters (including the lands therein 
and thereunder) and the adjacent shorelands (including the waters 
therein and thereunder) strongly influenced by each other and in 
proximity to the shorelands of the several coastal States. The coastal 
zone includes islands, transition and intertidal areas, salt marshes, 
wetlands, and beaches. The coastal zone extends seaward to the outer 
limit of the U.S. territorial sea and extends inland from the shorelines 
to the extent necessary to control shorelands, the uses of which have a 
direct and significant impact on the coastal waters, and the inward 
boundaries of which may be identified by the several coastal States, 
under the authority in section 305(b)(1) of the Coastal Zone Management 
Act (CZMA) of 1972.
    Competitive reservoir means a reservoir in which there are one or 
more producible or producing well completions on each of two or more 
leases or portions of leases, with different lease operating interests, 
from which the lessees plan future production.
    Correlative rights when used with respect to lessees of adjacent 
leases, means the right of each lessee to be afforded an equal 
opportunity to explore for, develop, and produce, without waste, 
minerals from a common source.
    Data means facts and statistics, measurements, or samples that have 
not been analyzed, processed, or interpreted.
    Departures means approvals granted by the appropriate MMS 
representative for operating requirements/procedures other than those 
specified in the regulations found in this part. These requirements/
procedures may be necessary to control a well; properly develop a lease; 
conserve natural resources, or protect life, property, or the marine, 
coastal, or human environment.
    Development means those activities that take place following 
discovery of minerals in paying quantities, including but not limited to 
geophysical activity, drilling, platform construction,

[[Page 270]]

and operation of all directly related onshore support facilities, and 
which are for the purpose of producing the minerals discovered.
    Development geological and geophysical (G&G) activities means those 
G&G and related data-gathering activities on your lease or unit that you 
conduct following discovery of oil, gas, or sulphur in paying quantities 
to detect or imply the presence of oil, gas, or sulphur in commercial 
quantities.
    Director means the Director of MMS of the U.S. Department of the 
Interior, or an official authorized to act on the Director's behalf.
    District Manager means the MMS officer with authority and 
responsibility for operations or other designated program functions for 
a district within an MMS Region.
    Easement means an authorization for a nonpossessory, nonexclusive 
interest in a portion of the OCS, whether leased or unleased, which 
specifies the rights of the holder to use the area embraced in the 
easement in a manner consistent with the terms and conditions of the 
granting authority.
    Eastern Gulf of Mexico means all OCS areas of the Gulf of Mexico the 
Director decides are adjacent to the State of Florida. The Eastern Gulf 
of Mexico is not the same as the Eastern Planning Area, an area 
established for OCS lease sales.
    Emission offsets means emission reductions obtained from facilities, 
either onshore or offshore, other than the facility or facilities 
covered by the proposed Exploration Plan (EP) or Development and 
Production Plan (DPP).
    Enhanced recovery operations means pressure maintenance operations, 
secondary and tertiary recovery, cycling, and similar recovery 
operations that alter the natural forces in a reservoir to increase the 
ultimate recovery of oil or gas.
    Existing facility, as used in 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, all installations permanently or 
temporarily attached to the seabed on the OCS (including manmade islands 
and bottom-sitting structures). They include mobile offshore drilling 
units (MODUs) or other vessels engaged in drilling or downhole 
operations, used for oil, gas or sulphur drilling, production, or 
related activities. They include all floating production systems (FPSs), 
variously described as column-stabilized-units (CSUs); floating 
production, storage and offloading facilities (FPSOs); tension-leg 
platforms (TLPs); spars, etc. They also include facilities for product 
measurement and royalty determination (e.g., lease Automatic Custody 
Transfer Units, gas meters) of OCS production on installations not on 
the OCS. Any group of OCS installations interconnected with walkways, or 
any group of installations that includes a central or primary 
installation with processing equipment and one or more satellite or 
secondary installations is a single facility. The Regional Supervisor 
may decide that the complexity of the individual installations justifies 
their classification as separate facilities.
    (2) As used in Sec. 250.303, means all installations or devices 
permanently or temporarily attached to the seabed. They include mobile 
offshore drilling units (MODUs), even while operating in the ``tender 
assist'' mode (i.e. with skid-off drilling units) or other vessels 
engaged in drilling or downhole operations. They are used for 
exploration, development, and production activities for oil, gas, or 
sulphur and emit or have the potential to emit any air pollutant from 
one or more sources. They

[[Page 271]]

include all floating production systems (FPSs), including column-
stabilized-units (CSUs); floating production, storage and offloading 
facilities (FPSOs); tension-leg platforms (TLPs); spars, etc. During 
production, multiple installations or devices are a single facility if 
the installations or devices are at a single site. Any vessel used to 
transfer production from an offshore facility is part of the facility 
while it is physically attached to the facility.
    (3) As used in Sec. 250.490(b), means a vessel, a structure, or an 
artificial island used for drilling, well completion, well-workover, or 
production operations.
    (4) As used in Sec. Sec. 250.900 through 250.921, means all 
installations or devices permanently or temporarily attached to the 
seabed. They are used for exploration, development, and production 
activities for oil, gas, or sulphur and emit or have the potential to 
emit any air pollutant from one or more sources. They include all 
floating production systems (FPSs), including column-stabilized-units 
(CSUs); floating production, storage and offloading facilities (FPSOs); 
tension-leg platforms (TLPs); spars, etc. During production, multiple 
installations or devices are a single facility if the installations or 
devices are at a single site. Any vessel used to transfer production 
from an offshore facility is part of the facility while it is physically 
attached to the facility.
    Gas reservoir means a reservoir that contains hydrocarbons 
predominantly in a gaseous (single-phase) state.
    Gas-well completion means a well completed in a gas reservoir or in 
the associated gas-cap of an oil reservoir.
    Geological and geophysical (G&G) explorations means those G&G 
surveys on your lease or unit that use seismic reflection, seismic 
refraction, magnetic, gravity, gas sniffers, coring, or other systems to 
detect or imply the presence of oil, gas, or sulphur in commercial 
quantities.
    Governor means the Governor of a State, or the person or entity 
designated by, or under, State law to exercise the powers granted to 
such Governor under the Act.
    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.

[[Page 272]]

    Lessee means a person who has entered into a lease with the United 
States to explore for, develop, and produce the leased minerals. The 
term lessee also includes the MMS-approved assignee of the lease, and 
the owner or the MMS-approved assignee of operating rights for the 
lease.
    Major Federal action means any action or proposal by the Secretary 
that is subject to the provisions of section 102(2)(C) of the National 
Environmental Policy Act of 1969, 42 U.S.C. (2)(C) (i.e., an action that 
will have a significant impact on the quality of the human environment 
requiring preparation of an environmental impact statement under section 
102(2)(C) of the National Environmental Policy Act).
    Marine environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the marine ecosystem. 
These include the waters of the high seas, the contiguous zone, 
transitional and intertidal areas, salt marshes, and wetlands within the 
coastal zone and on the OCS.
    Material remains means physical evidence of human habitation, 
occupation, use, or activity, including the site, location, or context 
in which such evidence is situated.
    Maximum efficient rate (MER) means the maximum sustainable daily oil 
or gas withdrawal rate from a reservoir that will permit economic 
development and depletion of that reservoir without detriment to 
ultimate recovery.
    Maximum production rate (MPR) means the approved maximum daily rate 
at which oil or gas may be produced from a specified oil-well or gas-
well completion.
    Minerals includes oil, gas, sulphur, geopressured-geothermal and 
associated resources, and all other minerals that are authorized by an 
Act of Congress to be produced.
    Natural resources includes, without limiting the generality thereof, 
oil, gas, and all other minerals, and fish, shrimp, oysters, clams, 
crabs, lobsters, sponges, kelp, and other marine animal and plant life 
but does not include water power or the use of water for the production 
of power.
    Nonattainment area means, for any air pollutant, an area that is 
shown by monitored data or that is calculated by air quality modeling 
(or other methods determined by the Administrator of EPA to be reliable) 
to exceed any primary or secondary ambient air quality standard 
established by EPA.
    Nonsensitive reservoir means a reservoir in which ultimate recovery 
is not decreased by high reservoir production rates.
    Oil reservoir means a reservoir that contains hydrocarbons 
predominantly in a liquid (single-phase) state.
    Oil reservoir with an associated gas cap means a reservoir that 
contains hydrocarbons in both a liquid and gaseous (two-phase) state.
    Oil-well completion means a well completed in an oil reservoir or in 
the oil accumulation of an oil reservoir with an associated gas cap.
    Operating rights means any interest held in a lease with the right 
to explore for, develop, and produce leased substances.
    Operator means the person the lessee(s) designates as having control 
or management of operations on the leased area or a portion thereof. An 
operator may be a lessee, the MMS-approved designated agent of the 
lessee(s), or the holder of operating rights under an MMS-approved 
operating rights assignment.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside of the area of lands beneath navigable waters as 
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) whose 
subsoil and seabed appertain to the United States and are subject to its 
jurisdiction and control.
    Person includes a natural person, an association (including 
partnerships, joint ventures, and trusts), a State, a political 
subdivision of a State, or a private, public, or municipal corporation.
    Pipelines are the piping, risers, and appurtenances installed for 
transporting oil, gas, sulphur, and produced waters.
    Processed geological or geophysical information means data collected 
under a

[[Page 273]]

permit or a lease that have been processed or reprocessed. Processing 
involves changing the form of data to facilitate interpretation. 
Processing operations may include, but are not limited to, applying 
corrections for known perturbing causes, rearranging or filtering data, 
and combining or transforming data elements. Reprocessing is the 
additional processing other than ordinary processing used in the general 
course of evaluation. Reprocessing operations may include varying 
identified parameters for the detailed study of a specific problem area.
    Production means those activities that take place after the 
successful completion of any means for the removal of minerals, 
including such removal, field operations, transfer of minerals to shore, 
operation monitoring, maintenance, and workover operations.
    Production areas are those areas where flammable petroleum gas, 
volatile liquids or sulphur are produced, processed (e.g., compressed), 
stored, transferred (e.g., pumped), or otherwise handled before entering 
the transportation process.
    Projected emissions means emissions, either controlled or 
uncontrolled, from a source or sources.
    Prospect means a geologic feature having the potential for mineral 
deposits.
    Regional Director means the MMS officer with responsibility and 
authority for a Region within MMS.
    Regional Supervisor means the MMS officer with responsibility and 
authority for operations or other designated program functions within an 
MMS Region.
    Right-of-use means any authorization issued under this part to use 
OCS lands.
    Right-of-way pipelines are those pipelines that are contained 
within:
    (1) The boundaries of a single lease or unit, but are not owned and 
operated by a lessee or operator of that lease or unit;
    (2) The boundaries of contiguous (not cornering) leases that do not 
have a common lessee or operator;
    (3) The boundaries of contiguous (not cornering) leases that have a 
common lessee or operator but are not owned and operated by that common 
lessee or operator; or
    (4) An unleased block(s).
    Routine operations, for the purposes of subpart F, means any of the 
following operations conducted on a well with the tree installed:
    (1) Cutting paraffin;
    (2) Removing and setting pump-through-type tubing plugs, gas-lift 
valves, and subsurface safety valves that can be removed by wireline 
operations;
    (3) Bailing sand;
    (4) Pressure surveys;
    (5) Swabbing;
    (6) Scale or corrosion treatment;
    (7) Caliper and gauge surveys;
    (8) Corrosion inhibitor treatment;
    (9) Removing or replacing subsurface pumps;
    (10) Through-tubing logging (diagnostics);
    (11) Wireline fishing;
    (12) Setting and retrieving other subsurface flow-control devices; 
and
    (13) Acid treatments.
    Sensitive reservoir means a reservoir in which high reservoir 
production rates will decrease ultimate recovery. For submitting the 
first MER, all oil reservoirs with an associated gas cap are classified 
as sensitive.
    Significant archaeological resource means those archaeological 
resources that meet the criteria of significance for eligibility to the 
National Register of Historic Places as defined in 36 CFR 60.4, or its 
successor.
    Suspension means a granted or directed deferral of the requirement 
to produce (Suspension of Production (SOP)) or to conduct leaseholding 
operations (Suspension of Operations (SOO)).
    Waste of oil, gas, or sulphur means:
    (1) The physical waste of oil, gas, or sulphur;
    (2) The inefficient, excessive, or improper use, or the unnecessary 
dissipation of reservoir energy;
    (3) The locating, spacing, drilling, equipping, operating, or 
producing of any oil, gas, or sulphur well(s) in a manner that causes or 
tends to cause a reduction in the quantity of oil, gas, or sulphur 
ultimately recoverable under prudent and proper operations or that 
causes or tends to cause unnecessary or

[[Page 274]]

excessive surface loss or destruction of oil or gas; or
    (4) The inefficient storage of oil.
    Welding means all activities connected with welding, including hot 
tapping and burning.
    Wellbay is the area on a facility within the perimeter of the 
outermost wellheads.
    Well-completion operations means the work conducted to establish 
production from a well after the production-casing string has been set, 
cemented, and pressure-tested.
    Well-control fluid means drilling mud, completion fluid, or workover 
fluid as appropriate to the particular operation being conducted.
    Western Gulf of Mexico means all OCS areas of the Gulf of Mexico 
except those the Director decides are adjacent to the State of Florida. 
The Western Gulf of Mexico is not the same as the Western Planning Area, 
an area established for OCS lease sales.
    Workover operations means the work conducted on wells after the 
initial well-completion operation for the purpose of maintaining or 
restoring the productivity of a well.
    You means a lessee, the owner or holder of operating rights, a 
designated operator or agent of the lessee(s), a pipeline right-of-way 
holder, or a State lessee granted a right-of-use and easement.

[64 FR 72775, Dec. 28, 1999, as amended at 68 FR 8422, Feb. 20, 2003; 70 
FR 41573, July 19, 2005; 70 FR 51500, Aug. 30, 2005; 71 FR 23862, Apr. 
25, 2006]

                          Performance Standards



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) All cranes installed on fixed platforms must be operated in 
accordance with American Petroleum Institute's Recommended Practice for 
Operation and Maintenance of Offshore Cranes (API RP 2D), incorporated 
by reference as specified in 30 CFR 250.198.
    (b) All cranes installed on fixed platforms must be equipped with a 
functional anti-two block device by March 16, 2005.
    (c) If a fixed platform is installed after March 17, 2003, all 
cranes on the platform must meet the requirements of American Petroleum 
Institute Specification for Offshore Pedestal Mounted Cranes (API Spec 
2C), incorporated by reference as specified in 30 CFR 250.198.
    (d) All cranes manufactured after March 17, 2003, and installed on a 
fixed platform, must meet the requirements of API Spec 2C, incorporated 
by reference as specified in 30 CFR 250.198.
    (e) You must maintain records specific to a crane or the operation 
of a crane installed on an OCS fixed platform, as follows:

[[Page 275]]

    (1) Retain all design and construction records, including 
installation records for any anti-two block safety devices, for the life 
of the crane. The records must be kept at the OCS fixed platform.
    (2) Retain all inspection, testing, and maintenance records of 
cranes for at least 4 years. The records must be kept at the OCS fixed 
platform.
    (3) Retain the qualification records of the crane operator and all 
rigger personnel for at least 4 years. The records must be kept at the 
OCS fixed platform.
    (f) You must operate and maintain all other material-handling 
equipment in a manner that ensures safe operations and prevents 
pollution.

[68 FR 7426, Feb. 14, 2003, as amended at 72 FR 12092, Mar. 15, 2007]



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

    (a) You must submit a Welding Plan to the District Manager before 
you begin drilling or production activities on a lease. You may not 
begin welding until the District Manager has approved your plan.
    (b) You must keep the following at the site where welding occurs:
    (1) A copy of the plan and its approval letter; and
    (2) Drawings showing the designated safe-welding areas.



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:
    (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.

[[Page 276]]

    (ii) You and the designated person in charge inspect the work area 
and areas below it for potential fire and explosion hazards.
    (2) During welding, the person in charge must designate one or more 
persons as a fire watch. The fire watch must:
    (i) Have no other duties while actual welding is in progress;
    (ii) Have usable firefighting equipment;
    (iii) Remain on duty for 30 minutes after welding activities end; 
and
    (iv) Maintain a continuous surveillance with a portable gas detector 
during the welding and burning operation if welding occurs in an area 
not equipped with a gas detector.
    (3) You may not weld piping, containers, tanks, or other vessels 
that have contained a flammable substance unless you have rendered the 
contents inert and the designated person in charge has determined it is 
safe to weld. This does not apply to approved hot taps.
    (4) You may not weld within 10 feet of a wellbay unless you have 
shut in all producing wells in that wellbay.
    (5) You may not weld within 10 feet of a production area, unless you 
have shut in that production area.
    (6) You may not weld while you drill, complete, workover, or conduct 
wireline operations unless:
    (i) The fluids in the well (being drilled, completed, worked over, 
or having wireline operations conducted) are noncombustible; and
    (ii) You have precluded the entry of formation hydrocarbons into the 
wellbore by either mechanical means or a positive overbalance toward the 
formation.



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 Fixed and Floating Offshore Petroleum Facilities for Unclassified 
and Class I, Division 1, and Division 2 Locations (incorporated by 
reference as specified in Sec. 250.198), or API RP 14FZ, Recommended 
Practice for Design and Installation of Electrical Systems for Fixed and 
Floating Offshore Petroleum Facilities for Unclassified and Class I, 
Zone 0, Zone 1, and Zone 2 Locations (incorporated by reference as 
specified in Sec. 250.198).
    (d) On each engine that has an electric ignition system, you must 
use an ignition system designed and maintained to reduce the release of 
electrical energy.

[64 FR 72775, Dec. 28, 1999, as amended at 65 FR 219, Jan. 4, 2000; 68 
FR 43298, July 22, 2003]



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 Manager to witness each test that you conduct 
under this section; or
    (2) Receive the District Manager's prior approval so that you can 
submit either test data with your affidavit or third party test data.
    (c) If the well is an oil well, you must conduct a production test 
that lasts at least 2 hours after flow stabilizes.
    (d) If the well is a gas well, you must conduct a deliverability 
test that lasts

[[Page 277]]

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 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.

[[Page 278]]



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 
Sec. Sec. 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.

                                  Fees



Sec. 250.125  Service fees.

    (a) The table in this paragraph (a) shows the fees that you must pay 
to MMS for the services listed. The fees will be adjusted periodically 
according to the Implicit Price Deflator for Gross Domestic Product by 
publication of a document in the Federal Register. If a significant 
adjustment is needed to arrive at the new actual cost for any reason 
other than inflation, then a proposed rule containing the new fees will 
be published in the Federal Register for comment.

                            Service Fee Table
------------------------------------------------------------------------
   Service--processing of the
           following:                 Fee amount        30 CFR citation
------------------------------------------------------------------------
(1) Change in Designation of      $150..............  Sec.  250.143(d).
 Operator.
(2) Right-of-Use and Easement     $2,350............  Sec.  250.165.
 for State lessee.
(3) Suspension of Operations/     $1,800............  Sec.  250.171(e).
 Suspension of Production (SOO/
 SOP) Request.
(4) Exploration Plan (EP).......  $3,250 for each     Sec.  250.211(d).
                                   surface location;
                                   no fee for
                                   revisions.
(5) Development and Production    $3,750 for each     Sec.  250.241(e).
 Plan (DPP) or Development         well proposed; no
 Operations Coordination           fee for revisions.
 Document (DOCD).
(6) Deepwater Operations Plan...  $3,150............  Sec.  250.292(p).
(7) Conservation Information      $24,200...........  Sec.  250.296(a).
 Document.
(8) Application for Permit to     $1,850 for initial  Sec.  250.410(d);
 Drill (APD; Form MMS-123).        applications        Sec.  250.411;
                                   only; no fee for    Sec.  250.460;
                                   revisions.          Sec.
                                                       250.513(b); Sec.
                                                        250.515; Sec.
                                                       250.1605; Sec.
                                                       250.1617(a); Sec.
                                                         250.1622.
(9) Application for Permit to     $110..............  Sec.  250.460;
 Modify (APM; Form MMS-124).                           Sec.
                                                       250.465(b); Sec.
                                                        250.513(b); Sec.
                                                         250.515; Sec.
                                                       250.613(b); Sec.
                                                        250.615; Sec.
                                                       250.1618(a); Sec.
                                                         250.1622; Sec.
                                                        250.1704(g).
(10) New Facility Production      $4,750 A component  Sec.  250.802(e).
 Safety System Application for     is a piece of
 facility with more than 125       equipment or
 components.                       ancillary system
                                   that is protected
                                   by one or more of
                                   the safety
                                   devices required
                                   by API RP 14C
                                   (incorporated by
                                   reference as
                                   specified in Sec.
                                     250.198);
                                   $12,500
                                   additional fee
                                   will be charged
                                   if MMS deems it
                                   necessary to
                                   visit a facility
                                   offshore, and
                                   $6,500 to visit a
                                   facility in a
                                   shipyard.

[[Page 279]]

 
(11) New Facility Production      $1,150 Additional   Sec.  250.802(e).
 Safety System Application for     fee of $7,850
 facility with 25-125 components.  will be charged
                                   if MMS deems it
                                   necessary to
                                   visit a facility
                                   offshore, and
                                   $4,500 to visit a
                                   facility in a
                                   shipyard.
(12) New Facility Production      $570..............  Sec.  250.802(e).
 Safety System Application for
 facility with fewer than 25
 components.
(13) Production Safety System     $530..............  Sec.  250.802(e).
 Application--Modification with
 more than 125 components
 reviewed.
(14) Production Safety System     $190..............  Sec.  250.802(e).
 Application--Modification with
 25-125 components reviewed.
(15) Production Safety System     $80...............  Sec.  250.802(e).
 Application--Modification with
 fewer than 25 components
 reviewed.
(16) Platform Application--       $19,900...........  Sec.  250.905(k).
 Installation--Under the
 Platform Verification Program.
(17) Platform Application--       $2,850............  Sec.  250.905(k).
 Installation--Fixed Structure
 Under the Platform Approval
 Program.
(18) Platform Application--       $1,450............  Sec.  250.905(k).
 Installation--Caisson/Well
 Protector.
(19) Platform Application--       $3,400............  Sec.  250.905(k).
 Modification/Repair.
(20) New Pipeline Application     $3,100............  Sec.
 (Lease Term).                                         250.1000(b).
(21) Pipeline Application--       $1,800............  Sec.
 Modification (Lease Term).                            250.1000(b).
(22) Pipeline Application--       $3,650............  Sec.
 Modification (ROW).                                   250.1000(b).
(23) Pipeline Repair              $340..............  Sec.
 Notification.                                         250.1008(e).
(24) Pipeline Right-of-Way (ROW)  $2,350............  Sec.
 Grant Application.                                    250.1015(a).
(25) Pipeline Conversion of       $200..............  Sec.
 Lease Term to ROW.                                    250.1015(a).
(26) Pipeline ROW Assignment....  $170..............  Sec.
                                                       250.1018(b).
(27) 500 Feet From Lease/Unit     $3,300............  Sec.
 Line Production Request.                              250.1101(f).
(28) Gas Cap Production Request.  $4,200............  Sec.
                                                       250.1101(f).
(29) Downhole Commingling         $4,900............  Sec.
 Request.                                              250.1106(d).
(30) Complex Surface Commingling  $3,550............  Sec.
 and Measurement Application.                          250.1202(a); Sec.
                                                         250.1203(b);
                                                       Sec.
                                                       250.1204(a).
(31) Simple Surface Commingling   $1,200............  Sec.
 and Measurement Application.                          250.1202(a); Sec.
                                                         250.1203(b);
                                                       Sec.
                                                       250.1204(a).
(32) Voluntary Unitization        $10,700...........  Sec.
 Proposal or Unit Expansion.                           250.1303(d).
(33) Unitization Revision.......  $760..............  Sec.
                                                       250.1303(d).
(34) Application to Remove a      $4,100............  Sec.  250.1727.
 Platform or Other Facility.
(35) Application to Decommission  $1,000............  Sec.  250.1751(a)
 a Pipeline (Lease Term).                              or Sec.
                                                       250.1752(a).
(36) Application to Decommission  $1,900............  Sec.  250.1751(a)
 a Pipeline (ROW).                                     or Sec.
                                                       250.1752(a).
------------------------------------------------------------------------

    (b) Payment of the fees listed in paragraph (a) of this section must 
accompany the submission of the document for approval or be sent to an 
office identified by the Regional Director. Once a fee is paid, it is 
nonrefundable, even if an application or other request is withdrawn. If 
your application is returned to you as incomplete, you are not required 
to submit a new fee when you submit the amended application.
    (c) Verbal approvals are occasionally given in special 
circumstances. Any action that will be considered a verbal permit 
approval requires either a paper permit application to follow the verbal 
approval or an electronic application

[[Page 280]]

submittal within 72 hours. Payment must be made with the completed paper 
or electronic application.

[70 FR 49875, Aug. 25, 2005, as amended at 71 FR 40909, July 19, 2006; 
72 FR 25199, May 4, 2007]



Sec. 250.126  General payment instructions.

    (a) Payment of fees associated with electronic applications. If you 
submitted an application through eWell or OCS Connect, you must use the 
interactive payment feature in that system.
    (b) Payment of fees for applications not submitted electronically. 
For applications not submitted electronically through eWell or OCS 
Connect, MMS prefers you to use credit card or automated clearing house 
(ACH) payments through the PAY.GOV Web site.
    (1) Payment using PAY.GOV Web site. The PAY.GOV Web site may be 
accessed through links on the MMS Offshore Web site at: http://
www.mms.gov/offshore/ homepage or directly through PAY.GOV at: https://
www.pay.gov/paygov/. If paying by credit card or ACH, you must include a 
copy of the PAY.GOV confirmation receipt page with your application.
    (2) MMS will also accept payments by any of the payment means listed 
in this section. Your payment must be payable to: ``Department of the 
Interior--Minerals Management Service'' or ``DOI-MMS'' and must include 
your MMS company number. MMS prefers that you use these payment 
documents in the order presented:
    (i) Commercial check drawn on a solvent bank;
    (ii) Certified check;
    (iii) Cashier's check;
    (iv) Money order; or
    (v) Bank draft drawn on a solvent bank or a Federal Reserve check.
    (c) Terms used in this section have the following meanings:
    (1) Automated Clearing House or ACH is a type of electronic fund 
transfer using the ACH network.
    (2) PAY.GOV is a U.S. Treasury payment system used by MMS to receive 
credit card and ACH payments for processing OCS plans, permits, and 
other related applications or documents.

[71 FR 40911, July 19, 2006]

                        Inspection of Operations



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 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

[[Page 281]]

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.)
----------------------------------------------------------------------------------------------------------------



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



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 Manager 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 (Form MMS-1123) unless you are the only lessee and are 
the only person conducting lease operations. When there is more than one 
lessee, each lessee must submit the Designation of Operator form and the 
Regional Supervisor must approve the designation before the designated 
operator may begin operations on the leasehold.

[[Page 282]]

    (b) This designation is authority for the designated operator to act 
on your behalf and to fulfill your obligations under the Act, the lease, 
and the regulations in this part.
    (c) You, or your designated operator, must immediately provide the 
Regional Supervisor a written notification of any change of address.
    (d) If you change the designated operator on your lease, you must 
pay the service fee listed in Sec. 250.125 of this subpart with your 
request for a change in designation of operator. Should there be 
multiple lessees, all designation of operator forms must be collected by 
one lessee and submitted to MMS in a single submittal, which is subject 
to only one filing fee.

[64 FR 72775, Dec. 28, 1999, as amended at 70 FR 49876, Aug. 25, 2005; 
72 FR 25200, May 4, 2007]



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.

  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

[[Page 283]]

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.
    (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:

[[Page 284]]

    (1) Permanently or temporarily attached to the seabed; and
    (2) Used for conducting exploration, development, and production 
activities or other operations on or off lease; or
    (3) Used for other purposes approved by MMS.
    (b) You must exercise the right-of-use and easement according to the 
regulations of this part;
    (c) You must meet the requirements at 30 CFR 256.35 (Qualification 
of lessees); establish a regional Company File as required by MMS; and 
must meet bonding requirements;
    (d) If you apply for a right-of-use and easement on a leased area, 
you must notify the lessee and give her/him an opportunity to comment on 
your application; and
    (e) You must receive MMS approval for all platforms, artificial 
islands, and installations and other devices permanently or temporarily 
attached to the seabed.
    (f) You must pay a rental amount as required by paragraph (g) of 
this section if:
    (1) You obtain a right-of-use and easement after January 12, 2004; 
or
    (2) You ask MMS to modify your right-of-use and easement to change 
the footprint of the associated platform, artificial island, or 
installation or device.
    (g) If you meet either of the conditions in paragraph (f) of this 
section, you must pay a rental amount to MMS as shown in the following 
table:

------------------------------------------------------------------------
               If...                               Then...
------------------------------------------------------------------------
(1) Your right-of-use and easement   You must pay a rental of $5 per
 site is located in water depths of   acre per year with a minimum of
 less than 200 meters;                $450 per year. The area subject to
                                      annual rental includes the areal
                                      extent of anchor chains, pipeline
                                      risers, and other equipment
                                      associated with the platform,
                                      artificial island, installation or
                                      device.
(2) Your right-of-use and easement   You must pay a rental of $7.50 per
 site is located in water depths of   acre per year with a minimum of
 200 meters or greater;               $675 per year. The area subject to
                                      annual rental includes the areal
                                      extent of anchor chains, pipeline
                                      risers, and other equipment
                                      associated with the platform,
                                      artificial island, or installation
                                      or device.
------------------------------------------------------------------------

    (h) You may make the rental payments required by paragraph (g)(1) 
and (g)(2) of this section on an annual basis, for a 5-year period, or 
for multiples of 5 years. You must make the first payment at the time 
you submit the right-of-use and easement application. You must make all 
subsequent payments before the respective time periods begin.
    (i) Late payments. An interest charge will be assessed on unpaid and 
underpaid amounts from the date the amounts are due, in accordance with 
the provisions found in 30 CFR 218.54. If you fail to make a payment 
that is late after written notice from MMS, MMS may initiate 
cancellation of the right-of-use grant and easement.

[64 FR 72775, Dec. 28, 1999, as amended at 68 FR 69311, Dec. 12, 2003; 
69 FR 29433, May 24, 2004; 72 FR 25200, May 4, 2007]



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

[[Page 285]]

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.



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. 250.125; and
    (b) The first year's rental as specified in Sec. 250.160(g).

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 72 FR 25200, May 4, 2007]



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 30 CFR 256.54 (General requirements for bonds) or an 
increase in the coverage of an existing surety bond.
    (2) Covers additional costs and liabilities for regulatory 
compliance, including well abandonment, platform and structure removal, 
and site clearance from the seafloor of the right-of-use and easement.

                               Suspensions



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), (d), and (e)). The extension is equal to the length of time 
the suspension is in effect, except as provided in paragraph (b) of this 
section.
    (b) A Directed Suspension does not extend the term of a lease when 
the Regional Supervisor directs a suspension because of:
    (1) Gross negligence; or

[[Page 286]]

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

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 72 FR 25200, May 4, 2007]



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). Your 
request must include:
    (a) The justification for the suspension including the length of 
suspension requested;
    (b) A reasonable schedule of work leading to the commencement or 
restoration of the suspended activity;
    (c) A statement that a well has been drilled on the lease and 
determined to be producible according to Sec. Sec. 250.115, 250.116, or 
250.1603 (SOP only);
    (d) A commitment to production (SOP only); and
    (e) The service fee listed in Sec. 250.125 of this subpart.

[70 FR 49876, Aug. 25, 2005]



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

[[Page 287]]

    (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?

    (a) The Regional Supervisor may grant an SOO when necessary to allow 
you time to begin drilling or other operations when you are prevented by 
reasons beyond your control, such as unexpected weather, unavoidable 
accidents, or drilling rig delays.
    (b) The Regional Supervisor may grant an SOO when all of the 
following conditions are met:
    (1) The lease was issued with a primary lease term of 5 years, or 
with a primary term of 8 years with a requirement to drill within 5 
years;
    (2) Before the end of the third year of the primary term, you or 
your predecessor in interest must have acquired and interpreted 
geophysical information that indicates:
    (i) The presence of a salt sheet;
    (ii) That all or a portion of a potential hydrocarbon-bearing 
formation may lie beneath or adjacent to the salt sheet; and
    (iii) The salt sheet interferes with identification of the potential 
hydrocarbon-bearing formation.
    (3) The interpreted geophysical information required under paragraph 
(b)(2) of this section must include full 3-D depth migration beneath the 
salt sheet and over the entire lease area.
    (4) Before requesting the suspension, you have conducted or are 
conducting additional data processing or interpretation of the 
geophysical information with the objective of identifying a potential 
hydrocarbon-bearing formation.
    (5) You demonstrate that additional time is necessary to:
    (i) complete current processing or interpretation of existing 
geophysical data or information;
    (ii) acquire, process, or interpret new geophysical data or 
information; or
    (iii) drill into the potential hydrocarbon-bearing formation 
identified as a result of the activities conducted in paragraphs (b)(2), 
(b)(4), and (b)(5) of this section.
    (c) The Regional Supervisor may grant an SOO to conduct additional 
geological and geophysical data analysis that may lead to the drilling 
of a well below 25,000 feet true vertical depth below the datum at mean 
sea level (TVD SS) when all of the following conditions are met:
    (1) The lease was issued with a primary lease term of:
    (i) 5 years; or
    (ii) 8 years with a requirement to drill within 5 years.
    (2) Before the end of the fifth year of the primary term, you or 
your predecessor in interest must have acquired and interpreted 
geophysical information that:
    (i) Indicates that all or a portion of a potential hydrocarbon-
bearing formation lies below 25,000 feet TVD SS; and
    (ii) Includes full 3-D depth migration over the entire lease area.
    (3) Before requesting the suspension, you have conducted or are 
conducting additional data processing or interpretation of the 
geophysical information with the objective of identifying a potential 
hydrocarbon-bearing geologic structure or stratigraphic trap lying below 
25,000 feet TVD SS.
    (4) You demonstrate that additional time is necessary to:
    (i) Complete current processing or interpretation of existing 
geophysical data or information;
    (ii) Acquire, process, or interpret new geophysical or geological 
data or information that would affect the decision to drill the same 
geologic structure or stratigraphic trap, as determined by the Regional 
Supervisor, identified in paragraphs (c)(2) and (c)(3) of this section; 
or
    (iii) Drill a well below 25,000 feet TVD SS into the geologic 
structure or stratigraphic trap identified as a result of the activities 
conducted in paragraphs (c)(2), (c)(3), and (c)(4)(i) and (ii) of this 
section.

[64 FR 72775, Dec. 28, 1999, as amended at 67 FR 44360, July 2, 2002; 70 
FR 74663, Dec. 16, 2005; 72 FR 25200, May 4, 2007]



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.

[[Page 288]]



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.
    (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 Manager according to 
paragraphs (h) and (i) of this section whenever production begins 
initially, whenever production ceases during the last 180 days of the 
primary term, and whenever production resumes during the last 180 days 
of the primary term.
    (2) Your lease expires at the end of its primary term unless you are 
conducting operations on your lease (see 30 CFR part 256). For purposes 
of this section, the term operations means, drilling, well-reworking, or 
production in paying quantities. The objective of the drilling or well-
reworking must be to establish production in paying quantities on the 
lease.
    (b) If you stop conducting operations during the last 180 days of 
your primary lease term, your lease will expire unless you either resume 
operations or receive an SOO or an SOP from the Regional Supervisor 
under Sec. Sec. 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 Manager either orally or by fax or e-mail and follow up with a 
written report according to paragraph (g) of this section.
    (g) If your lease is continued beyond its primary term, you must 
submit a

[[Page 289]]

report to the District Manager under paragraphs (h) and (i) of this 
section whenever production begins initially, whenever production 
ceases, whenever production resumes before the end of the 180-day period 
after having ceased, or whenever drilling or well-reworking operations 
begin before the end of the 180-day period.
    (h) The reports required by paragraphs (a) and (g) of this section 
must contain:
    (1) Name of lessee or operator;
    (2) The well number, lease number, area, and block;
    (3) As appropriate, the unit agreement name and number; and
    (4) A description of the operation and pertinent dates.
    (i) You must submit the reports required by paragraphs (a) and (g) 
of this section within the following timeframes:
    (1) Initialization of production--within 5 days of initial 
production.
    (2) Cessation of production--within 15 days after the first full 
month of zero production.
    (3) Resumption of production--within 5 days of resuming production 
after ceasing production under paragraph (i)(2) of this section.
    (4) Drilling or well reworking operations--within 5 days of 
beginning and completing the leaseholding operations.
    (j) For leases continued beyond the primary term, you must 
immediately report to the District Manager if operations do not begin 
before the end of the 180-day period.



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.

[[Page 290]]

    (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 Sec. Sec. 250.181, 250.182 
or 250.183 of this subpart, you are entitled to receive compensation 
under 43 U.S.C. 1334 (a)(2)(C). You must show the Director that the 
amount of compensation claimed is the lesser of paragraph (a) or (b) of 
this section:
    (a) The fair value of the cancelled rights as of the date of 
cancellation, taking into account both:
    (1) Anticipated revenues from the lease; and
    (2) Costs reasonably anticipated on the lease, including:
    (i) Costs of compliance with all applicable regulations and 
operating orders; and
    (ii) Liability for cleanup costs or damages, or both, in the case of 
an oil spill.
    (b) The excess, if any, over your revenues from the lease (plus 
interest thereon from the date of receipt to date of reimbursement) of:
    (1) All consideration paid for the lease (plus interest from the 
date of payment to the date of reimbursement); and
    (2) All your direct expenditures (plus interest from the date of 
payment to the date of reimbursement):
    (i) After the issue date of the lease; and
    (ii) For exploration or development, or both.
    (c) Compensation for leases issued before September 18, 1978, will 
be equal to the amount specified in paragraph (a) of this section.



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

    (a) You must submit information and reports as MMS requires.
    (1) You may obtain copies of forms from, and submit completed forms 
to, the District Manager or Regional Supervisor.
    (2) Instead of paper copies of forms available from the District 
Manager or Regional Supervisor, you may use your own computer-generated 
forms that are equal in size to MMS's forms. You must arrange the data 
on your form identical to the MMS form. If you generate your own form 
and it omits terms and conditions contained on the official MMS form, we 
will consider it to contain the omitted terms and conditions.
    (3) You may submit digital data when the Region/District is equipped 
to accept it.
    (b) When MMS specifies, you must include, for public information, an 
additional copy of such reports.
    (1) You must mark it Public Information.
    (2) You must include all required information, except information 
exempt from public disclosure under Sec. 250.197 or

[[Page 291]]

otherwise exempt from public disclosure under law or regulation.

[64 FR 72775, Dec. 28, 1999. Redesignated at 71 FR 19644, Apr. 17, 2006, 
as amended at 72 FR 25200, May 4, 2007]



Sec. 250.187  What are MMS' incident reporting requirements?

    (a) You must report all incidents listed in Sec. 250.188(a) and (b) 
to the District Manager. The specific reporting requirements for these 
incidents are contained in Sec. Sec. 250.189 and 250.190.
    (b) These reporting requirements apply to incidents that occur on 
the area covered by your lease, right-of-use and easement, pipeline 
right-of-way, or other permit issued by MMS, and that are related to 
operations resulting from the exercise of your rights under your lease, 
right-of-use and easement, pipeline right-of-way, or permit.
    (c) Nothing in this subpart relieves you from making notifications 
and reports of incidents that may be required by other regulatory 
agencies.
    (d) You must report all spills of oil or other liquid pollutants in 
accordance with 30 CFR 254.46.

[71 FR 19644, Apr. 17, 2006]



Sec. 250.188  What incidents must I report to MMS and when must I report 

them?

    (a) You must report the following incidents to the District Manager 
immediately via oral communication, and provide a written follow-up 
report (hard copy or electronically transmitted) within 15 calendar days 
after the incident:
    (1) All fatalities.
    (2) All injuries that require the evacuation of the injured 
person(s) from the facility to shore or to another offshore facility.
    (3) All losses of well control. ``Loss of well control'' means:
    (i) Uncontrolled flow of formation or other fluids. The flow may be 
to an exposed formation (an underground blowout) or at the surface (a 
surface blowout);
    (ii) Flow through a diverter; or
    (iii) Uncontrolled flow resulting from a failure of surface 
equipment or procedures.
    (4) All fires and explosions.
    (5) All reportable releases of hydrogen sulfide (H2S) 
gas, as defined in Sec. 250.490(l).
    (6) All collisions that result in property or equipment damage 
greater than $25,000. ``Collision'' means the act of a moving vessel 
(including an aircraft) striking another vessel, or striking a 
stationary vessel or object (e.g., a boat striking a drilling rig or 
platform). ``Property or equipment damage'' means the cost of labor and 
material to restore all affected items to their condition before the 
damage, including, but not limited to, the OCS facility, a vessel, 
helicopter, or equipment. It does not include the cost of salvage, 
cleaning, gas-freeing, dry docking, or demurrage.
    (7) All incidents involving structural damage to an OCS facility. 
``Structural damage'' means damage severe enough so that operations on 
the facility cannot continue until repairs are made.
    (8) All incidents involving crane or personnel/material handling 
operations.
    (9) All incidents that damage or disable safety systems or equipment 
(including firefighting systems).
    (b) You must provide a written report of the following incidents to 
the District Manager within 15 calendar days after the incident:
    (1) Any injuries that result in one or more days away from work or 
one or more days on restricted work or job transfer. One or more days 
means the injured person was not able to return to work or to all of 
their normal duties the day after the injury occurred;
    (2) All gas releases that initiate equipment or process shutdown;
    (3) All incidents that require operations personnel on the facility 
to muster for evacuation for reasons not related to weather or drills;
    (4) All other incidents, not listed in paragraph (a) of this 
section, resulting in property or equipment damage greater than $25,000.

[71 FR 19644, Apr. 17, 2006]



Sec. 250.189  Reporting requirements for incidents requiring immediate 

notification.

    For an incident requiring immediate notification under Sec. 
250.188(a), you must notify the District Manager via oral

[[Page 292]]

communication immediately after aiding the injured and stabilizing the 
situation. Your oral communication must provide the following 
information:
    (a) Date and time of occurrence;
    (b) Operator, and operator representative's, name and telephone 
number;
    (c) Contractor, and contractor representative's name and telephone 
number (if a contractor is involved in the incident or injury/fatality);
    (d) Lease number, OCS area, and block;
    (e) Platform/facility name and number, or pipeline segment number;
    (f) Type of incident or injury/fatality;
    (g) Operation or activity at time of incident (i.e., drilling, 
production, workover, completion, pipeline, crane, etc.); and
    (h) Description of the incident, damage, or injury/fatality.

[71 FR 19644, Apr. 17, 2006]



Sec. 250.190  Reporting requirements for incidents requiring written 

notification.

    (a) For any incident covered under Sec. 250.188, you must submit a 
written report within 15 calendar days after the incident to the 
District Manager. The report must contain the following information:
    (1) Date and time of occurrence;
    (2) Operator, and operator representative's name and telephone 
number;
    (3) Contractor, and contractor representative's name and telephone 
number (if a contractor is involved in the incident or injury);
    (4) Lease number, OCS area, and block;
    (5) Platform/facility name and number, or pipeline segment number;
    (6) Type of incident or injury;
    (7) Operation or activity at time of incident (i.e., drilling, 
production, workover, completion, pipeline, crane etc.);
    (8) Description of incident, damage, or injury (including days away 
from work, restricted work or job transfer), and any corrective action 
taken; and
    (9) Property or equipment damage estimate (in U.S. dollars).
    (b) You may submit a report or form prepared for another agency in 
lieu of the written report required by paragraph (a) of this section, 
provided the report or form contains all required information.
    (c) The District Manager may require you to submit additional 
information about an incident on a case-by-case basis.

[71 FR 19644, Apr. 17, 2006]



Sec. 250.191  How does MMS conduct incident investigations?

    Any investigation that MMS conducts under the authority of sections 
22(d)(1) and (2) of the Act (43 U.S.C. 1348(d)(1) and (2)) is a fact-
finding proceeding with no adverse parties. The purpose of the 
investigation is to prepare a public report that determines the cause or 
causes of the incident. The investigation may involve panel meetings 
conducted by a chairperson appointed by MMS. The following requirements 
apply to any panel meetings involving persons giving testimony:
    (a) A person giving testimony may have legal or other 
representative(s) present to provide advice or counsel while the person 
is giving testimony. The chairperson may require a verbatim transcript 
to be made of all oral testimony. The chairperson also may accept a 
sworn written statement in lieu of oral testimony.
    (b) Only panel members, and any experts the panel deems necessary, 
may address questions to any person giving testimony.
    (c) The chairperson may issue subpoenas to persons to appear and 
provide testimony or documents at a panel meeting. A subpoena may not 
require a person to attend a panel meeting held at a location more than 
100 miles from where a subpoena is served.
    (d) Any person giving testimony may request compensation for 
mileage, and fees for services, within 90 days after the panel meeting. 
The compensated expenses must be similar to mileage and fees the U.S. 
District Courts allow.

[71 FR 19645, Apr. 17, 2006]



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

[[Page 293]]

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  How must I protect archaeological resources?

    (a) If the Regional Director has reason to believe that an 
archaeological resource may exist in the lease area, the Regional 
Director will require in writing that your EP, DOCD, or DPP be 
accompanied by an archaeological report. If the archaeological report 
suggests that an archaeological resource may be present, you must 
either:
    (1) Locate the site of any operation so as not to adversely affect 
the area where the archaeological resource may be; or
    (2) Establish to the satisfaction of the Regional Director that an 
archaeological resource does not exist or will not be adversely affected 
by operations. This requires further archaeological investigation, 
conducted by an archaeologist and a geophysicist, using survey equipment 
and techniques the Regional Director considers appropriate. You must 
submit the investigation report to the Regional Director for review.
    (b) If the Regional Director determines that an archaeological 
resource is likely to be present in the lease area and may be adversely 
affected by operations, the Regional Director will notify you 
immediately. You must not take any action that may adversely affect the 
archaeological resource until the Regional Director has told you how to 
protect the resource.
    (c) If you discover any archaeological resource while conducting 
operations in the lease or right-of-way area, you must immediately halt 
operations within the area of the discovery and report the discovery to 
the Regional Director. If investigations determine that the resource is 
significant, the Regional Director will tell you how to protect it.

[64 FR 72775, Dec. 28, 1999, as amended at 71 FR 23862, Apr. 25, 2006; 
72 FR 25200, May 4, 2007]



Sec. 250.195  What notification does MMS require on the production status of 

wells?

    You must notify the appropriate MMS District Manager when you 
successfully complete or recomplete a well for production. You must:
    (a) Notify the District Manager within 5 working days of placing the 
well in a production status. You must confirm oral notification by 
telefax or e-mail within those 5 working days.
    (b) Provide the following information in your notification:
    (1) Lessee or operator name;
    (2) Well number, lease number, and OCS area and block designations;
    (3) Date you placed the well on production (indicate whether or not 
this is first production on the lease);
    (4) Type of production; and
    (5) Measured depth of the production interval.

[71 FR 23862, Apr. 25, 2006]



Sec. 250.196  Reimbursements for reproduction and processing costs.

    (a) MMS will reimburse you for costs of reproducing data and 
information that the Regional Director requests if:
    (1) You deliver geophysical and geological (G&G) data and 
information to

[[Page 294]]

MMS for the Regional Director to inspect or select and retain;
    (2) MMS receives your request for reimbursement and the Regional 
Director determines that the requested reimbursement is proper; and
    (3) The cost is at your lowest rate or at the lowest commercial rate 
established in the area, whichever is less.
    (b) MMS will reimburse you for the costs of processing geophysical 
information (that does not include cost of data acquisition):
    (1) If, at the request of the Regional Director, you processed the 
geophysical data or information in a form or manner other than that used 
in the normal conduct of business; or
    (2) If you collected the information under a permit that MMS issued 
to you before October 1, 1985, and the Regional Director requests and 
retains the information.
    (c) When you request reimbursement, you must identify reproduction 
and processing costs separately from acquisition costs.
    (d) MMS will not reimburse you for data acquisition costs or for the 
costs of analyzing or processing geological information or interpreting 
geological or geophysical information.

[64 FR 72775, Dec. 28, 1999. Redesignated at 71 FR 23862, Apr. 25, 2006]



Sec. 250.197  Data and information to be made available to the public or for 

limited inspection.

    MMS will protect data and information that you submit under this 
part, and part 203 of this chapter, as described in this section. 
Paragraphs (a) and (b) of this section describe what data and 
information will be made available to the public without the consent of 
the lessee, under what circumstances, and in what time period. Paragraph 
(c) of this section describes what data and information will be made 
available for limited inspection without the consent of the lessee, and 
under what circumstances.
    (a) All data and information you submit on MMS forms will be made 
available to the public upon submission, except as specified in the 
following table:

------------------------------------------------------------------------
                                     Data and
                                 information not
         On form . . .             immediately     Excepted data will be
                                available are . .   made available . . .
                                        .
------------------------------------------------------------------------
(1) MMS-123, Application for    Items 15, 16, 22   When the well goes on
 Permit to Drill.                through 25.        production or
                                                    according to the
                                                    table in paragraph
                                                    (b) of this section,
                                                    whichever is
                                                    earlier.
(2) MMS-123S, Supplemental APD  Items 3, 7, 8, 15  When the well goes on
 Information Sheet.              and 17.            production or
                                                    according to the
                                                    table in paragraph
                                                    (b) of this section,
                                                    whichever is
                                                    earlier.
(3) MMS-124, Application for    Item 17..........  When the well goes on
 Permit to Modify.                                  production or
                                                    according to the
                                                    table in paragraph
                                                    (b) of this section,
                                                    whichever is
                                                    earlier.
(4) MMS-125, End of Operations  Items 12, 13, 17,  When the well goes on
 Report.                         21, 22, 26         production or
                                 through 38.        according to the
                                                    table in paragraph
                                                    (b) of this section,
                                                    whichever is
                                                    earlier. However,
                                                    items 33 through 38
                                                    will not be released
                                                    when the well goes
                                                    on production unless
                                                    the period of time
                                                    in the table in
                                                    paragraph (b) has
                                                    expired.
(5) MMS-126, Well Potential     Item 101.........  2 years after you
 Test Report.                                       submit it.
(6) MMS-127, Sensitive          Items 124 through  2 years after the
 Reservoir Information Report.   168.               effective date of
                                                    the Sensitive
                                                    Reservoir
                                                    Information Report.
(7) MMS-133 Well Activity       Item 10 Fields     When the well goes on
 Report.                         [WELLBORE START    production or
                                 DATE, TD DATE,     according to the
                                 OP STATUS, END     table in paragraph
                                 DATE, MD, TVD,     (b) of this section,
                                 AND MW PPG].       whichever is
                                 Item 11 Fields     earlier.
                                 [WELLBORE START
                                 DATE, TD DATE,
                                 PLUGBACK DATE,
                                 FINAL MD, AND
                                 FINAL TVD] and
                                 Items 12 through
                                 15.
(8) MMS-133S Open Hole Data     Boxes 7 and 8....  When the well goes on
 Report.                                            production or
                                                    according to the
                                                    table in paragraph
                                                    (b) of this section,
                                                    whichever is
                                                    earlier.
(9) MMS-137 OCS Plan            Items providing    When the well goes on
 Information.                    the bottomhole     production or
                                 location, true     according to the
                                 vertical depth,    table in paragraph
                                 and measured       (b) of this section,
                                 depth of wells.    whichever is
                                                    earlier.
(10) MMS-140, Bottomhole        All items........  2 years after the
 Pressure Survey Report.                            date of the survey.
------------------------------------------------------------------------


[[Page 295]]

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

----------------------------------------------------------------------------------------------------------------
                 If                     MMS will release          At this time            Special provisions
----------------------------------------------------------------------------------------------------------------
(1) The Director determines that     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.
(2) 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.
(3) 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.
(4) 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.
(5) 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.
(6) 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.
(7) Data or information is           Descriptions of         When the well goes on   Directional survey data may
 submitted on well operations.        downhole locations,     production or when      be released earlier to the
                                      operations, and         geological data is      owner of an adjacent lease
                                      equipment.              released according to   according to Subpart D of
                                                              Sec. Sec.              this part.
                                                              250.197(b)(5) and
                                                              (b)(6), whichever
                                                              occurs earlier.
(8) 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 District Manager
 or Regional Supervisor.

[[Page 296]]

 
(9) Except for high-resolution data  G&G data, analyzed      Geological data and     None.
 and information released under       geological              information: 10 years
 paragraph (b)(2) of this section     information,            after MMS issues the
 data and information acquired by a   processed and           permit; Geophysical
 permit under part 251 are            interpreted G&G         data: 50 years after
 submitted by a lessee under 30 CFR   information.            MMS issues the
 part 203 or part 250.                                        permit; Geophysical
                                                              information: 25 years
                                                              after MMS issues the
                                                              permit.
----------------------------------------------------------------------------------------------------------------

    (c) MMS may allow limited inspection, but only by persons with a 
direct interest in related MMS decisions and issues in specific 
geographic areas, and who agree in writing to its confidentiality, of 
G&G data and information submitted under this part or part 203 of this 
chapter that MMS uses to:
    (1) Make unitization determinations on two or more leases;
    (2) Make competitive reservoir determinations;
    (3) Ensure proper plans of development for competitive reservoirs;
    (4) Promote operational safety;
    (5) Protect the environment;
    (6) Make field determinations; or
    (7) Determine eligibility for royalty relief.

[64 FR 72775, Dec. 28, 1999, as amended at 71 FR 16039, Mar. 30, 2006. 
Redesignated and amended at 71 FR 23862, Apr. 25, 2006; 72 FR 25200, May 
4, 2007]

                               References



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 Sec. Sec. 250.141 and 250.142, you may comply with a 
later edition of a specific document incorporated by reference, 
provided:
    (1) You show that complying with the later edition provides a degree 
of protection, safety, or performance equal to or better than would be 
achieved by compliance with the listed edition; and
    (2) You obtain the prior written approval for alternative compliance 
from the authorized MMS official.
    (d) You may inspect these documents at the Minerals Management 
Service, 381 Elden Street, Room 3313, Herndon, Virginia; or at the 
National Archives and Records Administration (NARA). For information on 
the availability of this material at NARA, call 202-741-6030, or go to: 
http://www.archives.gov/federal--register/code--of--federal--
regulations/ibr--locations.html. You may obtain the documents from the 
publishing organizations at the addresses given in the following table:

[[Page 297]]



------------------------------------------------------------------------
                For                               Write to
------------------------------------------------------------------------
(1) ACI Standards.................  American Concrete Institute, P. O.
                                     Box 9094, Farmington Hill, MI 48333-
                                     9094.
(2) AISC Standards................  American Institute of Steel
                                     Construction, Inc., One East Wacker
                                     Drive, Suite 700, Chicago,
                                     IL 60601-1802.
(3) ANSI/ASME Codes...............  American National Standards
                                     Institute, ATTN: Sales Department,
                                     25 West 43rd Street, 4th Floor, New
                                     York, NY 10036; and/or American
                                     Society of Mechanical Engineers, 22
                                     Law Drive, P.O. Box 2900,
                                     Fairfield, NJ 07007-2900.
(4) API Recommended Practices,      American Petroleum Institute, 1220 L
 Specs, Standards, Manual of         Street, NW., Washington, DC 20005-
 Petroleum Measurement Standards     4070.
 (MPMS) chapters.
(5) ASTM Standards................  American Society for Testing and
                                     Materials, 100 Bar Harbor Drive, P.
                                     O. Box C700, West Conshohocken, PA
                                     19428-2959.
(6) AWS Codes.....................  American Welding Society, 550 NW,
                                     LeJeune Road, P.O. Box 351040,
                                     Miami, FL 33135.
(7) NACE Standards................  National Association of Corrosion
                                     Engineers, First Services Dept.,
                                     1440 South Creek Drive, Houston, TX
                                     77218.
------------------------------------------------------------------------

    (e) This paragraph lists documents incorporated by reference. To 
easily reference text of the corresponding sections with the list of 
documents incorporated by reference, the list is in alphanumerical order 
by organization and document.

------------------------------------------------------------------------
                                               Incorporated by reference
              Title of documents                           at
------------------------------------------------------------------------
ACI Standard 318-95, Building Code             Sec.  250.901(a)(1).
 Requirements for Reinforced Concrete (ACI
 318-95) and Commentary (ACI 318R-95).
ACI 357R-84, Guide for the Design and          Sec.  250.901(a)(2).
 Construction of Fixed Offshore Concrete
 Structures, 1984; reapproved 1997.
ANSI/AISC 360-05, Specification for            Sec.  250.901(a)(3).
 Structural Steel Buildings, March 9, 2005.
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 2004 Edition;    250.1629(b)(1),
 and July 1, 2005 Addenda, Rules for            (b)(1)(i).
 Construction of Power Boilers, by ASME
 Boiler and Pressure Vessel Committee
 Subcommittee on Power Boilers; and all
 Section I Interpretations Volume 55.
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 Appendices 1, 2,    250.1629(b)(1),
 3, 5, 6, and Non-mandatory Appendices B, C,    (b)(1)(i).
 D, E, F, H, I, K, L, and M, and the Guide to
 Manufacturers Data Report Forms, 2004
 Edition; July 1, 2005 Addenda, Rules for
 Construction of Heating Boilers, by ASME
 Boiler and Pressure Vessel Committee
 Subcommittee on Heating Boilers; and all
 Section IV Interpretations Volume 55.
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, 2004      250.1629(b)(1),
 Edition; July 1, 2005 Addenda, Divisions 1     (b)(1)(i).
 and 2, Rules for Construction of Pressure
 Vessels, by ASME Boiler and Pressure Vessel
 Committee Subcommittee on Pressure Vessels;
 and all Section VIII Interpretations Volumes
 54 and 55.
ANSI/ASME B 16.5-2003, Pipe Flanges and        Sec.  250.1002(b)(2).
 Flanged Fittings.
ANSI/ASME B 31.8-2003, 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.  250.490(g)(4)(iv),
 for Respiratory Protection.                    (j)(13)(ii).
API 510, Pressure Vessel Inspection Code: In-  Sec.  250.803(b)(1);
 Service Inspection, Rating, Repair, and        Sec.  250.1629(b)(1).
 Alteration, Downstream Segment, Ninth
 Edition, June 2006, API Stock No. C51009.
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 Tank
 Strapping Method, First Edition, February
 1995; reaffirmed March 2002, API Stock No.
 H022A1.
API MPMS, Chapter 2--Tank Calibration,         Sec.  250.1202(l)(4).
 Section 2B--Calibration of Upright
 Cylindrical Tanks Using the Optical
 Reference Line Method, First Edition, March
 1989; reaffirmed March 2002, API Stock No.
 H30023.
API MPMS, Chapter 3--Tank Gauging, Section     Sec.  250.1202(l)(4).
 1A--Standard Practice for the Manual Gauging
 of Petroleum and Petroleum Products, Second
 Edition, August 2005, API Stock No. H301A02.
API MPMS, Chapter 3--Tank Gauging, Section     Sec.  250.1202(l)(4).
 1B--Standard Practice for Level Measurement
 of Liquid Hydrocarbons in Stationary Tanks
 by Automatic Tank Gauging, Second Edition,
 June 2001, API Stock No. H301B2.
API MPMS, Chapter 4--Proving Systems, Section  Sec.  250.1202(a)(3),
 1--Introduction, Third Edition, February       (f)(1).
 2005, API Stock No. H04013.
API MPMS, Chapter 4--Proving Systems, Section  Sec.  250.1202(a)(3),
 2--Displacement Provers, Third Edition,        (f)(1).
 September 2003, API Stock No. H04023.
API MPMS, Chapter 4--Proving Systems, Section  Sec.  250.1202(a)(3),
 4--Tank Provers, Second Edition, May 1998,     (f)(1).
 API Stock No. H04042.

[[Page 298]]

 
API MPMS, Chapter 4--Proving Systems, Section  Sec.  250.1202(a)(3),
 5--Master-Meter Provers, Second Edition, May   (f)(1).
 2000, API Stock No. H04052.
API MPMS, Chapter 4--Proving Systems, Section  Sec.  250.1202(a)(3),
 6--Pulse Interpolation, Second Edition, July   (f)(1).
 1999; reaffirmed 2003, API Stock No. H06042.
API MPMS, Chapter 4--Proving Systems, Section  Sec.  250.1202(a)(3),
 7--Field Standard Test Measures, Second        (f)(1).
 Edition, December 1998; reaffirmed 2003, API
 Stock No. H04072.
API MPMS, Chapter 5--Metering, Section 1--     Sec.  250.1202(a)(3).
 General Considerations for Measurement by
 Meters, Measurement Coordination Department,
 Fourth Edition, September 2005, API Stock
 No. H05014.
API MPMS, Chapter 5--Metering, Section 2--     Sec.  250.1202(a)(3).
 Measurement of Liquid Hydrocarbons by
 Displacement Meters, Third Edition,
 September 2005, API Stock No. H05023.
API MPMS Chapter 5--Metering, Section 3--      Sec.  250.1202(a)(3).
 Measurement of Liquid Hydrocarbons by
 Turbine Meters, Fifth Edition, September
 2005, API Stock No. H05035.
API MPMS, Chapter 5--Metering, Section 4--     Sec.  250.1202(a)(3).
 Accessory Equipment for Liquid Meters,
 Fourth Edition, September 2005, API Stock
 No. H05044.
API MPMS, Chapter 5--Metering, Section 5--     Sec.  250.1202(a)(3).
 Fidelity and Security of Flow Measurement
 Pulsed-Data Transmission Systems, Second
 Edition, August 2005, API Stock No. H50502.
API MPMS, Chapter 6--Metering Assemblies,      Sec.  250.1202(a)(3).
 Section 1--Lease Automatic Custody Transfer
 (LACT) Systems, Second Edition, May 1991;
 reaffirmed March 2002, API Stock No. H30121.
API MPMS, Chapter 6--Metering Assemblies,      Sec.  250.1202(a)(3).
 Section 6--Pipeline Metering Systems, Second
 Edition, May 1991; reaffirmed March 2002,
 API Stock No. H30126.
API MPMS, Chapter 6--Metering Assemblies,      Sec.  250.1202(a)(3).
 Section 7--Metering Viscous Hydrocarbons,
 Second Edition, May 1991; reaffirmed March
 2002, API Stock No. H30127.
API MPMS, Chapter 7--Temperature               Sec.  250.1202(a)(3),
 Determination, Measurement Coordination,       (l)(4).
 First Edition, June 2001, API Stock No.
 H07001.
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; reaffirmed March
 2006, API Stock No. H30161.
API MPMS, Chapter 8--Sampling, Section 2--     Sec.  250.1202(a)(3),
 Standard Practice for Automatic Sampling of    (l)(4).
 Liquid Petroleum and Petroleum Products,
 Second Edition, October 1995; reaffirmed
 June 2005, API Stock No. H08022.
API MPMS, Chapter 9--Density Determination,    Sec.  250.1202(a)(3),
 Section 1--Standard Test Method for Density,   (l)(4).
 Relative Density (Specific Gravity), or API
 Gravity of Crude Petroleum and Liquid
 Petroleum Products by Hydrometer Method,
 Second Edition, December 2002; reaffirmed
 October 2005, API Stock No. H09012.
API MPMS, Chapter 9--Density Determination,    Sec.  250.1202(a)(3),
 Section 2--Standard Test Method for Density    (l)(4).
 or Relative Density of Light Hydrocarbons by
 Pressure Hydrometer, Second Edition, March
 2003, API Stock No. H09022.
API MPMS, Chapter 10--Sediment and Water,      Sec.  250.1202(a)(3),
 Section 1--Standard Test Method for Sediment   (l)(4).
 in Crude Oils and Fuel Oils by the
 Extraction Method, Second Edition, October
 2002, API Stock No. H10012.
API MPMS, Chapter 10--Sediment and Water,      Sec.  250.1202(a)(3),
 Section 2--Determination of Water in Crude     (l)(4).
 Oil by Distillation Method, First Edition,
 April 1981; reaffirmed 2005, API Stock No.
 H30202.
API MPMS, Chapter 10--Sediment and Water,      Sec.  250.1202(a)(3),
 Section 3--Standard Test Method for Water      (l)(4).
 and Sediment in Crude Oil by the Centrifuge
 Method (Laboratory Procedure), Second
 Edition, May 2003, API Stock No. H10032.
API MPMS, Chapter 10--Sediment and Water,      Sec.  250.1202(a)(3),
 Section 4--Determination of Water and/or       (l)(4).
 Sediment in Crude Oil by the Centrifuge
 Method (Field Procedure), Third Edition,
 December 1999, API Stock No. H10043.
API MPMS, Chapter 10--Sediment and Water,      Sec.  250.1202(a)(3),
 Section 9--Standard Test Method for Water in   (l)(4).
 Crude Oils by Coulometric Karl Fischer
 Titration, Second Edition, December 2002;
 reaffirmed 2005, API Stock No. H10092.
API MPMS, Chapter 11.1--Volume Correction      Sec.  250.1202(a)(3),
 Factors, Volume 1, Table 5A--Generalized       (g)(3), (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 at 60 [deg]F, API Standard 2540,
 First Edition, August 1980; reaffirmed March
 1997, API Stock No. H27000.
API MPMS, Chapter 11.2.2--Compressibility      Sec.  250.1202(a)(3),
 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 December 2002, API Stock No.
 H27307.
API MPMS, Chapter 11--Physical Properties      Sec.  250.1202(a)(3).
 Data, Addendum to Section 2, Part 2--
 Compressibility Factors for Hydrocarbons,
 Correlation of Vapor Pressure for Commercial
 Natural Gas Liquids, First Edition, December
 1994; reaffirmed December 2002, API Stock
 No. H27308.
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, Part 1--Introduction,
 Second Edition, May 1995; reaffirmed March
 2002, API Stock No. 852-12021.

[[Page 299]]

 
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, Part 2--Measurement
 Tickets, Third Edition, June 2003, API Stock
 No. H12223.
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 January
 2003, API Stock No. H30350.
API MPMS, Chapter 14--Natural Gas Fluids       Sec.  250.1203(b)(2).
 Measurement, Section 3--Concentric, Square-
 Edged Orifice Meters, Part 2--Specification
 and Installation Requirements, Fourth
 Edition, April 2000; reaffirmed March 2006,
 API Stock No. H30351.
API MPMS, Chapter 14--Natural Gas Fluids       Sec.  250.1203(b)(2).
 Measurement, Section 3--Concentric, Square-
 Edged Orifice Meters, Part 3--Natural Gas
 Applications, Third Edition, August 1992;
 reaffirmed January 2003, API Stock No.
 H30353.
API MPMS, Chapter 14.5--Calculation of Gross   Sec.  250.1203(b)(2).
 Heating Value, Relative Density and
 Compressibility Factor for Natural Gas
 Mixtures from Compositional Analysis, Second
 Edition, revised 1996; reaffirmed March
 2002, API Stock No. H14052.
API MPMS, Chapter 14--Natural Gas Fluids       Sec.  250.1203(b)(2).
 Measurement, Section 6--Continuous Density
 Measurement, Second Edition, April 1991;
 reaffirmed February 2006, API Stock No.
 H30346.
API MPMS, Chapter 14--Natural Gas Fluids       Sec.  250.1203(b)(2).
 Measurement, Section 8--Liquefied Petroleum
 Gas Measurement, Second Edition, July 1997;
 reaffirmed March 2002, API Stock No. H14082.
API MPMS, Chapter 20--Section 1--Allocation    Sec.  250.1202(k)(1).
 Measurement, First Edition, August 1993;
 reaffirmed October 2006, API Stock No.
 H30701.
API MPMS, Chapter 21--Flow Measurement Using   Sec.  250.1203(b)(4).
 Electronic Metering Systems, Section 1--
 Electronic Gas Measurement, First Edition,
 August 1993; reaffirmed July 2005, API Stock
 No. H30730.
API RP 2A-WSD, Recommended Practice for        Sec.  250.901(a)(4);
 Planning, Designing and Constructing Fixed     Sec.  250.908(a); Sec.
 Offshore Platforms--Working Stress Design,      250.920(a), (b), (c),
 Twenty-first Edition, December 2000; Errata    (e).
 and Supplement 1, December 2002; Errata and
 Supplement 2, October 2005, API Stock No.
 G2AWSD.
API RP 2D, Recommended Practice for Operation  Sec.  250.108(a).
 and Maintenance of Offshore Cranes, Fifth
 Edition, June 2003, API Stock No. G02D05.
API RP 2FPS, Recommended Practice for          Sec.  250.901(a)(5).
 Planning, Designing, and Constructing
 Floating Production Systems, First Edition,
 March 2001, API Stock No. G2FPS1.
API RP 2RD, Recommended Practice for Design    Sec.  250.800(b)(2);
 of Risers for Floating Production Systems      Sec.  250.901(a)(6);
 (FPSs) and Tension-Leg Platforms (TLPs),       Sec.  250.1002(b)(5).
 First Edition, June 1998; reaffirmed May
 2006, API Stock No. G02RD1.
API RP 2SK, Recommended Practice for Design    Sec.  250.800(b)(3);
 and Analysis of Stationkeeping Systems for     Sec.  250.901(a)(7).
 Floating Structures, Third Edition, October
 2005, API Stock No. G2SK03.
API RP 2SM, Recommended Practice for Design,   Sec.  250.901(a)(8).
 Manufacture, Installation, and Maintenance
 of Synthetic Fiber Ropes for Offshore
 Mooring, First Edition, March 2001, API
 Stock No. G02SM1.
API RP 2T, Recommended Practice for Planning,  Sec.  250.901(a)(9).
 Designing, and Constructing Tension Leg
 Platforms, Second Edition, August 1997, API
 Stock No. G02T02.
API RP 14B, Recommended Practice for Design,   Sec.  250.801(e)(4);
 Installation, Repair and Operation of          Sec.  250.804(a)(1)(i).
 Subsurface Safety Valve Systems, Fifth
 Edition, October 2005, also available as ISO
 10417: 2004, (Identical) Petroleum and
 natural gas industries--Subsurface safety
 valve systems--Design, installation,
 operation and redress, API Stock No. GX14B05.
API RP 14C, Recommended Practice for           Sec.  250.125(a); Sec.
 Analysis, Design, Installation, and Testing    250.292(j); Sec.
 of Basic Surface Safety Systems for Offshore   250.802(b), (e)(2); Sec.
 Production Platforms, Seventh Edition, March     250.803(a), (b)(2)(i),
 2001, API Stock No. C14C07.                    (b)(4), (b)(5)(i),
                                                (b)(7), (b)(9)(v),
                                                (c)(2); Sec.
                                                250.804(a), (a)(6); 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);
 and Installation of Offshore Production        Sec.  250.1628(b)(2),
 Platform Piping Systems, Fifth Edition,        (d)(3).
 October 1, 1991; reaffirmed June 2000, 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.
 Fixed and Floating Offshore Petroleum          250.1629(b)(4)(v).
 Facilities for Unclassified and Class I,
 Division 1 and Division 2 Locations, Fourth
 Edition, June 1999, API Stock No. G14F04.
API RP 14FZ, Recommended Practice for Design   Sec.  250.114(c); Sec.
 and Installation of Electrical Systems for     250.803(b)(9)(v); Sec.
 Fixed and Floating Offshore Petroleum          250.1629(b)(4)(v).
 Facilities for Unclassified and Class I,
 Zone 0, Zone 1 and Zone 2 Locations, First
 Edition, September 2001, API Stock No.
 G14FZ1.
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; reaffirmed June 2000, API    (b)(4)(v).
 Stock No. G07194.
API RP 14H, Recommended Practice for           Sec.  250.802(d); Sec.
 Installation, Maintenance, and Repair of       250.804(a)(5).
 Surface Safety Valves and Underwater Safety
 Valves Offshore, Fourth Edition, July 1,
 1994, API Stock No. G14H04.

[[Page 300]]

 
API RP 14J, Recommended Practice for Design    Sec.  250.800(b)(1);
 and Hazards Analysis for Offshore Production   Sec.  250.901(a)(10).
 Facilities, Second Edition, May 2001, API
 Stock No. G14J02.
API RP 53, Recommended Practices for Blowout   Sec.  250.442(c); Sec.
 Prevention Equipment Systems for Drilling      250.446(a).
 Wells, Third Edition, March 1997; reaffirmed
 September 2004, API Stock No. G53003.
API RP 65, Recommended Practice for Cementing  Sec.  250.198; Sec.
 Shallow Water Flow Zones in Deep Water         250.415(e).
 Wells, First Edition, September 2002, API
 Stock No. G56001.
API RP 500, Recommended Practice for           Sec.  250.114(a); Sec.
 Classification of Locations for Electrical     250.459; 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),
 reaffirmed November 2002, API Stock No.        (d)(4)(i); Sec.
 C50002.                                        250.1629(b)(4)(i).
API RP 505, Recommended Practice for           Sec.  250.114(a); Sec.
 Classification of Locations for Electrical     250.459; 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;          250.1628(b)(3),
 reaffirmed November 2002, API Stock No.        (d)(4)(i); Sec.
 C50501.                                        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; reaffirmed
 November 2003, API Stock No. H25560.
API Spec. Q1, Specification for Quality        Sec.  250.806(a)(2)(ii).
 Programs for the Petroleum, Petrochemical
 and Natural Gas Industry, ANSI/API
 Specification Q1, Seventh Edition, June 15,
 2003; also available as ISO/TS 29001,
 Effective Date: December 15, 2003, API Stock
 No. GQ1007.
API Spec. 2C, Specification for Offshore       Sec.  250.108(c), (d).
 Pedestal Mounted Cranes, Sixth Edition,
 March 2004, Effective Date: September 2004,
 API Stock No. G02C06.
API Spec. 6A, Specification for Wellhead and   Sec.  250.806(a)(3);
 Christmas Tree Equipment, ANSI/API             Sec.  250.1002 (b)(1),
 Specification 6A, Nineteenth Edition, July     (b)(2).
 2004; also available as ISO 10423:2003,
 (Modified) Petroleum and natural gas
 industries--Drilling and production
 equipment--Wellhead and Christmas tree
 equipment, Effective Date: February 1, 2005;
 Errata 1, September 1, 2004, API Stock No.
 GX06A19.
API Spec. 6AV1, Specification for              Sec.  250.806(a)(3).
 Verification Test of Wellhead Surface Safety
 Valves and Underwater Safety Valves for
 Offshore Service, First Edition, February 1,
 1996; reaffirmed January 2003, API Stock No.
 G06AV1.
API Spec. 6D, Specification for Pipeline       Sec.  250.1002(b)(1).
 Valves, Twenty-second Edition, January 2002;
 also available as ISO 14313:1999, MOD,
 Petroleum and natural gas industries--
 Pipeline transportation systems--Pipeline
 valves, Effective Date: July 1, 2002,
 Proposed National Adoption, includes Annex
 F, March 1, 2005, API Stock No. G06D22.
API Spec. 14A, Specification for Subsurface    Sec.  250.806(a)(3).
 Safety Valve Equipment, Tenth Edition,
 November 2000; also available as ISO
 10432:1999, Petroleum and natural gas
 industries--Downhole equipment--Subsurface
 safety valve equipment, Effective Date: May
 15, 2001, API Stock No. GG14A10.
API Spec. 17J, Specification for Unbonded      Sec.
 Flexible Pipe, Second Edition, November        250.803(b)(2)(iii); Sec.
 1999; Errata dated May 25, 2001; Addendum 1,     250.1002(b)(4); Sec.
 June 2003, Effective Date: December 2002,      250.1007(a)(4).
 API Stock No. G17J02.
API Standard 2551, Measurement and             Sec.  250.1202(l)(4).
 Calibration of Horizontal Tanks, First
 Edition, 1965; reaffirmed March 2002, API
 Stock No. H25510.
API Standard 2552, USA Standard Method for     Sec.  250.1202(l)(4).
 Measurement and Calibration of Spheres and
 Spheroids, First Edition, 1966; reaffirmed
 February 2006, API Stock No. H25520.
API Standard 2555, Method for Liquid           Sec.  250.1202(l)(4).
 Calibration of Tanks, First Edition,
 September 1966; reaffirmed March 2002; API
 Stock No. H25550.
ASTM Standard C 33-99a, Standard               Sec.  250.901(a)(11).
 Specification for Concrete Aggregates.
ASTM Standard C 94/C 94M-99, Standard          Sec.  250.901(a)(12).
 Specification for Ready-Mixed Concrete.
ASTM Standard C 150-99, Standard               Sec.  250.901(a)(13).
 Specification for Portland Cement.
ASTM Standard C 330-99, Standard               Sec.  250.901(a)(14).
 Specification for Lightweight Aggregates for
 Structural Concrete.
ASTM Standard C 595-98, Standard               Sec.  250.901(a)(15).
 Specification for Blended Hydraulic Cements.
AWS D1.1:2000, Structural Welding Code--Steel  Sec.  250.901(a)(16).
AWS D1.4-98, Structural Welding Code--         Sec.  250.901(a)(17).
 Reinforcing Steel.
AWS D3.6M:1999, Specification for Underwater   Sec.  250.901(a)(18).
 Welding.
NACE Standard MR0175-2003, Item No. 21302,     Sec.  250.901(a)(19),
 Standard Material Requirements, Metals for     Sec.  250.490(p)(2).
 Sulfide Stress Cracking and Stress Corrosion
 Cracking Resistance in Sour Oilfield
 Environments.
NACE Standard RP0176-2003, Item No. 21018,     Sec.  250.901(a)(20).
 Standard Recommended Practice, Corrosion
 Control of Steel Fixed Offshore Structures
 Associated with Petroleum Production.
------------------------------------------------------------------------


[64 FR 72775, Dec. 28, 1999, as amended at 65 FR 218, 219, Jan. 4, 2000; 
65 FR 3127, Jan. 20, 2000; 65 FR 14470, Mar. 17, 2000; 65 FR 15863, Mar. 
24, 2000; 65 FR 18432, Apr. 7, 2000; 65 FR 25285, May 1, 2000; 65 FR 
36328, June 8, 2000; 65 FR 40052, June 29, 2000; 65 FR 41002, July 3, 
2000; 65 FR 76935, Dec. 8, 2000; 67 FR 51759, Aug. 9, 2002; 68 FR 46, 
Jan. 2, 2003; 68 FR 7427, Feb. 14, 2003; 68 FR 8422, Feb. 20, 2003; 68 
FR 19355, Apr. 21, 2003; 68 FR 43298, July 22, 2003; 69 FR 18803, Apr. 
9, 2004; 70 FR 7403, Feb. 14, 2005; 70 FR 41573, July 19, 2005; 72 FR 
12092, Mar. 15, 2007; 72 FR 25200, May 4, 2007]

[[Page 301]]



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. 250.197, Data and information 
to be made available to the public; parts 251 and 252; and the Freedom 
of Information Act (5 U.S.C. 552) and its implementing regulations at 43 
CFR part 2.
    (c) The Paperwork Reduction Act of 1995 requires us to inform the 
public that an agency may not conduct or sponsor, and you are not 
required to respond to, a collection of information unless it displays a 
currently valid OMB control number.
    (d) Send comments regarding any aspect of the collections of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Minerals 
Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 
20240.
    (e) MMS is collecting this information for the reasons given in the 
following table:

------------------------------------------------------------------------
 30 CFR subpart, title and/or MMS Form        Reasons for collecting
           (OMB Control No.)                 information and how used
------------------------------------------------------------------------
(1) Subpart A, General (1010-0114),      To inform MMS of actions taken
 including Forms MMS-132, Evacuation      to comply with general
 Statistics; MMS-1123, Designation of     operational requirements on
 Operator; MMS-1832, Notification of      the OCS. To ensure that
 Incidents of Noncompliance.              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,
 0151), including Forms MMS-137, OCS      development, and production
 Plan Information Form; MMS-139, EP Air   operations on the OCS. To
 Quality Screening Checklist; MMS-138,    ensure that operations on the
 DOCD Air Quality Screening Checklist,    OCS are planned to comply with
 MMS-141, ROV Survey Report Form; MMS-    statutory and regulatory
 142, Environmental Impact Analysis       requirements, will be safe and
 Worksheet.                               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 and Drilling  To inform MMS of the equipment
 Operations (1010-0141), including        and procedures to be used in
 Forms MMS-123, Application for Permit    drilling operations on the
 to Drill; MMS-123S, Supplemental APD     OCS. To ensure that drilling
 Information Sheet; MMS-124,              operations are safe and
 Application for Permit to Modify; MMS-   protect the human, marine, and
 125, End of Operations Report; MMS-      coastal environment.
 133, Well Activity Report; MMS-133S,
 Open Hole Data Report.
(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 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.
(8) Subpart I, Platforms and Structures  To provide MMS with information
 (1010-0149).                             regarding the design,
                                          fabrication, and installation
                                          of platforms on the OCS. To
                                          ensure the structural
                                          integrity of platforms
                                          installed on the OCS.
(9) Subpart J, Pipelines and Pipeline    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.

[[Page 302]]

 
(10) Subpart K, Oil and Gas Production   To inform MMS of production
 Rates (1010-0041), including Forms MMS-  rates for hydrocarbons
 126, Well Potential Test Report; MMS-    produced on the OCS. To ensure
 127, Sensitive Reservoir Information     economic maximization of
 Report; MMS-128, Semiannual Well Test    ultimate hydrocarbon recovery.
 Report; MMS-140 Bottomhole Pressure
 Survey Report.
(11) 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.
(12) Subpart M, Unitization (1010-0068)  To inform MMS of the
                                          unitization of leases. To
                                          ensure that unitization
                                          prevents waste, conserves
                                          natural resources, and
                                          protects correlative rights.
(13) Subpart N, Remedies and Penalties.  The requirements in subpart N
                                          are exempt from the Paperwork
                                          Reduction Act of 1995
                                          according to 5 CFR 1320.4.
(14) Subpart O, Well Control and         To inform MMS of training
 Production Safety Training (1010-0128).  program curricula, course
                                          schedules, and attendance. To
                                          ensure that training programs
                                          are technically accurate and
                                          sufficient to meet safety and
                                          environmental requirements,
                                          and that workers are properly
                                          trained to operate on the OCS.
(15) Subpart P, Sulphur Operations       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.
(16) Subpart Q, Decommissioning          To determine that
 Activities (1010-0142).                  decommissioning activities
                                          comply with regulatory
                                          requirements and approvals. To
                                          ensure that site clearance and
                                          platform or pipeline removal
                                          are properly performed to
                                          protect marine life and the
                                          environment and do not
                                          conflict with other users of
                                          the OCS.
(17) Form MMS-131, Performance Measures  Voluntary. We use the
 (1010-0112).                             information obtained from this
                                          form to develop an industry
                                          average that helps to describe
                                          how well the offshore oil and
                                          gas industry is performing.
(18) Form MMS-144, Rig Movement          The rig notification
 Notification Report (form used in the    requirement is essential for
 GOM OCS Region), Subparts D, E, F,       MMS inspection scheduling and
 (1010-0150).                             to verify that the equipment
                                          being used complies with
                                          approved permits.
------------------------------------------------------------------------


[64 FR 72775, Dec. 28, 1999, as amended at 67 FR 35405, May 17, 2002; 68 
FR 8422, Feb. 20, 2003; 71 FR 23863, Apr. 25, 2006; 72 FR 25200, May 4, 
2007]



                     Subpart B_Plans and Information

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

                           General Information



Sec. 250.200  Definitions.

    Acronyms and terms used in this subpart have the following meanings:
    (a) Acronyms used frequently in this subpart are listed 
alphabetically below:
    CID means Conservation Information Document
    CZMA means Coastal Zone Management Act
    DOCD means Development Operations Coordination Document
    DPP means Development and Production Plan
    DWOP means Deepwater Operations Plan
    EIA means Environmental Impact Analysis
    EP means Exploration Plan
    MMS means Minerals Management Service
    NPDES means National Pollutant Discharge Elimination System
    NTL means Notice to Lessees and Operators
    OCS means Outer Continental Shelf
    (b) Terms used in this subpart are listed alphabetically below:
    Amendment means a change you make to an EP, DPP, or DOCD that is 
pending before MMS for a decision (see Sec. Sec. 250.232(d) and 
250.267(d)).
    Modification means a change required by the Regional Supervisor to 
an EP, DPP, or DOCD (see Sec. 250.233(b)(2) and Sec.  250.270(b)(2)) 
that is pending before MMS for a decision because the OCS plan is 
inconsistent with applicable requirements.
    New or unusual technology means equipment or procedures that:
    (1) Have not been used previously or extensively in an MMS OCS 
Region;

[[Page 303]]

    (2) Have not been used previously under the anticipated operating 
conditions; or
    (3) Have operating characteristics that are outside the performance 
parameters established by this part.
    Non-conventional production or completion technology includes, but 
is not limited to, floating production systems, tension leg platforms, 
spars, floating production, storage, and offloading systems, guyed 
towers, compliant towers, subsea manifolds, and other subsea production 
components that rely on a remote site or host facility for utility and 
well control services.
    Offshore vehicle means a vehicle that is capable of being driven on 
ice.
    Resubmitted OCS plan means an EP, DPP, or DOCD that contains changes 
you make to an OCS plan that MMS has disapproved (see Sec. Sec. 
250.234(b), 250.272(a), and 250.273(b)).
    Revised OCS plan means an EP, DPP, or DOCD that proposes changes to 
an approved OCS plan, such as those in the location of a well or 
platform, type of drilling unit, or location of the onshore support base 
(see Sec. 250.283(a)).
    Supplemental OCS plan means an EP, DPP, or DOCD that proposes the 
addition to an approved OCS plan of an activity that requires approval 
of an application or permit (see Sec. 250.283(b)).



Sec. 250.201  What plans and information must I submit before I conduct any 

activities on my lease or unit?

    (a) Plans and documents. Before you conduct the activities on your 
lease or unit listed in the following table, you must submit, and MMS 
must approve, the listed plans and documents. Your plans and documents 
may cover one or more leases or units.

------------------------------------------------------------------------
  You must submit a(n) . . .                Before you . . .
------------------------------------------------------------------------
(1) Exploration Plan (EP)....  Conduct any exploration activities on a
                                lease or unit.
(2) Development and            Conduct any development and production
 Production Plan (DPP).         activities on a lease or unit in any OCS
                                area other than the Western Gulf of
                                Mexico.
(3) Development Operations     Conduct any development and production
 Coordination Document (DOCD).  activities on a lease or unit in the
                                Western GOM.
(4) Deepwater Operations Plan  Conduct post-drilling installation
 (DWOP).                        activities in any water depth associated
                                with a development project that will
                                involve the use of a non-conventional
                                production or completion technology.
(5) Conservation Information   Commence production from development
 Document (CID).                projects in water depths greater than
                                1,312 feet (400 meters).
(6) EP, DPP, or DOCD.........  Conduct geological or geophysical (G&G)
                                exploration or a development G&G
                                activity (see definitions under Sec.
                                250.105) on your lease or unit when:
                               (i) It will result in a physical
                                penetration of the seabed greater than
                                500 feet (152 meters);
                               (ii) It will involve the use of
                                explosives;
                               (iii) The Regional Director determines
                                that it might have a significant adverse
                                effect on the human, marine, or coastal
                                environment; or
                               (iv) The Regional Supervisor, after
                                reviewing a notice under Sec.  250.209,
                                determines that an EP, DPP, or DOCD is
                                necessary.
------------------------------------------------------------------------

    (b) Submitting additional information. On a case-by-case basis, the 
Regional Supervisor may require you to submit additional information if 
the Regional Supervisor determines that it is necessary to evaluate your 
proposed plan or document.
    (c) Limiting information. The Regional Director may limit the amount 
of information or analyses that you otherwise must provide in your 
proposed plan or document under this subpart when:
    (1) Sufficient applicable information or analysis is readily 
available to MMS;
    (2) Other coastal or marine resources are not present or affected;
    (3) Other factors such as technological advances affect information 
needs; or
    (4) Information is not necessary or required for a State to 
determine consistency with their CZMA Plan.
    (d) Referencing. In preparing your proposed plan or document, you 
may reference information and data discussed in other plans or documents 
you previously submitted or that are otherwise readily available to MMS.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]

[[Page 304]]



Sec. 250.202  What criteria must the Exploration Plan (EP), Development and 

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

meet?

    Your EP, DPP, or DOCD must demonstrate that you have planned and are 
prepared to conduct the proposed activities in a manner that:
    (a) Conforms to the Outer Continental Shelf Lands Act as amended 
(Act), applicable implementing regulations, lease provisions and 
stipulations, and other Federal laws;
    (b) Is safe;
    (c) Conforms to sound conservation practices and protects the rights 
of the lessor;
    (d) Does not unreasonably interfere with other uses of the OCS, 
including those involved with national security or defense; and
    (e) Does not cause undue or serious harm or damage to the human, 
marine, or coastal environment.



Sec. 250.203  Where can wells be located under an EP, DPP, or DOCD?

    The Regional Supervisor reviews and approves proposed well location 
and spacing under an EP, DPP, or DOCD. In deciding whether to approve a 
proposed well location and spacing, the Regional Supervisor will 
consider factors including, but not limited to, the following:
    (a) Protecting correlative rights;
    (b) Protecting Federal royalty interests;
    (c) Recovering optimum resources;
    (d) Number of wells that can be economically drilled for proper 
reservoir management;
    (e) Location of drilling units and platforms;
    (f) Extent and thickness of the reservoir;
    (g) Geologic and other reservoir characteristics;
    (h) Minimizing environmental risk;
    (i) Preventing unreasonable interference with other uses of the OCS; 
and
    (j) Drilling of unnecessary wells.



Sec. 250.204  How must I protect the rights of the Federal government?

    (a) To protect the rights of the Federal government, you must 
either:
    (1) Drill and produce the wells that the Regional Supervisor 
determines are necessary to protect the Federal government from loss due 
to production on other leases or units or from adjacent lands under the 
jurisdiction of other entities (e.g., State and foreign governments); or
    (2) Pay a sum that the Regional Supervisor determines as adequate to 
compensate the Federal government for your failure to drill and produce 
any well.
    (b) Payment under paragraph (a)(2) of this section may constitute 
production in paying quantities for the purpose of extending the lease 
term.
    (c) You must complete and produce any penetrated hydrocarbon-bearing 
zone that the Regional Supervisor determines is necessary to conform to 
sound conservation practices.



Sec. 250.205  Are there special requirements if my well affects an adjacent 

property?

    For wells that could intersect or drain an adjacent property, the 
Regional Supervisor may require special measures to protect the rights 
of the Federal government and objecting lessees or operators of adjacent 
leases or units.



Sec. 250.206  How do I submit the EP, DPP, or DOCD?

    (a) Number of copies. When you submit an EP, DPP, or DOCD to MMS, 
you must provide:
    (1) Four copies that contain all required information (proprietary 
copies);
    (2) Eight copies for public distribution (public information copies) 
that omit information that you assert is exempt from disclosure under 
the Freedom of Information Act (FOIA) (5 U.S.C. 552) and the 
implementing regulations (43 CFR part 2); and
    (3) Any additional copies that may be necessary to facilitate review 
of the EP, DPP, or DOCD by certain affected States and other reviewing 
entities.
    (b) Electronic submission. You may submit part or all of your EP, 
DPP, or DOCD and its accompanying information electronically. If you 
prefer to submit your EP, DPP, or DOCD electronically, ask the Regional 
Supervisor for further guidance.

[[Page 305]]

    (c) Withdrawal after submission. You may withdraw your proposed EP, 
DPP, or DOCD at any time for any reason. Notify the appropriate MMS OCS 
Region if you do.

                          Ancillary Activities



Sec. 250.207  What ancillary activities may I conduct?

    Before or after you submit an EP, DPP, or DOCD to MMS, you may 
elect, the regulations in this part may require, or the Regional 
Supervisor may direct you to conduct ancillary activities. Ancillary 
activities include:
    (a) Geological and geophysical (G&G) explorations and development 
G&G activities;
    (b) Geological and high-resolution geophysical, geotechnical, 
archaeological, biological, physical oceanographic, meteorological, 
socioeconomic, or other surveys; or
    (c) Studies that model potential oil and hazardous substance spills, 
drilling muds and cuttings discharges, projected air emissions, or 
potential hydrogen sulfide (H2S) releases.



Sec. 250.208  If I conduct ancillary activities, what notices must I provide?

    At least 30 calendar days before you conduct any G&G exploration or 
development G&G activity (see Sec. 250.207(a)), you must notify the 
Regional Supervisor in writing.
    (a) When you prepare the notice, you must:
    (1) Sign and date the notice;
    (2) Provide the names of the vessel, its operator, and the person(s) 
in charge; the specific type(s) of operations you will conduct; and the 
instrumentation/techniques and vessel navigation system you will use;
    (3) Provide expected start and completion dates and the location of 
the activity; and
    (4) Describe the potential adverse environmental effects of the 
proposed activity and any mitigation to eliminate or minimize these 
effects on the marine, coastal, and human environment.
    (b) The Regional Supervisor may require you to:
    (1) Give written notice to MMS at least 15 calendar days before you 
conduct any other ancillary activity (see Sec. 250.207(b) and (c)) in 
addition to those listed in Sec. 250.207(a); and
    (2) Notify other users of the OCS before you conduct any ancillary 
activity.



Sec. 250.209  What is the MMS review process for the notice?

    The Regional Supervisor will review any notice required under Sec. 
250.208(a) and (b)(1) to ensure that your ancillary activity complies 
with the performance standards listed in Sec. 250.202(a), (b), (d), and 
(e). The Regional Supervisor may notify you that your ancillary activity 
does not comply with those standards. In such a case, the Regional 
Supervisor will require you to submit an EP, DPP, or DOCD and you may 
not start your ancillary activity until the Regional Supervisor approves 
the EP, DPP, or DOCD.



Sec. 250.210  If I conduct ancillary activities, what reporting and 

data/information retention requirements must I satisfy?

    (a) Reporting. The Regional Supervisor may require you to prepare 
and submit reports that summarize and analyze data or information 
obtained or derived from your ancillary activities. When applicable, MMS 
will protect and disclose the data and information in these reports in 
accordance with Sec. 250.197(b).
    (b) Data and information retention. You must retain copies of all 
original data and information, including navigation data, obtained or 
derived from your G&G explorations and development G&G activities (see 
Sec. 250.207(a)), including any such data and information you obtained 
from previous leaseholders or unit operators. You must submit such data 
and information to MMS for inspection and possible retention upon 
request at any time before lease or unit termination. When applicable, 
MMS will protect and disclose such submitted data and information in 
accordance with Sec. 250.197(b).

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]

                   Contents of Exploration Plans (EP)



Sec. 250.211  What must the EP include?

    Your EP must include the following:

[[Page 306]]

    (a) Description, objectives, and schedule. A description, discussion 
of the objectives, and tentative schedule (from start to completion) of 
the exploration activities that you propose to undertake. Examples of 
exploration activities include exploration drilling, well test flaring, 
installing a well protection structure, and temporary well abandonment.
    (b) Location. A map showing the surface location and water depth of 
each proposed well and the locations of all associated drilling unit 
anchors.
    (c) Drilling unit. A description of the drilling unit and associated 
equipment you will use to conduct your proposed exploration activities, 
including a brief description of its important safety and pollution 
prevention features, and a table indicating the type and the estimated 
maximum quantity of fuels, oil, and lubricants that will be stored on 
the facility (see third definition of ``facility'' under Sec. 250.105).
    (d) Service fee. You must include payment of the service fee listed 
in Sec. 250.125.

[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]



Sec. 250.212  What information must accompany the EP?

    The following information must accompany your EP:
    (a) General information required by Sec. 250.213;
    (b) Geological and geophysical (G&G) information required by Sec. 
250.214;
    (c) Hydrogen sulfide information required by Sec. 250.215;
    (d) Biological, physical, and socioeconomic information required by 
Sec. 250.216;
    (e) Solid and liquid wastes and discharges information and cooling 
water intake information required by Sec. 250.217;
    (f) Air emissions information required by Sec. 250.218;
    (g) Oil and hazardous substance spills information required by Sec. 
250.219;
    (h) Alaska planning information required by Sec. 250.220;
    (i) Environmental monitoring information required by Sec. 250.221;
    (j) Lease stipulations information required by Sec. 250.222;
    (k) Mitigation measures information required by Sec. 250.223;
    (l) Support vessels and aircraft information required by Sec. 
250.224;
    (m) Onshore support facilities information required by Sec. 
250.225;
    (n) Coastal zone management information required by Sec. 250.226;
    (o) Environmental impact analysis information required by Sec. 
250.227; and
    (p) Administrative information required by Sec. 250.228.



Sec. 250.213  What general information must accompany the EP?

    The following general information must accompany your EP:
    (a) Applications and permits. A listing, including filing or 
approval status, of the Federal, State, and local application approvals 
or permits you must obtain to conduct your proposed exploration 
activities.
    (b) Drilling fluids. A table showing the projected amount, discharge 
rate, and chemical constituents for each type (i.e., water-based, oil-
based, synthetic-based) of drilling fluid you plan to use to drill your 
proposed exploration wells.
    (c) Chemical products. A table showing the name and brief 
description, quantities to be stored, storage method, and rates of usage 
of the chemical products you will use to conduct your proposed 
exploration activities. List only those chemical products you will store 
or use in quantities greater than the amounts defined as Reportable 
Quantities in 40 CFR part 302, or amounts specified by the Regional 
Supervisor.
    (d) New or unusual technology. A description and discussion of any 
new or unusual technology (see definition under Sec. 250.200) you will 
use to carry out your proposed exploration activities. In the public 
information copies of your EP, you may exclude any proprietary 
information from this description. In that case, include a brief 
discussion of the general subject matter of the omitted information. If 
you will not use any new or unusual technology to carry out your 
proposed exploration activities, include a statement so indicating.
    (e) Bonds, oil spill financial responsibility, and well control 
statements. Statements attesting that:

[[Page 307]]

    (1) The activities and facilities proposed in your EP are or will be 
covered by an appropriate bond under 30 CFR part 256, subpart I;
    (2) You have demonstrated or will demonstrate oil spill financial 
responsibility for facilities proposed in your EP according to 30 CFR 
part 253; and
    (3) You have or will have the financial capability to drill a relief 
well and conduct other emergency well control operations.
    (f) Suspensions of operations. A brief discussion of any suspensions 
of operations that you anticipate may be necessary in the course of 
conducting your activities under the EP.
    (g) Blowout scenario. A scenario for the potential blowout of the 
proposed well in your EP that you expect will have the highest volume of 
liquid hydrocarbons. Include the estimated flow rate, total volume, and 
maximum duration of the potential blowout. Also, discuss the potential 
for the well to bridge over, the likelihood for surface intervention to 
stop the blowout, the availability of a rig to drill a relief well, and 
rig package constraints. Estimate the time it would take to drill a 
relief well.
    (h) Contact. The name, address (e-mail address, if available), and 
telephone number of the person with whom the Regional Supervisor and any 
affected State(s) can communicate about your EP.



Sec. 250.214  What geological and geophysical (G&G) information must 

accompany the EP?

    The following G&G information must accompany your EP:
    (a) Geological description. A geological description of the 
prospect(s).
    (b) Structure contour maps. Current structure contour maps (depth-
based, expressed in feet subsea) drawn on the top of each prospective 
hydrocarbon-bearing reservoir showing the locations of proposed wells.
    (c) Two-dimensional (2-D) or three-dimensional (3-D) seismic lines. 
Copies of migrated and annotated 2-D or 3-D seismic lines (with depth 
scale) intersecting at or near your proposed well locations. You are not 
required to conduct both 2-D and 3-D seismic surveys if you choose to 
conduct only one type of survey. If you have conducted both types of 
surveys, the Regional Supervisor may instruct you to submit the results 
of both surveys. You must interpret and display this information. 
Because of its volume, provide this information as an enclosure to only 
one proprietary copy of your EP.
    (d) Geological cross-sections. Interpreted geological cross-sections 
showing the location and depth of each proposed well.
    (e) Shallow hazards report. A shallow hazards report based on 
information obtained from a high-resolution geophysical survey, or a 
reference to such report if you have already submitted it to the 
Regional Supervisor.
    (f) Shallow hazards assessment. For each proposed well, an 
assessment of any seafloor and subsurface geological and manmade 
features and conditions that may adversely affect your proposed drilling 
operations.
    (g) High-resolution seismic lines. A copy of the high-resolution 
survey line closest to each of your proposed well locations. Because of 
its volume, provide this information as an enclosure to only one 
proprietary copy of your EP. You are not required to provide this 
information if the surface location of your proposed well has been 
approved in a previously submitted EP, DPP, or DOCD.
    (h) Stratigraphic column. A generalized biostratigraphic/
lithostratigraphic column from the surface to the total depth of the 
prospect.
    (i) Time-versus-depth chart. A seismic travel time-versus-depth 
chart based on the appropriate velocity analysis in the area of 
interpretation and specifying the geodetic datum.
    (j) Geochemical information. A copy of any geochemical reports you 
used or generated.
    (k) Future G&G activities. A brief description of the types of G&G 
explorations and development G&G activities you may conduct for lease or 
unit purposes after your EP is approved.



Sec. 250.215  What hydrogen sulfide (H[bdi2]S) information must accompany the 

EP?

    The following H2S information, as applicable, must 
accompany your EP:

[[Page 308]]

    (a) Concentration. The estimated concentration of any H2S 
you might encounter while you conduct your proposed exploration 
activities.
    (b) Classification. Under Sec. 250.490(c), a request that the 
Regional Supervisor classify the area of your proposed exploration 
activities as either H2S absent, H2S present, or 
H2S unknown. Provide sufficient information to justify your 
request.
    (c) H2S Contingency Plan. If you ask the Regional 
Supervisor to classify the area of your proposed exploration activities 
as either H2S present or H2S unknown, an 
H2S Contingency Plan prepared under Sec. 250.490(f), or a 
reference to an approved or submitted H2S Contingency Plan 
that covers the proposed exploration activities.
    (d) Modeling report. If you modeled a potential H2S 
release when developing your EP, modeling report or the modeling 
results, or a reference to such report or results if you have already 
submitted it to the Regional Supervisor.
    (1) The analysis in the modeling report must be specific to the 
particular site of your proposed exploration activities, and must 
consider any nearby human-occupied OCS facilities, shipping lanes, 
fishery areas, and other points where humans may be subject to potential 
exposure from an H2S release from your proposed exploration 
activities.
    (2) If any H2S emissions are projected to affect an 
onshore location in concentrations greater than 10 parts per million, 
the modeling analysis must be consistent with the Environmental 
Protection Agency's (EPA) risk management plan methodologies outlined in 
40 CFR part 68.



Sec. 250.216  What biological, physical, and socioeconomic information must 

accompany the EP?

    If you obtain the following information in developing your EP, or if 
the Regional Supervisor requires you to obtain it, you must include a 
report, or the information obtained, or a reference to such a report or 
information if you have already submitted it to the Regional Supervisor, 
as accompanying information:
    (a) Biological environment reports. Site-specific information on 
chemosynthetic communities, federally listed threatened or endangered 
species, marine mammals protected under the Marine Mammal Protection Act 
(MMPA), sensitive underwater features, marine sanctuaries, critical 
habitat designated under the Endangered Species Act (ESA), or other 
areas of biological concern.
    (b) Physical environment reports. Site-specific meteorological, 
physical oceanographic, geotechnical reports, or archaeological reports 
(if required under Sec. 250.194).
    (c) Socioeconomic study reports. Socioeconomic information regarding 
your proposed exploration activities.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18584, Apr. 13, 2007]



Sec. 250.217  What solid and liquid wastes and discharges information and 

cooling water intake information must accompany the EP?

    The following solid and liquid wastes and discharges information and 
cooling water intake information must accompany your EP:
    (a) Projected wastes. A table providing the name, brief description, 
projected quantity, and composition of solid and liquid wastes (such as 
spent drilling fluids, drill cuttings, trash, sanitary and domestic 
wastes, and chemical product wastes) likely to be generated by your 
proposed exploration activities. Describe:
    (1) The methods you used for determining this information; and
    (2) Your plans for treating, storing, and downhole disposal of these 
wastes at your drilling location(s).
    (b) Projected ocean discharges. If any of your solid and liquid 
wastes will be discharged overboard, or are planned discharges from 
manmade islands:
    (1) A table showing the name, projected amount, and rate of 
discharge for each waste type; and
    (2) A description of the discharge method (such as shunting through 
a downpipe, etc.) you will use.
    (c) National Pollutant Discharge Elimination System (NPDES) permit. 
(1) A discussion of how you will comply with the provisions of the 
applicable general NPDES permit that covers your proposed exploration 
activities; or

[[Page 309]]

    (2) A copy of your application for an individual NPDES permit. 
Briefly describe the major discharges and methods you will use for 
compliance.
    (d) Modeling report. The modeling report or the modeling results (if 
you modeled the discharges of your projected solid or liquid wastes when 
developing your EP), or a reference to such report or results if you 
have already submitted it to the Regional Supervisor.
    (e) Projected cooling water intake. A table for each cooling water 
intake structure likely to be used by your proposed exploration 
activities that includes a brief description of the cooling water intake 
structure, daily water intake rate, water intake through screen 
velocity, percentage of water intake used for cooling water, mitigation 
measures for reducing impingement and entrainment of aquatic organisms, 
and biofouling prevention measures.



Sec. 250.218  What air emissions information must accompany the EP?

    The following air emissions information, as applicable, must 
accompany your EP:
    (a) Projected emissions. Tables showing the projected emissions of 
sulphur dioxide (SO2), particulate matter in the form of 
PM10 and PM2.5 when applicable, nitrogen oxides 
(NOX), carbon monoxide (CO), and volatile organic compounds 
(VOC) that will be generated by your proposed exploration activities.
    (1) For each source on or associated with the drilling unit 
(including well test flaring and well protection structure 
installation), you must list:
    (i) The projected peak hourly emissions;
    (ii) The total annual emissions in tons per year;
    (iii) Emissions over the duration of the proposed exploration 
activities;
    (iv) The frequency and duration of emissions; and
    (v) The total of all emissions listed in paragraphs (a)(1)(i) 
through (iv) of this section.
    (2) You must provide the basis for all calculations, including 
engine size and rating, and applicable operational information.
    (3) You must base the projected emissions on the maximum rated 
capacity of the equipment on the proposed drilling unit under its 
physical and operational design.
    (4) If the specific drilling unit has not yet been determined, you 
must use the maximum emission estimates for the type of drilling unit 
you will use.
    (b) Emission reduction measures. A description of any proposed 
emission reduction measures, including the affected source(s), the 
emission reduction control technologies or procedures, the quantity of 
reductions to be achieved, and any monitoring system you propose to use 
to measure emissions.
    (c) Processes, equipment, fuels, and combustibles. A description of 
processes, processing equipment, combustion equipment, fuels, and 
storage units. You must include the characteristics and the frequency, 
duration, and maximum burn rate of any well test fluids to be burned.
    (d) Distance to shore. Identification of the distance of your 
drilling unit from the mean high water mark (mean higher high water mark 
on the Pacific coast) of the adjacent State.
    (e) Non-exempt drilling units. A description of how you will comply 
with Sec. 250.303 when the projected emissions of SO2, PM, 
NOX, CO, or VOC, that will be generated by your proposed 
exploration activities, are greater than the respective emission 
exemption amounts ``E'' calculated using the formulas in Sec. 
250.303(d). When MMS requires air quality modeling, you must use the 
guidelines in Appendix W of 40 CFR part 51 with a model approved by the 
Director. Submit the best available meteorological information and data 
consistent with the model(s) used.
    (f) Modeling report. A modeling report or the modeling results (if 
Sec. 250.303 requires you to use an approved air quality model to model 
projected air emissions in developing your EP), or a reference to such a 
report or results if you have already submitted it to the Regional 
Supervisor.



Sec. 250.219  What oil and hazardous substance spills information must 

accompany the EP?

    The following information regarding potential spills of oil (see 
definition

[[Page 310]]

under 30 CFR 254.6) and hazardous substances (see definition under 40 
CFR part 116) as applicable, must accompany your EP:
    (a) Oil spill response planning. The material required under 
paragraph (a)(1) or (a)(2) of this section:
    (1) An Oil Spill Response Plan (OSRP) for the facilities you will 
use to conduct your exploration activities prepared according to the 
requirements of 30 CFR part 254, subpart B; or
    (2) Reference to your approved regional OSRP (see 30 CFR 254.3) to 
include:
    (i) A discussion of your regional OSRP;
    (ii) The location of your primary oil spill equipment base and 
staging area;
    (iii) The name(s) of your oil spill removal organization(s) for both 
equipment and personnel;
    (iv) The calculated volume of your worst case discharge scenario 
(see 30 CFR 254.26(a)), and a comparison of the appropriate worst case 
discharge scenario in your approved regional OSRP with the worst case 
discharge scenario that could result from your proposed exploration 
activities; and
    (v) A description of the worst case discharge scenario that could 
result from your proposed exploration activities (see 30 CFR 254.26(b), 
(c), (d), and (e)).
    (b) Modeling report. If you model a potential oil or hazardous 
substance spill in developing your EP, a modeling report or the modeling 
results, or a reference to such report or results if you have already 
submitted it to the Regional Supervisor.



Sec. 250.220  If I propose activities in the Alaska OCS Region, what planning 

information must accompany the EP?

    If you propose exploration activities in the Alaska OCS Region, the 
following planning information must accompany your EP:
    (a) Emergency plans. A description of your emergency plans to 
respond to a blowout, loss or disablement of a drilling unit, and loss 
of or damage to support craft.
    (b) Critical operations and curtailment procedures. Critical 
operations and curtailment procedures for your exploration activities. 
The procedures must identify ice conditions, weather, and other 
constraints under which the exploration activities will either be 
curtailed or not proceed.



Sec. 250.221  What environmental monitoring information must accompany the 

EP?

    The following environmental monitoring information, as applicable, 
must accompany your EP:
    (a) Monitoring systems. A description of any existing and planned 
monitoring systems that are measuring, or will measure, environmental 
conditions or will provide project-specific data or information on the 
impacts of your exploration activities.
    (b) Incidental takes. If there is reason to believe that protected 
species may be incidentally taken by planned exploration activities, you 
must describe how you will monitor for incidental take of:
    (1) Threatened and endangered species listed under the ESA and
    (2) Marine mammals, as appropriate, if you have not already received 
authorization for incidental take as may be necessary under the MMPA.
    (c) Flower Garden Banks National Marine Sanctuary (FGBNMS). If you 
propose to conduct exploration activities within the protective zones of 
the FGBNMS, a description of your provisions for monitoring the impacts 
of an oil spill on the environmentally sensitive resources at the 
FGBNMS.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18584, Apr. 13, 2007]



Sec. 250.222  What lease stipulations information must accompany the EP?

    A description of the measures you took, or will take, to satisfy the 
conditions of lease stipulations related to your proposed exploration 
activities must accompany your EP.



Sec. 250.223  What mitigation measures information must accompany the EP?

    (a) If you propose to use any measures beyond those required by the 
regulations in this part to minimize or mitigate environmental impacts 
from your proposed exploration activities, a description of the measures 
you will use must accompany your EP.

[[Page 311]]

    (b) If there is reason to believe that protected species may be 
incidentally taken by planned exploration activities, you must include 
mitigation measures designed to avoid or minimize the incidental take 
of:
    (1) Threatened and endangered species listed under the ESA and
    (2) Marine mammals, as appropriate, if you have not already received 
authorization for incidental take as may be necessary under the MMPA.

[72 FR 18585, Apr. 13, 2007]



Sec. 250.224  What information on support vessels, offshore vehicles, and 

aircraft you will use must accompany the EP?

    The following information on the support vessels, offshore vehicles, 
and aircraft you will use must accompany your EP:
    (a) General. A description of the crew boats, supply boats, anchor 
handling vessels, tug boats, barges, ice management vessels, other 
vessels, offshore vehicles, and aircraft you will use to support your 
exploration activities. The description of vessels and offshore vehicles 
must estimate the storage capacity of their fuel tanks and the frequency 
of their visits to your drilling unit.
    (b) Air emissions. A table showing the source, composition, 
frequency, and duration of the air emissions likely to be generated by 
the support vessels, offshore vehicles, and aircraft you will use that 
will operate within 25 miles of your drilling unit.
    (c) Drilling fluids and chemical products transportation. A 
description of the transportation method and quantities of drilling 
fluids and chemical products (see Sec. 250.213(b) and (c)) you will 
transport from the onshore support facilities you will use to your 
drilling unit.
    (d) Solid and liquid wastes transportation. A description of the 
transportation method and a brief description of the composition, 
quantities, and destination(s) of solid and liquid wastes (see Sec. 
250.217(a)) you will transport from your drilling unit.
    (e) Vicinity map. A map showing the location of your proposed 
exploration activities relative to the shoreline. The map must depict 
the primary route(s) the support vessels and aircraft will use when 
traveling between the onshore support facilities you will use and your 
drilling unit.



Sec. 250.225  What information on the onshore support facilities you will use 

must accompany the EP?

    The following information on the onshore support facilities you will 
use must accompany your EP:
    (a) General. A description of the onshore facilities you will use to 
provide supply and service support for your proposed exploration 
activities (e.g., service bases and mud company docks).
    (1) Indicate whether the onshore support facilities are existing, to 
be constructed, or to be expanded.
    (2) If the onshore support facilities are, or will be, located in 
areas not adjacent to the Western GOM, provide a timetable for acquiring 
lands (including rights-of-way and easements) and constructing or 
expanding the facilities. Describe any State or Federal permits or 
approvals (dredging, filling, etc.) that would be required for 
constructing or expanding them.
    (b) Air emissions. A description of the source, composition, 
frequency, and duration of the air emissions (attributable to your 
proposed exploration activities) likely to be generated by the onshore 
support facilities you will use.
    (c) Unusual solid and liquid wastes. A description of the quantity, 
composition, and method of disposal of any unusual solid and liquid 
wastes (attributable to your proposed exploration activities) likely to 
be generated by the onshore support facilities you will use. Unusual 
wastes are those wastes not specifically addressed in the relevant 
National Pollution Discharge Elimination System (NPDES) permit.
    (d) Waste disposal. A description of the onshore facilities you will 
use to store and dispose of solid and liquid wastes generated by your 
proposed exploration activities (see Sec. 250.217) and the types and 
quantities of such wastes.



Sec. 250.226  What Coastal Zone Management Act (CZMA) information must 

accompany the EP?

    The following CZMA information must accompany your EP:

[[Page 312]]

    (a) Consistency certification. A copy of your consistency 
certification under section 307(c)(3)(B) of the CZMA (16 U.S.C. 
1456(c)(3)(B)) and 15 CFR 930.76(d) stating that the proposed 
exploration activities described in detail in this EP comply with (name 
of State(s)) approved coastal management program(s) and will be 
conducted in a manner that is consistent with such program(s); and
    (b) Other information. ``Information'' as required by 15 CFR 
930.76(a) and 15 CFR 930.58(a)(2)) and ``Analysis'' as required by 15 
CFR 930.58(a)(3).



Sec. 250.227  What environmental impact analysis (EIA) information must 

accompany the EP?

    The following EIA information must accompany your EP:
    (a) General requirements. Your EIA must:
    (1) Assess the potential environmental impacts of your proposed 
exploration activities;
    (2) Be project specific; and
    (3) Be as detailed as necessary to assist the Regional Supervisor in 
complying with the National Environmental Policy Act (NEPA) of 1969 (42 
U.S.C. 4321 et seq.) and other relevant Federal laws such as the ESA and 
the MMPA.
    (b) Resources, conditions, and activities. Your EIA must describe 
those resources, conditions, and activities listed below that could be 
affected by your proposed exploration activities, or that could affect 
the construction and operation of facilities or structures, or the 
activities proposed in your EP.
    (1) Meteorology, oceanography, geology, and shallow geological or 
manmade hazards;
    (2) Air and water quality;
    (3) Benthic communities, marine mammals, sea turtles, coastal and 
marine birds, fish and shellfish, and plant life;
    (4) Threatened or endangered species and their critical habitat as 
defined by the Endangered Species Act of 1973;
    (5) Sensitive biological resources or habitats such as essential 
fish habitat, refuges, preserves, special management areas identified in 
coastal management programs, sanctuaries, rookeries, and calving 
grounds;
    (6) Archaeological resources;
    (7) Socioeconomic resources including employment, existing offshore 
and coastal infrastructure (including major sources of supplies, 
services, energy, and water), land use, subsistence resources and 
harvest practices, recreation, recreational and commercial fishing 
(including typical fishing seasons, location, and type), minority and 
lower income groups, and coastal zone management programs;
    (8) Coastal and marine uses such as military activities, shipping, 
and mineral exploration or development; and
    (9) Other resources, conditions, and activities identified by the 
Regional Supervisor.
    (c) Environmental impacts. Your EIA must:
    (1) Analyze the potential direct and indirect impacts (including 
those from accidents, cooling water intake structures, and those 
identified in relevant ESA biological opinions such as, but not limited 
to, those from noise, vessel collisions, and marine trash and debris) 
that your proposed exploration activities will have on the identified 
resources, conditions, and activities;
    (2) Analyze any potential cumulative impacts from other activities 
to those identified resources, conditions, and activities potentially 
impacted by your proposed exploration activities;
    (3) Describe the type, severity, and duration of these potential 
impacts and their biological, physical, and other consequences and 
implications;
    (4) Describe potential measures to minimize or mitigate these 
potential impacts; and
    (5) Summarize the information you incorporate by reference.
    (d) Consultation. Your EIA must include a list of agencies and 
persons with whom you consulted, or with whom you will be consulting, 
regarding potential impacts associated with your proposed exploration 
activities.
    (e) References cited. Your EIA must include a list of the references 
that you cite in the EIA.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]

[[Page 313]]



Sec. 250.228  What administrative information must accompany the EP?

    The following administrative information must accompany your EP:
    (a) Exempted information description (public information copies 
only). A description of the general subject matter of the proprietary 
information that is included in the proprietary copies of your EP or its 
accompanying information.
    (b) Bibliography. (1) If you reference a previously submitted EP, 
DPP, DOCD, study report, survey report, or other material in your EP or 
its accompanying information, a list of the referenced material; and
    (2) The location(s) where the Regional Supervisor can inspect the 
cited referenced material if you have not submitted it.

                 Review and Decision Process for the EP



Sec. 250.231  After receiving the EP, what will MMS do?

    (a) Determine whether deemed submitted. Within 15 working days after 
receiving your proposed EP and its accompanying information, the 
Regional Supervisor will review your submission and deem your EP 
submitted if:
    (1) The submitted information, including the information that must 
accompany the EP (refer to the list in Sec. 250.212), fulfills 
requirements and is sufficiently accurate;
    (2) You have provided all needed additional information (see Sec. 
250.201(b)); and
    (3) You have provided the required number of copies (see Sec. 
250.206(a)).
    (b) Identify problems and deficiencies. If the Regional Supervisor 
determines that you have not met one or more of the conditions in 
paragraph (a) of this section, the Regional Supervisor will notify you 
of the problem or deficiency within 15 working days after the Regional 
Supervisor receives your EP and its accompanying information. The 
Regional Supervisor will not deem your EP submitted until you have 
corrected all problems or deficiencies identified in the notice.
    (c) Deemed submitted notification. The Regional Supervisor will 
notify you when the EP is deemed submitted.



Sec. 250.232  What actions will MMS take after the EP is deemed submitted?

    (a) State and CZMA consistency reviews. Within 2 working days after 
deeming your EP submitted under Sec. 250.231, the Regional Supervisor 
will use receipted mail or alternative method to send a public 
information copy of the EP and its accompanying information to the 
following:
    (1) The Governor of each affected State. The Governor has 21 
calendar days after receiving your deemed-submitted EP to submit 
comments. The Regional Supervisor will not consider comments received 
after the deadline.
    (2) The CZMA agency of each affected State. The CZMA consistency 
review period under section 307(c)(3)(B)(ii) of the CZMA (16 U.S.C. 
1456(c)(3)(B)(ii)) and 15 CFR 930.78 begins when the State's CZMA agency 
receives a copy of your deemed-submitted EP, consistency certification, 
and required necessary data and information (see 15 CFR 930.77(a)(1)).
    (b) MMS compliance review. The Regional Supervisor will review the 
exploration activities described in your proposed EP to ensure that they 
conform to the performance standards in Sec. 250.202.
    (c) MMS environmental impact evaluation. The Regional Supervisor 
will evaluate the environmental impacts of the activities described in 
your proposed EP and prepare environmental documentation under the 
National Environmental Policy Act (NEPA) (42 U.S.C. 4321 et seq.) and 
the implementing regulations (40 CFR parts 1500 through 1508).
    (d) Amendments. During the review of your proposed EP, the Regional 
Supervisor may require you, or you may elect, to change your EP. If you 
elect to amend your EP, the Regional Supervisor may determine that your 
EP, as amended, is subject to the requirements of Sec. 250.231.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]



Sec. 250.233  What decisions will MMS make on the EP and within what 

timeframe?

    (a) Timeframe. The Regional Supervisor will take one of the actions 
shown in the table in paragraph (b) of

[[Page 314]]

this section within 30 calendar days after the Regional Supervisor deems 
your EP submitted under Sec. 250.231, or receives the last amendment to 
your proposed EP, whichever occurs later.
    (b) MMS decision. By the deadline in paragraph (a) of this section, 
the Regional Supervisor will take one of the following actions:

------------------------------------------------------------------------
  The regional  supervisor
         will . . .                 If . . .           And then . . .
------------------------------------------------------------------------
(1) Approve your EP.........  It complies with all  The Regional
                               applicable            Supervisor will
                               requirements.         notify you in
                                                     writing of the
                                                     decision and may
                                                     require you to meet
                                                     certain conditions,
                                                     including those to
                                                     provide monitoring
                                                     information.
(2) Require you to modify     The Regional          The Regional
 your proposed EP.             Supervisor finds      Supervisor will
                               that it is            notify you in
                               inconsistent with     writing of the
                               the lease, the Act,   decision and
                               the regulations       describe the
                               prescribed under      modifications you
                               the Act, or notify    must make to your
                               Federal laws.         proposed EP to
                                                     ensure it complies
                                                     with all applicable
                                                     requirements.
(3) Disapprove your EP......  Your proposed         (i) The Regional
                               activities would      Supervisor will
                               probably cause        notify you in
                               serious harm or       writing of the
                               damage to life        decision and
                               (including fish or    describe the
                               other aquatic         reason(s) for
                               life); property;      disapproving your
                               any mineral (in       EP.
                               areas leased or not  (ii) MMS may cancel
                               leased); the          your lease and
                               national security     compensate you
                               or defense; or the    under 43 U.S.C.
                               marine, coastal, or   1334(a)(2)(C) and
                               human environment;    the implementing
                               and you cannot        regulations in Sec.
                               modify your            Sec.  250.182,
                               proposed activities   250.184, and
                               to avoid such         250.185 and 30 CFR
                               condition(s).         256.77.
------------------------------------------------------------------------



Sec. 250.234  How do I submit a modified EP or resubmit a disapproved EP, and 

when will MMS make a decision?

    (a) Modified EP. If the Regional Supervisor requires you to modify 
your proposed EP under Sec. 250.233(b)(2), you must submit the 
modification(s) to the Regional Supervisor in the same manner as for a 
new EP. You need submit only information related to the proposed 
modification(s).
    (b) Resubmitted EP. If the Regional Supervisor disapproves your EP 
under Sec. 250.233(b)(3), you may resubmit the disapproved EP if there 
is a change in the conditions that were the basis of its disapproval.
    (c) MMS review and timeframe. The Regional Supervisor will use the 
performance standards in Sec. 250.202 to either approve, require you to 
further modify, or disapprove your modified or resubmitted EP. The 
Regional Supervisor will make a decision within 30 calendar days after 
the Regional Supervisor deems your modified or resubmitted EP to be 
submitted, or receives the last amendment to your modified or 
resubmitted EP, whichever occurs later.



Sec. 250.235  If a State objects to the EP's coastal zone consistency 

certification, what can I do?

    If an affected State objects to the coastal zone consistency 
certification accompanying your proposed EP within the timeframe 
prescribed in Sec. 250.233(a) or Sec.  250.234(c), you may do one of 
the following:
    (a) Amend your EP. Amend your EP to accommodate the State's 
objection and submit the amendment to the Regional Supervisor for 
approval. The amendment needs to only address information related to the 
State's objection.
    (b) Appeal. Appeal the State's objection to the Secretary of 
Commerce using the procedures in 15 CFR part 930, subpart H. The 
Secretary of Commerce will either:
    (1) Grant your appeal by finding, under section 307(c)(3)(B)(iii) of 
the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)), that each activity described in 
detail in your EP is consistent with the objectives of the CZMA, or is 
otherwise necessary in the interest of national security; or
    (2) Deny your appeal, in which case you may amend your EP as 
described in paragraph (a) of this section.

[[Page 315]]

    (c) Withdraw your EP. Withdraw your EP if you decide not to conduct 
your proposed exploration activities.

[70 FR 51501, Aug. 30, 2005; 71 FR 12438, Mar. 10, 2006]

   Contents of Development and Production Plans (DPP) and Development 
                Operations Coordination Documents (DOCD)



Sec. 250.241  What must the DPP or DOCD include?

    Your DPP or DOCD must include the following:
    (a) Description, objectives, and schedule. A description, discussion 
of the objectives, and tentative schedule (from start to completion) of 
the development and production activities you propose to undertake. 
Examples of development and production activities include:
    (1) Development drilling;
    (2) Well test flaring;
    (3) Installation of production platforms, satellite structures, 
subsea wellheads and manifolds, and lease term pipelines (see definition 
at Sec. 250.105); and
    (4) Installation of production facilities and conduct of production 
operations.
    (b) Location. The location and water depth of each of your proposed 
wells and production facilities. Include a map showing the surface and 
bottom-hole location and water depth of each proposed well, the surface 
location of each production facility, and the locations of all 
associated drilling unit and construction barge anchors.
    (c) Drilling unit. A description of the drilling unit and associated 
equipment you will use to conduct your proposed development drilling 
activities. Include a brief description of its important safety and 
pollution prevention features, and a table indicating the type and the 
estimated maximum quantity of fuels and oil that will be stored on the 
facility (see third definition of ``facility'' under Sec. 250.105).
    (d) Production facilities. A description of the production 
platforms, satellite structures, subsea wellheads and manifolds, lease 
term pipelines (see definition at Sec. 250.105), production facilities, 
umbilicals, and other facilities you will use to conduct your proposed 
development and production activities. Include a brief description of 
their important safety and pollution prevention features, and a table 
indicating the type and the estimated maximum quantity of fuels and oil 
that will be stored on the facility (see third definition of 
``facility'' under Sec. 250.105).
    (e) Service fee. You must include payment of the service fee listed 
in Sec. 250.125.

[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]



Sec. 250.242  What information must accompany the DPP or DOCD?

    The following information must accompany your DPP or DOCD.
    (a) General information required by Sec. 250.243;
    (b) G&G information required by Sec. 250.244;
    (c) Hydrogen sulfide information required by Sec. 250.245;
    (d) Mineral resource conservation information required by Sec. 
250.246;
    (e) Biological, physical, and socioeconomic information required by 
Sec. 250.247;
    (f) Solid and liquid wastes and discharges information and cooling 
water intake information required by Sec. 250.248;
    (g) Air emissions information required by Sec. 250.249;
    (h) Oil and hazardous substance spills information required by Sec. 
250.250;
    (i) Alaska planning information required by Sec. 250.251;
    (j) Environmental monitoring information required by Sec. 250.252;
    (k) Lease stipulations information required by Sec. 250.253;
    (l) Mitigation measures information required by Sec. 250.254;
    (m) Decommissioning information required by Sec. 250.255;
    (n) Related facilities and operations information required by Sec. 
250.256;
    (o) Support vessels and aircraft information required by Sec. 
250.257;
    (p) Onshore support facilities information required by Sec. 
250.258;
    (q) Sulphur operations information required by Sec. 250.259;
    (r) Coastal zone management information required by Sec. 250.260;

[[Page 316]]

    (s) Environmental impact analysis information required by Sec. 
250.261; and
    (t) Administrative information required by Sec. 250.262.



Sec. 250.243  What general information must accompany the DPP or DOCD?

    The following general information must accompany your DPP or DOCD:
    (a) Applications and permits. A listing, including filing or 
approval status, of the Federal, State, and local application approvals 
or permits you must obtain to carry out your proposed development and 
production activities.
    (b) Drilling fluids. A table showing the projected amount, discharge 
rate, and chemical constituents for each type (i.e., water based, oil 
based, synthetic based) of drilling fluid you plan to use to drill your 
proposed development wells.
    (c) Production. The following production information:
    (1) Estimates of the average and peak rates of production for each 
type of production and the life of the reservoir(s) you intend to 
produce; and
    (2) The chemical and physical characteristics of the produced oil 
(see definition under 30 CFR 254.6) that you will handle or store at the 
facilities you will use to conduct your proposed development and 
production activities.
    (d) Chemical products. A table showing the name and brief 
description, quantities to be stored, storage method, and rates of usage 
of the chemical products you will use to conduct your proposed 
development and production activities. You need list only those chemical 
products you will store or use in quantities greater than the amounts 
defined as Reportable Quantities in 40 CFR part 302, or amounts 
specified by the Regional Supervisor.
    (e) New or unusual technology. A description and discussion of any 
new or unusual technology (see definition under Sec. 250.200) you will 
use to carry out your proposed development and production activities. In 
the public information copies of your DPP or DOCD, you may exclude any 
proprietary information from this description. In that case, include a 
brief discussion of the general subject matter of the omitted 
information. If you will not use any new or unusual technology to carry 
out your proposed development and production activities, include a 
statement so indicating.
    (f) Bonds, oil spill financial responsibility, and well control 
statements. Statements attesting that:
    (1) The activities and facilities proposed in your DPP or DOCD are 
or will be covered by an appropriate bond under 30 CFR part 256, subpart 
I;
    (2) You have demonstrated or will demonstrate oil spill financial 
responsibility for facilities proposed in your DPP or DOCD, according to 
30 CFR Part 253; and
    (3) You have or will have the financial capability to drill a relief 
well and conduct other emergency well control operations.
    (g) Suspensions of production or operations. A brief discussion of 
any suspensions of production or suspensions of operations that you 
anticipate may be necessary in the course of conducting your activities 
under the DPP or DOCD.
    (h) Blowout scenario. A scenario for a potential blowout of the 
proposed well in your DPP or DOCD that you expect will have the highest 
volume of liquid hydrocarbons. Include the estimated flow rate, total 
volume, and maximum duration of the potential blowout. Also, discuss the 
potential for the well to bridge over, the likelihood for surface 
intervention to stop the blowout, the availability of a rig to drill a 
relief well, and rig package constraints. Estimate the time it would 
take to drill a relief well.
    (i) Contact. The name, mailing address, (e-mail address if 
available), and telephone number of the person with whom the Regional 
Supervisor and the affected State(s) can communicate about your DPP or 
DOCD.



Sec. 250.244  What geological and geophysical (G&G) information must 

accompany the DPP or DOCD?

    The following G&G information must accompany your DPP or DOCD:
    (a) Geological description. A geological description of the 
prospect(s).
    (b) Structure contour maps. Current structure contour maps (depth-
based, expressed in feet subsea) showing

[[Page 317]]

depths of expected productive formations and the locations of proposed 
wells.
    (c) Two dimensional (2-D) or three-dimensional (3-D) seismic lines. 
Copies of migrated and annotated 2-D or 3-D seismic lines (with depth 
scale) intersecting at or near your proposed well locations. You are not 
required to conduct both 2-D and 3-D seismic surveys if you choose to 
conduct only one type of survey. If you have conducted both types of 
surveys, the Regional Supervisor may instruct you to submit the results 
of both surveys. You must interpret and display this information. 
Provide this information as an enclosure to only one proprietary copy of 
your DPP or DOCD.
    (d) Geological cross-sections. Interpreted geological cross-sections 
showing the depths of expected productive formations.
    (e) Shallow hazards report. A shallow hazards report based on 
information obtained from a high-resolution geophysical survey, or a 
reference to such report if you have already submitted it to the 
Regional Supervisor.
    (f) Shallow hazards assessment. For each proposed well, an 
assessment of any seafloor and subsurface geologic and manmade features 
and conditions that may adversely affect your proposed drilling 
operations.
    (g) High resolution seismic lines. A copy of the high-resolution 
survey line closest to each of your proposed well locations. Because of 
its volume, provide this information as an enclosure to only one 
proprietary copy of your DPP or DOCD. You are not required to provide 
this information if the surface location of your proposed well has been 
approved in a previously submitted EP, DPP, or DOCD.
    (h) Stratigraphic column. A generalized biostratigraphic/
lithostratigraphic column from the surface to the total depth of each 
proposed well.
    (i) Time-versus-depth chart. A seismic travel time-versus-depth 
chart based on the appropriate velocity analysis in the area of 
interpretation and specifying the geodetic datum.
    (j) Geochemical information. A copy of any geochemical reports you 
used or generated.
    (k) Future G&G activities. A brief description of the G&G 
explorations and development G&G activities that you may conduct for 
lease or unit purposes after your DPP or DOCD is approved.



Sec. 250.245  What hydrogen sulfide (H[bdi2]S) information must accompany the 

DPP or DOCD?

    The following H2S information, as applicable, must 
accompany your DPP or DOCD:
    (a) Concentration. The estimated concentration of any H2S 
you might encounter or handle while you conduct your proposed 
development and production activities.
    (b) Classification. Under Sec. 250.490(c), a request that the 
Regional Supervisor classify the area of your proposed development and 
production activities as either H2S absent, H2S 
present, or H2S unknown. Provide sufficient information to 
justify your request.
    (c) H2S Contingency Plan. If you request that the 
Regional Supervisor classify the area of your proposed development and 
production activities as either H2S present or H2S 
unknown, an H2S Contingency Plan prepared under Sec. 
250.490(f), or a reference to an approved or submitted H2S 
Contingency Plan that covers the proposed development and production 
activities.
    (d) Modeling report. (1) If you have determined or estimated that 
the concentration of any H2S you may encounter or handle 
while you conduct your development and production activities will be 
greater than 500 parts per million (ppm), you must:
    (i) Model a potential worst case H2S release from the 
facilities you will use to conduct your proposed development and 
production activities; and
    (ii) Include a modeling report or modeling results, or a reference 
to such report or results if you have already submitted it to the 
Regional Supervisor.
    (2) The analysis in the modeling report must be specific to the 
particular site of your development and production activities, and must 
consider any nearby human-occupied OCS facilities, shipping lanes, 
fishery areas, and other points where humans may be subject to potential 
exposure from an H2S release from your proposed activities.

[[Page 318]]

    (3) If any H2S emissions are projected to affect an 
onshore location in concentrations greater than 10 ppm, the modeling 
analysis must be consistent with the EPA's risk management plan 
methodologies outlined in 40 CFR part 68.



Sec. 250.246  What mineral resource conservation information must accompany 

the DPP or DOCD?

    The following mineral resource conservation information, as 
applicable, must accompany your DPP or DOCD:
    (a) Technology and reservoir engineering practices and procedures. A 
description of the technology and reservoir engineering practices and 
procedures you will use to increase the ultimate recovery of oil and gas 
(e.g., secondary, tertiary, or other enhanced recovery practices). If 
you will not use enhanced recovery practices initially, provide an 
explanation of the methods you considered and the reasons why you are 
not using them.
    (b) Technology and recovery practices and procedures. A description 
of the technology and recovery practices and procedures you will use to 
ensure optimum recovery of oil and gas or sulphur.
    (c) Reservoir development. A discussion of exploratory well results, 
other reservoir data, proposed well spacing, completion methods, and 
other relevant well plan information.



Sec. 250.247  What biological, physical, and socioeconomic information must 

accompany the DPP or DOCD?

    If you obtain the following information in developing your DPP or 
DOCD, or if the Regional Supervisor requires you to obtain it, you must 
include a report, or the information obtained, or a reference to such a 
report or information if you have already submitted it to the Regional 
Supervisor, as accompanying information:
    (a) Biological environment reports. Site-specific information on 
chemosynthetic communities, federally listed threatened or endangered 
species, marine mammals protected under the MMPA, sensitive underwater 
features, marine sanctuaries, critical habitat designated under the ESA, 
or other areas of biological concern.
    (b) Physical environment reports. Site-specific meteorological, 
physical oceanographic, geotechnical reports, or archaeological reports 
(if required under Sec. 250.194).
    (c) Socioeconomic study reports. Socioeconomic information related 
to your proposed development and production activities.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]



Sec. 250.248  What solid and liquid wastes and discharges information and 

cooling water intake information must accompany the DPP or DOCD?

    The following solid and liquid wastes and discharges information and 
cooling water intake information must accompany your DPP or DOCD:
    (a) Projected wastes. A table providing the name, brief description, 
projected quantity, and composition of solid and liquid wastes (such as 
spent drilling fluids, drill cuttings, trash, sanitary and domestic 
wastes, produced waters, and chemical product wastes) likely to be 
generated by your proposed development and production activities. 
Describe:
    (1) The methods you used for determining this information; and
    (2) Your plans for treating, storing, and downhole disposal of these 
wastes at your facility location(s).
    (b) Projected ocean discharges. If any of your solid and liquid 
wastes will be discharged overboard or are planned discharges from 
manmade islands:
    (1) A table showing the name, projected amount, and rate of 
discharge for each waste type; and
    (2) A description of the discharge method (such as shunting through 
a downpipe, adding to a produced water stream, etc.) you will use.
    (c) National Pollutant Discharge Elimination System (NPDES) permit. 
(1) A discussion of how you will comply with the provisions of the 
applicable general NPDES permit that covers your proposed development 
and production activities; or
    (2) A copy of your application for an individual NPDES permit. 
Briefly describe the major discharges and methods you will use for 
compliance.

[[Page 319]]

    (d) Modeling report. A modeling report or the modeling results (if 
you modeled the discharges of your projected solid or liquid wastes in 
developing your DPP or DOCD), or a reference to such report or results 
if you have already submitted it to the Regional Supervisor.
    (e) Projected cooling water intake. A table for each cooling water 
intake structure likely to be used by your proposed development and 
production activities that includes a brief description of the cooling 
water intake structure, daily water intake rate, water intake through-
screen velocity, percentage of water intake used for cooling water, 
mitigation measures for reducing impingement and entrainment of aquatic 
organisms, and biofouling prevention measures.



Sec. 250.249  What air emissions information must accompany the DPP or DOCD?

    The following air emissions information, as applicable, must 
accompany your DPP or DOCD:
    (a) Projected emissions. Tables showing the projected emissions of 
sulphur dioxide (SO2), particulate matter in the form of 
PM10 and PM2.5 when applicable, nitrogen oxides 
(NOX), carbon monoxide (CO), and volatile organic compounds 
(VOC) that will be generated by your proposed development and production 
activities.
    (1) For each source on or associated with the facility you will use 
to conduct your proposed development and production activities, you must 
list:
    (i) The projected peak hourly emissions;
    (ii) The total annual emissions in tons per year;
    (iii) Emissions over the duration of the proposed development and 
production activities;
    (iv) The frequency and duration of emissions; and
    (v) The total of all emissions listed in paragraph (a)(1)(i) through 
(iv) of this section.
    (2) If your proposed production and development activities would 
result in an increase in the emissions of an air pollutant from your 
facility to an amount greater than the amount specified in your 
previously approved DPP or DOCD, you must show the revised emission 
rates for each source as well as the incremental change for each source.
    (3) You must provide the basis for all calculations, including 
engine size and rating, and applicable operational information.
    (4) You must base the projected emissions on the maximum rated 
capacity of the equipment and the maximum throughput of the facility you 
will use to conduct your proposed development and production activities 
under its physical and operational design.
    (5) If the specific drilling unit has not yet been determined, you 
must use the maximum emission estimates for the type of drilling unit 
you will use.
    (b) Emission reduction measures. A description of any proposed 
emission reduction measures, including the affected source(s), the 
emission reduction control technologies or procedures, the quantity of 
reductions to be achieved, and any monitoring system you propose to use 
to measure emissions.
    (c) Processes, equipment, fuels, and combustibles. A description of 
processes, processing equipment, combustion equipment, fuels, and 
storage units. You must include the frequency, duration, and maximum 
burn rate of any flaring activity.
    (d) Distance to shore. Identification of the distance of the site of 
your proposed development and production activities from the mean high 
water mark (mean higher high water mark on the Pacific coast) of the 
adjacent State.
    (e) Non-exempt facilities. A description of how you will comply with 
Sec. 250.303 when the projected emissions of SO2, PM, 
NOX, CO, or VOC that will be generated by your proposed 
development and production activities are greater than the respective 
emission exemption amounts ``E'' calculated using the formulas in Sec. 
250.303(d). When MMS requires air quality modeling, you must use the 
guidelines in Appendix W of 40 CFR part 51 with a model approved by the 
Director. Submit the best available meteorological information and data 
consistent with the model(s) used.

[[Page 320]]

    (f) Modeling report. A modeling report or the modeling results (if 
Sec. 250.303 requires you to use an approved air quality model to model 
projected air emissions in developing your DPP or DOCD), or a reference 
to such report or results if you have already submitted it to the 
Regional Supervisor.



Sec. 250.250  What oil and hazardous substance spills information must 

accompany the DPP or DOCD?

    The following information regarding potential spills of oil (see 
definition under 30 CFR 254.6) and hazardous substances (see definition 
under 40 CFR part 116), as applicable, must accompany your DPP or DOCD:
    (a) Oil spill response planning. The material required under 
paragraph (a)(1) or (a)(2) of this section:
    (1) An Oil Spill Response Plan (OSRP) for the facilities you will 
use to conduct your proposed development and production activities 
prepared according to the requirements of 30 CFR part 254, subpart B; or
    (2) Reference to your approved regional OSRP (see 30 CFR 254.3) to 
include:
    (i) A discussion of your regional OSRP;
    (ii) The location of your primary oil spill equipment base and 
staging area;
    (iii) The name(s) of your oil spill removal organization(s) for both 
equipment and personnel;
    (iv) The calculated volume of your worst case discharge scenario 
(see 30 CFR 254.26(a)), and a comparison of the appropriate worst case 
discharge scenario in your approved regional OSRP with the worst case 
discharge scenario that could result from your proposed development and 
production activities; and
    (v) A description of the worst case oil spill scenario that could 
result from your proposed development and production activities (see 30 
CFR 254.26(b), (c), (d), and (e)).
    (b) Modeling report. If you model a potential oil or hazardous 
substance spill in developing your DPP or DOCD, a modeling report or the 
modeling results, or a reference to such report or results if you have 
already submitted it to the Regional Supervisor.



Sec. 250.251  If I propose activities in the Alaska OCS Region, what planning 

information must accompany the DPP?

    If you propose development and production activities in the Alaska 
OCS Region, the following planning information must accompany your DPP:
    (a) Emergency plans. A description of your emergency plans to 
respond to a blowout, loss or disablement of a drilling unit, and loss 
of or damage to support craft; and
    (b) Critical operations and curtailment procedures. Critical 
operations and curtailment procedures for your development and 
production activities. The procedures must identify ice conditions, 
weather, and other constraints under which the development and 
production activities will either be curtailed or not proceed.



Sec. 250.252  What environmental monitoring information must accompany the 

DPP or DOCD?

    The following environmental monitoring information, as applicable, 
must accompany your DPP or DOCD:
    (a) Monitoring systems. A description of any existing and planned 
monitoring systems that are measuring, or will measure, environmental 
conditions or will provide project-specific data or information on the 
impacts of your development and production activities.
    (b) Incidental takes. If there is reason to believe that protected 
species may be incidentally taken by planned development and production 
activities, you must describe how you will monitor for incidental take 
of:
    (1) Threatened and endangered species listed under the ESA and
    (2) Marine mammals, as appropriate, if you have not already received 
authorization for incidental take of marine mammals as may be necessary 
under the MMPA.
    (c) Flower Garden Banks National Marine Sanctuary (FGBNMS). If you 
propose to conduct development and production activities within the 
protective zones of the FGBNMS, a description of your provisions for 
monitoring

[[Page 321]]

the impacts of an oil spill on the environmentally sensitive resources 
of the FGBNMS.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]



Sec. 250.253  What lease stipulations information must accompany the DPP or 

DOCD?

    A description of the measures you took, or will take, to satisfy the 
conditions of lease stipulations related to your proposed development 
and production activities must accompany your DPP or DOCD.



Sec. 250.254  What mitigation measures information must accompany the DPP or 

DOCD?

    (a) If you propose to use any measures beyond those required by the 
regulations in this part to minimize or mitigate environmental impacts 
from your proposed development and production activities, a description 
of the measures you will use must accompany your DPP or DOCD.
    (b) If there is reason to believe that protected species may be 
incidentally taken by planned development and production activities, you 
must include mitigation measures designed to avoid or minimize that 
incidental take of:
    (1) Threatened and endangered species listed under the ESA and
    (2) Marine mammals, as appropriate, if you have not already received 
authorization for incidental take as may be necessary under the MMPA.

[72 FR 18585, Apr. 13, 2007]



Sec. 250.255  What decommissioning information must accompany the DPP or 

DOCD?

    A brief description of how you intend to decommission your wells, 
platforms, pipelines, and other facilities, and clear your site(s) must 
accompany your DPP or DOCD.



Sec. 250.256  What related facilities and operations information must 

accompany the DPP or DOCD?

    The following information regarding facilities and operations 
directly related to your proposed development and production activities 
must accompany your DPP or DOCD.
    (a) OCS facilities and operations. A description and location of any 
of the following that directly relate to your proposed development and 
production activities:
    (1) Drilling units;
    (2) Production platforms;
    (3) Right-of-way pipelines (including those that transport chemical 
products and produced water); and
    (4) Other facilities and operations located on the OCS (regardless 
of ownership).
    (b) Transportation system. A discussion of the transportation system 
that you will use to transport your production to shore, including:
    (1) Routes of any new pipelines;
    (2) Information concerning barges and shuttle tankers, including the 
storage capacity of the transport vessel(s), and the number of transfers 
that will take place per year;
    (3) Information concerning any intermediate storage or processing 
facilities;
    (4) An estimate of the quantities of oil, gas, or sulphur to be 
transported from your production facilities; and
    (5) A description and location of the primary onshore terminal.



Sec. 250.257  What information on the support vessels, offshore vehicles, and 

aircraft you will use must accompany the DPP or DOCD?

    The following information on the support vessels, offshore vehicles, 
and aircraft you will use must accompany your DPP or DOCD:
    (a) General. A description of the crew boats, supply boats, anchor 
handling vessels, tug boats, barges, ice management vessels, other 
vessels, offshore vehicles, and aircraft you will use to support your 
development and production activities. The description of vessels and 
offshore vehicles must estimate the storage capacity of their fuel tanks 
and the frequency of their visits to the facilities you will use to 
conduct your proposed development and production activities.
    (b) Air emissions. A table showing the source, composition, 
frequency, and duration of the air emissions likely to be generated by 
the support vessels, offshore vehicles, and aircraft you will use that 
will operate within 25 miles of the facilities you will use to conduct

[[Page 322]]

your proposed development and production activities.
    (c) Drilling fluids and chemical products transportation. A 
description of the transportation method and quantities of drilling 
fluids and chemical products (see Sec. 250.243(b) and (d)) you will 
transport from the onshore support facilities you will use to the 
facilities you will use to conduct your proposed development and 
production activities.
    (d) Solid and liquid wastes transportation. A description of the 
transportation method and a brief description of the composition, 
quantities, and destination(s) of solid and liquid wastes (see Sec. 
250.248(a)) you will transport from the facilities you will use to 
conduct your proposed development and production activities.
    (e) Vicinity map. A map showing the location of your proposed 
development and production activities relative to the shoreline. The map 
must depict the primary route(s) the support vessels and aircraft will 
use when traveling between the onshore support facilities you will use 
and the facilities you will use to conduct your proposed development and 
production activities.



Sec. 250.258  What information on the onshore support facilities you will use 

must accompany the DPP or DOCD?

    The following information on the onshore support facilities you will 
use must accompany your DPP or DOCD:
    (a) General. A description of the onshore facilities you will use to 
provide supply and service support for your proposed development and 
production activities (e.g., service bases and mud company docks).
    (1) Indicate whether the onshore support facilities are existing, to 
be constructed, or to be expanded; and
    (2) For DPPs only, provide a timetable for acquiring lands 
(including rights-of-way and easements) and constructing or expanding 
any of the onshore support facilities.
    (b) Air emissions. A description of the source, composition, 
frequency, and duration of the air emissions (attributable to your 
proposed development and production activities) likely to be generated 
by the onshore support facilities you will use.
    (c) Unusual solid and liquid wastes. A description of the quantity, 
composition, and method of disposal of any unusual solid and liquid 
wastes (attributable to your proposed development and production 
activities) likely to be generated by the onshore support facilities you 
will use. Unusual wastes are those wastes not specifically addressed in 
the relevant National Pollution Discharge Elimination System (NPDES) 
permit.
    (d) Waste disposal. A description of the onshore facilities you will 
use to store and dispose of solid and liquid wastes generated by your 
proposed development and production activities (see Sec. 250.248(a)) 
and the types and quantities of such wastes.



Sec. 250.259  What sulphur operations information must accompany the DPP or 

DOCD?

    If you are proposing to conduct sulphur development and production 
activities, the following information must accompany your DPP or DOCD:
    (a) Bleedwater. A discussion of the bleedwater that will be 
generated by your proposed sulphur activities, including the measures 
you will take to mitigate the potential toxic or thermal impacts on the 
environment caused by the discharge of bleedwater.
    (b) Subsidence. An estimate of the degree of subsidence expected at 
various stages of your sulphur development and production activities, 
and a description of the measures you will take to mitigate the effects 
of subsidence on existing or potential oil and gas production, 
production platforms, and production facilities, and to protect the 
environment.



Sec. 250.260  What Coastal Zone Management Act (CZMA) information must 

accompany the DPP or DOCD?

    The following CZMA information must accompany your DPP or DOCD:
    (a) Consistency certification. A copy of your consistency 
certification under section 307(c)(3)(B) of the CZMA (16 U.S.C. 
1456(c)(3)(B)) and 15 CFR 930.76(d) stating that the proposed 
development and production activities described in detail in this DPP or 
DOCD comply with (name of State(s))

[[Page 323]]

approved coastal management program(s) and will be conducted in a manner 
that is consistent with such program(s); and
    (b) Other information. ``Information'' as required by 15 CFR 
930.76(a) and 15 CFR 930.58(a)(2)) and ``Analysis'' as required by 15 
CFR 930.58(a)(3).



Sec. 250.261  What environmental impact analysis (EIA) information must 

accompany the DPP or DOCD?

    The following EIA information must accompany your DPP or DOCD:
    (a) General requirements. Your EIA must:
    (1) Assess the potential environmental impacts of your proposed 
development and production activities;
    (2) Be project specific; and
    (3) Be as detailed as necessary to assist the Regional Supervisor in 
complying with the NEPA of 1969 (42 U.S.C. 4321 et seq.) and other 
relevant Federal laws such as the ESA and the MMPA.
    (b) Resources, conditions, and activities. Your EIA must describe 
those resources, conditions, and activities listed below that could be 
affected by your proposed development and production activities, or that 
could affect the construction and operation of facilities or structures 
or the activities proposed in your DPP or DOCD.
    (1) Meteorology, oceanography, geology, and shallow geological or 
manmade hazards;
    (2) Air and water quality;
    (3) Benthic communities, marine mammals, sea turtles, coastal and 
marine birds, fish and shellfish, and plant life;
    (4) Threatened or endangered species and their critical habitat;
    (5) Sensitive biological resources or habitats such as essential 
fish habitat, refuges, preserves, special management areas identified in 
coastal management programs, sanctuaries, rookeries, and calving 
grounds;
    (6) Archaeological resources;
    (7) Socioeconomic resources (including the approximate number, 
timing, and duration of employment of persons engaged in onshore support 
and construction activities), population (including the approximate 
number of people and families added to local onshore areas), existing 
offshore and onshore infrastructure (including major sources of 
supplies, services, energy, and water), types of contractors or vendors 
that may place a demand on local goods and services, land use, 
subsistence resources and harvest practices, recreation, recreational 
and commercial fishing (including seasons, location, and type), minority 
and lower income groups, and CZMA programs;
    (8) Coastal and marine uses such as military activities, shipping, 
and mineral exploration or development; and
    (9) Other resources, conditions, and activities identified by the 
Regional Supervisor.
    (c) Environmental impacts. Your EIA must:
    (1) Analyze the potential direct and indirect impacts (including 
those from accidents, cooling water intake structures, and those 
identified in relevant ESA biological opinions such as, but not limited 
to, those from noise, vessel collisions, and marine trash and debris) 
that your proposed development and production activities will have on 
the identified resources, conditions, and activities;
    (2) Describe the type, severity, and duration of these potential 
impacts and their biological, physical, and other consequences and 
implications;
    (3) Describe potential measures to minimize or mitigate these 
potential impacts;
    (4) Describe any alternatives to your proposed development and 
production activities that you considered while developing your DPP or 
DOCD, and compare the potential environmental impacts; and
    (5) Summarize the information you incorporate by reference.
    (d) Consultation. Your EIA must include a list of agencies and 
persons with whom you consulted, or with whom you will be consulting, 
regarding potential impacts associated with your proposed development 
and production activities.
    (e) References cited. Your EIA must include a list of the references 
that you cite in the EIA.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]

[[Page 324]]



Sec. 250.262  What administrative information must accompany the DPP or DOCD?

    The following administrative information must accompany your DPP or 
DOCD:
    (a) Exempted information description (public information copies 
only). A description of the general subject matter of the proprietary 
information that is included in the proprietary copies of your DPP or 
DOCD or its accompanying information.
    (b) Bibliography. (1) If you reference a previously submitted EP, 
DPP, DOCD, study report, survey report, or other material in your DPP or 
DOCD or its accompanying information, a list of the referenced material; 
and
    (2) The location(s) where the Regional Supervisor can inspect the 
cited referenced material if you have not submitted it.

             Review and Decision Process for the DPP or DOCD



Sec. 250.266  After receiving the DPP or DOCD, what will MMS do?

    (a) Determine whether deemed submitted. Within 25 working days after 
receiving your proposed DPP or DOCD and its accompanying information, 
the Regional Supervisor will deem your DPP or DOCD submitted if:
    (1) The submitted information, including the information that must 
accompany the DPP or DOCD (refer to the list in Sec. 250.242), fulfills 
requirements and is sufficiently accurate;
    (2) You have provided all needed additional information (see Sec. 
250.201(b)); and
    (3) You have provided the required number of copies (see Sec. 
250.206(a)).
    (b) Identify problems and deficiencies. If the Regional Supervisor 
determines that you have not met one or more of the conditions in 
paragraph (a) of this section, the Regional Supervisor will notify you 
of the problem or deficiency within 25 working days after the Regional 
Supervisor receives your DPP or DOCD and its accompanying information. 
The Regional Supervisor will not deem your DPP or DOCD submitted until 
you have corrected all problems or deficiencies identified in the 
notice.
    (c) Deemed submitted notification. The Regional Supervisor will 
notify you when your DPP or DOCD is deemed submitted.



Sec. 250.267  What actions will MMS take after the DPP or DOCD is deemed 

submitted?

    (a) State, local government, CZMA consistency, and other reviews. 
Within 2 working days after the Regional Supervisor deems your DPP or 
DOCD submitted under Sec. 250.266, the Regional Supervisor will use 
receipted mail or alternative method to send a public information copy 
of the DPP or DOCD and its accompanying information to the following:
    (1) The Governor of each affected State. The Governor has 60 
calendar days after receiving your deemed-submitted DPP or DOCD to 
submit comments and recommendations. The Regional Supervisor will not 
consider comments and recommendations received after the deadline.
    (2) The executive of any affected local government who requests a 
copy. The executive of any affected local government has 60 calendar 
days after receipt of your deemed-submitted DPP or DOCD to submit 
comments and recommendations. The Regional Supervisor will not consider 
comments and recommendations received after the deadline. The executive 
of any affected local government must forward all comments and 
recommendations to the respective Governor before submitting them to the 
Regional Supervisor.
    (3) The CZMA agency of each affected State. The CZMA consistency 
review period under section 307(c)(3)(B)(ii) of the CZMA (16 
U.S.C.1456(c)(3)(B)(ii)) and 15 CFR 930.78 begins when the States CZMA 
agency receives a copy of your deemed-submitted DPP or DOCD, consistency 
certification, and required necessary data/information (see 15 CFR 
930.77(a)(1)).
    (b) General public. Within 2 working days after the Regional 
Supervisor deems your DPP or DOCD submitted under Sec. 250.266, the 
Regional Supervisor will make a public information copy of

[[Page 325]]

the DPP or DOCD and its accompanying information available for review to 
any appropriate interstate regional entity and the public at the 
appropriate MMS Regional Public Information Office. Any interested 
Federal agency or person may submit comments and recommendations to the 
Regional Supervisor. Comments and recommendations must be received by 
the Regional Supervisor within 60 calendar days after the DPP or DOCD 
including its accompanying information is made available.
    (c) MMS compliance review. The Regional Supervisor will review the 
development and production activities in your proposed DPP or DOCD to 
ensure that they conform to the performance standards in Sec. 250.202.
    (d) Amendments. During the review of your proposed DPP or DOCD, the 
Regional Supervisor may require you, or you may elect, to change your 
DPP or DOCD. If you elect to amend your DPP or DOCD, the Regional 
Supervisor may determine that your DPP or DOCD, as amended, is subject 
to the requirements of Sec. 250.266.



Sec. 250.268  How does MMS respond to recommendations?

    (a) Governor. The Regional Supervisor will accept those 
recommendations from the Governor that provide a reasonable balance 
between the national interest and the well-being of the citizens of each 
affected State. The Regional Supervisor will explain in writing to the 
Governor the reasons for rejecting any of his or her recommendations.
    (b) Local governments and the public. The Regional Supervisor may 
accept recommendations from the executive of any affected local 
government or the public.
    (c) Availability. The Regional Supervisor will make all comments and 
recommendations available to the public upon request.



Sec. 250.269  How will MMS evaluate the environmental impacts of the DPP or 

DOCD?

    The Regional Supervisor will evaluate the environmental impacts of 
the activities described in your proposed DPP or DOCD and prepare 
environmental documentation under the National Environmental Policy Act 
(NEPA) (42 U.S.C.4321 et seq.) and the implementing regulations (40 CFR 
parts 1500 through 1508).
    (a) Environmental impact statement (EIS) declaration. At least once 
in each OCS planning area (other than the Western and Central GOM 
Planning Areas), the Director will declare that the approval of a 
proposed DPP is a major Federal action, and MMS will prepare an EIS.
    (b) Leases or units in the vicinity. Before or immediately after the 
Director determines that preparation of an EIS is required, the Regional 
Supervisor may require lessees and operators of leases or units in the 
vicinity of the proposed development and production activities for which 
DPPs have not been approved to submit information about preliminary 
plans for their leases or units.
    (c) Draft EIS. The Regional Supervisor will send copies of the draft 
EIS to the Governor of each affected State and to the executive of each 
affected local government who requests a copy. Additionally, when MMS 
prepares a DPP EIS, and the Federally-approved CZMA program for an 
affected State requires a DPP NEPA document for use in determining 
consistency, the Regional Supervisor will forward a copy of the draft 
EIS to the State's CZMA agency. The Regional Supervisor will also make 
copies of the draft EIS available to any appropriate Federal agency, 
interstate regional entity, and the public.



Sec. 250.270  What decisions will MMS make on the DPP or DOCD and within what 

timeframe?

    (a) Timeframe. The Regional Supervisor will act on your deemed-
submitted DPP or DOCD as follows:
    (1) The Regional Supervisor will make a decision within 60 calendar 
days after the latest of the day that:
    (i) The comment period provided in Sec. 250.267(a)(1), (a)(2), and 
(b) closes;
    (ii) The final EIS for a DPP is released or adopted; or
    (iii) The last amendment to your proposed DOCD is received by the 
Regional Supervisor.

[[Page 326]]

    (2) Notwithstanding paragraph (a)(1) of this section, MMS will not 
approve your DPP or DOCD until either:
    (i) All affected States with approved CZMA programs concur, or have 
been conclusively presumed to concur, with your DPP or DOCD consistency 
certification under section 307(c)(3)(B)(i) and (ii) of the CZMA (16 
U.S.C. 1456(c)(3)(B)(i) and (ii)); or
    (ii) The Secretary of Commerce has made a finding authorized by 
section 307(c)(3)(B)(iii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)) 
that each activity described in the DPP or DOCD is consistent with the 
objectives of the CZMA, or is otherwise necessary in the interest of 
national security.
    (b) MMS decision. By the deadline in paragraph (a) of this section, 
the Regional Supervisor will take one of the following actions:

------------------------------------------------------------------------
   The regional supervisor
         will . . .                 If . . .           And then . . .
------------------------------------------------------------------------
(1) Approve your DPP or DOCD  It complies with all  The Regional
                               applicable            Supervisor will
                               requirements.         notify you in
                                                     writing of the
                                                     decision and may
                                                     require you to meet
                                                     certain conditions,
                                                     including those to
                                                     provide monitoring
                                                     information.
(2) Require you to modify     It fails to make      The Regional
 your proposed DPP or DOCD.    adequate provisions   Supervisor will
                               for safety,           notify you in
                               environmental         writing of the
                               protection, or        decision and
                               conservation of       describe the
                               natural resources     modifications you
                               or otherwise does     must make to your
                               not comply with the   proposed DPP or
                               lease, the Act, the   DOCD to ensure it
                               regulations           complies with all
                               prescribed under      applicable
                               the Act, or other     requirements.
                               Federal laws.
(3) Disapprove your DPP or    Any of the reasons    (i) The Regional
 DOCD.                         in Sec.  250.271     Supervisor will
                               apply.                notify you in
                                                     writing of the
                                                     decision and
                                                     describe the
                                                     reason(s) for
                                                     disapproving your
                                                     DPP or DOCD; and
                                                    (ii) MMS may cancel
                                                     your lease and
                                                     compensate you
                                                     under 43 U.S.C.
                                                     1351(h)(2)(C) and
                                                     the implementing
                                                     regulations in Sec.
                                                      Sec.  250.183,
                                                     250.184, and
                                                     250.185 and 30 CFR
                                                     256.77.
------------------------------------------------------------------------


[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]



Sec. 250.271  For what reasons will MMS disapprove the DPP or DOCD?

    The Regional Supervisor will disapprove your proposed DPP or DOCD if 
one of the four reasons in this section applies:
    (a) Non-compliance. The Regional Supervisor determines that you have 
failed to demonstrate that you can comply with the requirements of the 
Outer Continental Shelf Lands Act, as amended (Act), implementing 
regulations, or other applicable Federal laws.
    (b) No consistency concurrence. (1) An affected State has not yet 
issued a final decision on your coastal zone consistency certification 
(see 15 CFR 930.78(a)); or
    (2) An affected State objects to your coastal zone consistency 
certification, and the Secretary of Commerce, under section 
307(c)(3)(B)(iii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)), has not 
found that each activity described in the DPP or DOCD is consistent with 
the objectives of the CZMA or is otherwise necessary in the interest of 
national security.
    (3) If the Regional Supervisor disapproved your DPP or DOCD for the 
sole reason that an affected State either has not yet issued a final 
decision on, or has objected to, your coastal zone consistency 
certification (see paragraphs (b)(1) and (2) in this section), the 
Regional Supervisor will approve your DPP or DOCD upon receipt of 
concurrence by the affected State, at the time concurrence of the 
affected State is conclusively presumed, or when the Secretary of 
Commerce makes a finding authorized by section 307(c)(3)(B)(iii) of the 
CZMA (16 U.S.C. 1456(c)(3)(B)(iii)) that each activity described in your 
DPP or DOCD is consistent with the objectives of the CZMA, or is 
otherwise necessary in the interest of national security. In that event, 
you do not need to resubmit your DPP or DOCD for approval under Sec. 
250.273(b).
    (c) National security or defense conflicts. Your proposed activities 
would threaten national security or defense.

[[Page 327]]

    (d) Exceptional circumstances. The Regional Supervisor determines 
because of exceptional geological conditions, exceptional resource 
values in the marine or coastal environment, or other exceptional 
circumstances that all of the following apply:
    (1) Implementing your DPP or DOCD would cause serious harm or damage 
to life (including fish and other aquatic life), property, any mineral 
deposits (in areas leased or not leased), the national security or 
defense, or the marine, coastal, or human environment;
    (2) The threat of harm or damage will not disappear or decrease to 
an acceptable extent within a reasonable period of time; and
    (3) The advantages of disapproving your DPP or DOCD outweigh the 
advantages of development and production.



Sec. 250.272  If a State objects to the DPP's or DOCD's coastal zone 

consistency certification, what can I do?

    If an affected State objects to the coastal zone consistency 
certification accompanying your proposed or disapproved DPP or DOCD, you 
may do one of the following:
    (a) Amend or resubmit your DPP or DOCD. Amend or resubmit your DPP 
or DOCD to accommodate the State's objection and submit the amendment or 
resubmittal to the Regional Supervisor for approval. The amendment or 
resubmittal needs to only address information related to the State's 
objections.
    (b) Appeal. Appeal the State's objection to the Secretary of 
Commerce using the procedures in 15 CFR part 930, subpart H. The 
Secretary of Commerce will either:
    (1) Grant your appeal by finding under section 307(c)(3)(B)(iii) of 
the CZMA (16 U.S.C.1456(c)(3)(B)(iii)) that each activity described in 
detail in your DPP or DOCD is consistent with the objectives of the 
CZMA, or is otherwise necessary in the interest of national security; or
    (2) Deny your appeal, in which case you may amend or resubmit your 
DPP or DOCD, as described in paragraph (a) of this section.
    (c) Withdraw your DPP or DOCD. Withdraw your DPP or DOCD if you 
decide not to conduct your proposed development and production 
activities.



Sec. 250.273  How do I submit a modified DPP or DOCD or resubmit a 

disapproved DPP or DOCD?

    (a) Modified DPP or DOCD. If the Regional Supervisor requires you to 
modify your proposed DPP or DOCD under Sec. 250.270(b)(2), you must 
submit the modification(s) to the Regional Supervisor in the same manner 
as for a new DPP or DOCD. You need submit only information related to 
the proposed modification(s).
    (b) Resubmitted DPP or DOCD. If the Regional Supervisor disapproves 
your DPP or DOCD under Sec. 250.270(b)(3), and except as provided in 
Sec. 250.271(b)(3), you may resubmit the disapproved DPP or DOCD if 
there is a change in the conditions that were the basis of its 
disapproval.
    (c) MMS review and timeframe. The Regional Supervisor will use the 
performance standards in Sec. 250.202 to either approve, require you to 
further modify, or disapprove your modified or resubmitted DPP or DOCD. 
The Regional Supervisor will make a decision within 60 calendar days 
after the Regional Supervisor deems your modified or resubmitted DPP or 
DOCD to be submitted, or receives the last amendment to your modified or 
resubmitted DPP or DOCD, whichever occurs later.

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



Sec. 250.280  How must I conduct activities under the approved EP, DPP, or 

DOCD?

    (a) Compliance. You must conduct all of your lease and unit 
activities according to your approved EP, DPP, or DOCD and any approval 
conditions. If you fail to comply with your approved EP, DPP, or DOCD:
    (1) You may be subject to MMS enforcement action, including civil 
penalties; and
    (2) The lease(s) involved in your EP, DPP, or DOCD may be forfeited 
or cancelled under 43 U.S.C. 1334(c) or (d). If this happens, you will 
not be entitled to compensation under Sec. 250.185(b) and 30 CFR 
256.77.
    (b) Emergencies. Nothing in this subpart or in your approved EP, 
DPP, or

[[Page 328]]

DOCD relieves you of, or limits your responsibility to take appropriate 
measures to meet emergency situations. In an emergency situation, the 
Regional Supervisor may approve or require departures from your approved 
EP, DPP, or DOCD.



Sec. 250.281  What must I do to conduct activities under the approved EP, 

DPP, or DOCD?

    (a) Approvals and permits. Before you conduct activities under your 
approved EP, DPP, or DOCD you must obtain the following approvals and or 
permits, as applicable, from the District Manager or Regional 
Supervisor:
    (1) Approval of applications for permits to drill (APDs) (see Sec. 
250.410);
    (2) Approval of production safety systems (see Sec. 250.800);
    (3) Approval of new platforms and other structures (or major 
modifications to platforms and other structures) (see Sec. 250.905);
    (4) Approval of applications to install lease term pipelines (see 
Sec. 250.1007); and
    (5) Other permits, as required by applicable law.
    (b) Conformance. The activities proposed in these applications and 
permits must conform to the activities described in detail in your 
approved EP, DPP, or DOCD.
    (c) Separate State CZMA consistency review. APDs, and other 
applications for licenses, approvals, or permits to conduct activities 
under your approved EP, DPP, or DOCD including those identified in 
paragraph (a) of this section, are not subject to separate State CZMA 
consistency review.
    (d) Approval restrictions for permits for activities conducted under 
EPs. The District Manager or Regional Supervisor will not approve any 
APDs or other applications for licenses, approvals, or permits under 
your approved EP until either:
    (1) All affected States with approved coastal zone management 
programs concur, or are conclusively presumed to concur, with the 
coastal zone consistency certification accompanying your EP under 
section 307(c)(3)(B)(i) and (ii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(i) 
and (ii)); or
    (2) The Secretary of Commerce finds, under section 307(c)(3)(B)(iii) 
of the CZMA (16 U.S.C.1456(c)(3)(B)(iii)) that each activity covered by 
the EP is consistent with the objectives of the CZMA or is otherwise 
necessary in the interest of national security;
    (3) If an affected State objects to the coastal zone consistency 
certification accompanying your approved EP after MMS has approved your 
EP, you may either:
    (i) Revise your EP to accommodate the State's objection and submit 
the revision to the Regional Supervisor for approval; or
    (ii) Appeal the State's objection to the Secretary of Commerce using 
the procedures in 15 CFR part 930 subpart H. The Secretary of Commerce 
will either:
    (A) Grant your appeal by making the finding described in paragraph 
(d)(2) of this section; or
    (B) Deny your appeal, in which case you may revise your EP as 
described in paragraph (d)(3)(i) of this section.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]



Sec. 250.282  Do I have to conduct post-approval monitoring?

    After approving your EP, DPP, or DOCD, the Regional Supervisor may 
direct you to conduct monitoring programs, including monitoring in 
accordance with the ESA and the MMPA. You must retain copies of all 
monitoring data obtained or derived from your monitoring programs and 
make them available to the MMS upon request. The Regional Supervisor may 
require you to:
    (a) Monitoring plans. Submit monitoring plans for approval before 
you begin the work; and
    (b) Monitoring reports. Prepare and submit reports that summarize 
and analyze data and information obtained or derived from your 
monitoring programs. The Regional Supervisor will specify requirements 
for preparing and submitting these reports.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]

[[Page 329]]



Sec. 250.283  When must I revise or supplement the approved EP, DPP, or DOCD?

    (a) Revised OCS plans. You must revise your approved EP, DPP, or 
DOCD when you propose to:
    (1) Change the type of drilling rig (e.g., jack-up, platform rig, 
barge, submersible, semisubmersible, or drillship), production facility 
(e.g., caisson, fixed platform with piles, tension leg platform), or 
transportation mode (e.g., pipeline, barge);
    (2) Change the surface location of a well or production platform by 
a distance more than that specified by the Regional Supervisor;
    (3) Change the type of production or significantly increase the 
volume of production or storage capacity;
    (4) Increase the emissions of an air pollutant to an amount that 
exceeds the amount specified in your approved EP, DPP, or DOCD;
    (5) Significantly increase the amount of solid or liquid wastes to 
be handled or discharged;
    (6) Request a new H2S area classification, or increase the 
concentration of H2S to a concentration greater than that specified by 
the Regional Supervisor;
    (7) Change the location of your onshore support base either from one 
State to another or to a new base or a base requiring expansion; or
    (8) Change any other activity specified by the Regional Supervisor.
    (b) Supplemental OCS plans. You must supplement your approved EP, 
DPP, or DOCD when you propose to conduct activities on your lease(s) or 
unit that require approval of a license or permit which is not described 
in your approved EP, DPP, or DOCD. These types of changes are called 
supplemental OCS plans.



Sec. 250.284  How will MMS require revisions to the approved EP, DPP, or 

DOCD?

    (a) Periodic review. The Regional Supervisor will periodically 
review the activities you conduct under your approved EP, DPP, or DOCD 
and may require you to submit updated information on your activities. 
The frequency and extent of this review will be based on the 
significance of any changes in available information and onshore or 
offshore conditions affecting, or affected by, the activities in your 
approved EP, DPP, or DOCD.
    (b) Results of review. The Regional Supervisor may require you to 
revise your approved EP, DPP, or DOCD based on this review. In such 
cases, the Regional Supervisor will inform you of the reasons for the 
decision.



Sec. 250.285  How do I submit revised and supplemental EPs, DPPs, and DOCDs?

    (a) Submittal. You must submit to the Regional Supervisor any 
revisions and supplements to approved EPs, DPPs, or DOCDs for approval, 
whether you initiate them or the Regional Supervisor orders them.
    (b) Information. Revised and supplemental EPs, DPPs, and DOCDs need 
include only information related to or affected by the proposed changes, 
including information on changes in expected environmental impacts.
    (c) Procedures. All supplemental EPs, DPPs, and DOCDs, and those 
revised EPs, DPPs, and DOCDs that the Regional Supervisor determines are 
likely to result in a significant change in the impacts previously 
identified and evaluated, are subject to all of the procedures under 
Sec. 250.231 through Sec.  250.235 for EPs and Sec.  250.266 through 
Sec. 250.273 for DPPs and DOCDs.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25201, May 4, 2007]

                    Deepwater Operations Plans (DWOP)



Sec. 250.286  What is a DWOP?

    (a) A DWOP is a plan that provides sufficient information for MMS to 
review a deepwater development project, and any other project that uses 
non-conventional production or completion technology, from a total 
system approach. The DWOP does not replace, but supplements other 
submittals required by the regulations such as Exploration Plans, 
Development and Production Plans, and Development Operations 
Coordination Documents. MMS will use the information in your DWOP to 
determine whether the project will be developed in an acceptable manner,

[[Page 330]]

particularly with respect to operational safety and environmental 
protection issues involved with non-conventional production or 
completion technology.
    (b) The DWOP process consists of two parts: a Conceptual Plan and 
the DWOP. Section 250.289 prescribes what the Conceptual Plan must 
contain, and Sec. 250.292 prescribes what the DWOP must contain.



Sec. 250.287  For what development projects must I submit a DWOP?

    You must submit a DWOP for each development project in which you 
will use non-conventional production or completion technology, 
regardless of water depth. If you are unsure whether MMS considers the 
technology of your project non-conventional, you must contact the 
Regional Supervisor for guidance.



Sec. 250.288  When and how must I submit the Conceptual Plan?

    You must submit four copies, or one hard copy and one electronic 
version, of the Conceptual Plan to the Regional Director after you have 
decided on the general concept(s) for development and before you begin 
engineering design of the well safety control system or subsea 
production systems to be used after well completion.



Sec. 250.289  What must the Conceptual Plan contain?

    In the Conceptual Plan, you must explain the general design basis 
and philosophy that you will use to develop the field. You must include 
the following information:
    (a) An overview of the development concept(s);
    (b) A well location plat;
    (c) The system control type (i.e., direct hydraulic or electro-
hydraulic); and
    (d) The distance from each of the wells to the host platform.



Sec. 250.290  What operations require approval of the Conceptual Plan?

    You may not complete any production well or install the subsea 
wellhead and well safety control system (often called the tree) before 
MMS has approved the Conceptual Plan.



Sec. 250.291  When and how must I submit the DWOP?

    You must submit four copies, or one hard copy and one electronic 
version, of the DWOP to the Regional Director after you have 
substantially completed safety system design and before you begin to 
procure or fabricate the safety and operational systems (other than the 
tree), production platforms, pipelines, or other parts of the production 
system.



Sec. 250.292  What must the DWOP contain?

    You must include the following information in your DWOP:
    (a) A description and schematic of the typical wellbore, casing, and 
completion;
    (b) Structural design, fabrication, and installation information for 
each surface system, including host facilities;
    (c) Design, fabrication, and installation information on the mooring 
systems for each surface system;
    (d) Information on any active stationkeeping system(s) involving 
thrusters or other means of propulsion used with a surface system;
    (e) Information concerning the drilling and completion systems;
    (f) Design and fabrication information for each riser system (e.g., 
drilling, workover, production, and injection);
    (g) Pipeline information;
    (h) Information about the design, fabrication, and operation of an 
offtake system for transferring produced hydrocarbons to a transport 
vessel;
    (i) Information about subsea wells and associated systems that 
constitute all or part of a single project development covered by the 
DWOP;
    (j) Flow schematics and Safety Analysis Function Evaluation (SAFE) 
charts (API RP 14C, subsection 4.3c, incorporated by reference in Sec. 
250.198) of the production system from the Surface Controlled Subsurface 
Safety Valve (SCSSV) downstream to the first item of separation 
equipment;
    (k) A description of the surface/subsea safety system and emergency 
support systems to include a table that depicts what valves will close, 
at what times, and for what events or reasons;

[[Page 331]]

    (l) A general description of the operating procedures, including a 
table summarizing the curtailment of production and offloading based on 
operational considerations;
    (m) A description of the facility installation and commissioning 
procedure;
    (n) A discussion of any new technology that affects hydrocarbon 
recovery systems;
    (o) A list of any alternate compliance procedures or departures for 
which you anticipate requesting approval; and
    (p) Payment of the service fee listed in Sec. 250.125.

[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]



Sec. 250.293  What operations require approval of the DWOP?

    You may not begin production until MMS approves your DWOP.



Sec. 250.294  May I combine the Conceptual Plan and the DWOP?

    If your development project meets the following criteria, you may 
submit a combined Conceptual Plan/DWOP on or before the deadline for 
submitting the Conceptual Plan.
    (a) The project is located in water depths of less than 400 meters 
(1,312 feet); and
    (b) The project is similar to projects involving non-conventional 
production or completion technology for which you have obtained approval 
previously.



Sec. 250.295  When must I revise my DWOP?

    You must revise either the Conceptual Plan or your DWOP to reflect 
changes in your development project that materially alter the 
facilities, equipment, and systems described in your plan. You must 
submit the revision within 60 days after any material change to the 
information required for that part of your plan.

                Conservation Information Documents (CID)



Sec. 250.296  When and how must I submit a CID or a revision to a CID?

    (a) You must submit one original and two copies of a CID to the 
appropriate OCS Region at the same time you first submit your DOCD or 
DPP for any development of a lease or leases located in water depths 
greater than 400 meters (1,312 feet). You must also submit a CID for a 
Supplemental DOCD or DPP when requested by the Regional Supervisor. The 
submission of your CID must be accompanied by payment of the service fee 
listed in Sec. 250.125.
    (b) If you decide not to develop a reservoir you committed to 
develop in your CID, you must submit one original and two copies of a 
revision to the CID to the appropriate OCS Region. The revision to the 
CID must be submitted within 14 calendar days after making your decision 
not to develop the reservoir and before the reservoir is bypassed. The 
Regional Supervisor will approve or disapprove any such revision to the 
original CID. If the Regional Supervisor disapproves the revision, you 
must develop the reservoir as described in the original CID.

[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]



Sec. 250.297  What information must a CID contain?

    (a) You must base the CID on wells drilled before your CID 
submittal, that define the extent of the reservoirs. You must notify MMS 
of any well that is drilled to total depth during the CID evaluation 
period and you may be required to update your CID.
    (b) You must include all of the following information if available. 
Information must be provided for each hydrocarbon-bearing reservoir that 
is penetrated by a well that would meet the producibility requirements 
of Sec. 250.115 or Sec.  250.116:
    (1) General discussion of the overall development of the reservoir;
    (2) Summary spreadsheets of well log data and reservoir parameters 
(i.e., sand tops and bases, fluid contacts, net pay, porosity, water 
saturations, pressures, formation volume factor);
    (3) Appropriate well logs, including digital well log (i.e., gamma 
ray, resistivity, neutron, density, sonic, caliper curves) curves in an 
acceptable digital format;
    (4) Sidewall core/whole core and pressure-volume-temperature 
analysis;
    (5) Structure maps, with the existing and proposed penetration 
points and

[[Page 332]]

subsea depths for all wells penetrating the reservoirs, fluid contacts 
(or the lowest or highest known levels in the absence of actual 
contacts), reservoir boundaries, and the scale of the map;
    (6) Interpreted structural cross sections and corresponding 
interpreted seismic lines or block diagrams, as necessary, that include 
all current wellbores and planned wellbores on the leases or units to be 
developed, the reservoir boundaries, fluid contacts, depth scale, 
stratigraphic positions, and relative biostratigraphic ages;
    (7) Isopach maps of each reservoir showing the net feet of pay for 
each well within the reservoir identified at the penetration point, 
along with the well name, labeled contours, and scale;
    (8) Estimates of original oil and gas in-place and anticipated 
recoverable oil and gas reserves, all reservoir parameters, and risk 
factors and assumptions;
    (9) Plat map at the same scale as the structure maps with existing 
and proposed well paths, as well as existing and proposed penetrations;
    (10) Wellbore schematics indicating proposed perforations;
    (11) Proposed wellbore utility chart showing all existing and 
proposed wells, with proposed completion intervals indicated for each 
borehole;
    (12) Appropriate pressure data, specified by date, and whether 
estimated or measured;
    (13) Description of reservoir development strategies;
    (14) Description of the enhanced recovery practices you will use or, 
if you do not plan to use such practices, an explanation of the methods 
you considered and reasons you do not intend to use them;
    (15) For each reservoir you do not intend to develop:
    (i) A statement explaining the reason(s) you will not develop the 
reservoir, and
    (ii) Economic justification, including costs, recoverable reserve 
estimate, production profiles, and pricing assumptions; and
    (16) Any other appropriate data you used in performing your 
reservoir evaluations and preparing your reservoir development 
strategies.



Sec. 250.298  How long will MMS take to evaluate and make a decision on the 

CID?

    (a) The Regional Supervisor will make a decision within 150 calendar 
days of receiving your CID. If MMS does not act within 150 calendar 
days, your CID is considered approved.
    (b) MMS may suspend the 150-calendar-day evaluation period if there 
is missing, inconclusive, or inaccurate data, or when a well reaches 
total depth during the evaluation period. MMS may also suspend the 
evaluation period when a well penetrating a hydrocarbon-bearing 
structure reaches total depth during the evaluation period and the data 
from that well is needed for the CID. You will receive written 
notification from the Regional Supervisor describing the additional 
information that is needed, and the evaluation period will resume once 
MMS receives the requested information.
    (c) The Regional Supervisor will approve or deny your CID request 
based on your commitment to develop economically producible reservoirs 
according to sound conservation, engineering, and economic practices.



Sec. 250.299  What operations require approval of the CID?

    You may not begin production before you receive MMS approval of the 
CID.



               Subpart C_Pollution Prevention and Control



Sec. 250.300  Pollution prevention.

    (a) During the exploration, development, production, and 
transportation of oil and gas or sulphur, the lessee shall take measures 
to prevent unauthorized discharge of pollutants into the offshore 
waters. The lessee shall not create conditions that will pose 
unreasonable risk to public health, life, property, aquatic life, 
wildlife, recreation, navigation, commercial fishing, or other uses of 
the ocean.
    (1) When pollution occurs as a result of operations conducted by or 
on behalf of the lessee and the pollution damages or threatens to damage 
life (including fish and other aquatic life), property, any mineral 
deposits (in areas leased or not leased), or the marine, coastal, or

[[Page 333]]

human environment, the control and removal of the pollution to the 
satisfaction of the District Manager shall be at the expense of the 
lessee. Immediate corrective action shall be taken in all cases where 
pollution has occurred. Corrective action shall be subject to 
modification when directed by the District Manager.
    (2) If the lessee fails to control and remove the pollution, the 
Director, in cooperation with other appropriate Agencies of Federal, 
State, and local governments, or in cooperation with the lessee, or 
both, shall have the right to control and remove the pollution at the 
lessee's expense. Such action shall not relieve the lessee of any 
responsibility provided for by law.
    (b)(1) The District Manager may restrict the rate of drilling fluid 
discharges or prescribe alternative discharge methods. The District 
Manager may also restrict the use of components which could cause 
unreasonable degradation to the marine environment. No petroleum-based 
substances, including diesel fuel, may be added to the drilling mud 
system without prior approval of the District Manager.
    (2) Approval of the method of disposal of drill cuttings, sand, and 
other well solids shall be obtained from the District Manager.
    (3) All hydrocarbon-handling equipment for testing and production 
such as separators, tanks, and treaters shall be designed, installed, 
and operated to prevent pollution. Maintenance or repairs which are 
necessary to prevent pollution of offshore waters shall be undertaken 
immediately.
    (4) Curbs, gutters, drip pans, and drains shall be installed in deck 
areas in a manner necessary to collect all contaminants not authorized 
for discharge. Oil drainage shall be piped to a properly designed, 
operated, and maintained sump system which will automatically maintain 
the oil at a level sufficient to prevent discharge of oil into offshore 
waters. All gravity drains shall be equipped with a water trap or other 
means to prevent gas in the sump system from escaping through the 
drains. Sump piles shall not be used as processing devices to treat or 
skim liquids but may be used to collect treated-produced water, treated-
produced sand, or liquids from drip pans and deck drains and as a final 
trap for hydrocarbon liquids in the event of equipment upsets. 
Improperly designed, operated, or maintained sump piles which do not 
prevent the discharge of oil into offshore waters shall be replaced or 
repaired.
    (5) On artificial islands, all vessels containing hydrocarbons shall 
be placed inside an impervious berm or otherwise protected to contain 
spills. Drainage shall be directed away from the drilling rig to a sump. 
Drains and sumps shall be constructed to prevent seepage.
    (6) Disposal of equipment, cables, chains, containers, or other 
materials into offshore waters is prohibited.
    (c) Materials, equipment, tools, containers, and other items used in 
the Outer Continental Shelf (OCS) which are of such shape or 
configuration that they are likely to snag or damage fishing devices 
shall be handled and marked as follows:
    (1) All loose material, small tools, and other small objects shall 
be kept in a suitable storage area or a marked container when not in use 
and in a marked container before transport over offshore waters;
    (2) All cable, chain, or wire segments shall be recovered after use 
and securely stored until suitable disposal is accomplished;
    (3) Skid-mounted equipment, portable containers, spools or reels, 
and drums shall be marked with the owner's name prior to use or 
transport over offshore waters; and
    (4) All markings must clearly identify the owner and must be durable 
enough to resist the effects of the environmental conditions to which 
they may be exposed.
    (d) Any of the items described in paragraph (c) of this section that 
are lost overboard shall be recorded on the facility's daily operations 
report, as appropriate, and reported to the District Manager.

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



Sec. 250.301  Inspection of facilities.

    (a) Drilling and production facilities shall be inspected daily or 
at intervals

[[Page 334]]

approved or prescribed by the District Manager to determine if pollution 
is occurring. Necessary maintenance or repairs shall be made 
immediately. Records of such inspections and repairs shall be maintained 
at the facility or at a nearby manned facility for 2 years.

[53 FR 10690, Apr. 1, 1988, as amended at 62 FR 13996, Mar. 25, 1997. 
Redesignated at 63 FR 29479, May 29, 1998]



Sec. 250.302  Definitions concerning air quality.

    For purposes of Sec. Sec. 250.303 and 250.304 of this part:
    Air pollutant means any combination of agents for which the 
Environmental Protection Agency (EPA) has established, pursuant to 
section 109 of the Clean Air Act, national primary or secondary ambient 
air quality standards.
    Attainment area means, for any air pollutant, an area which is shown 
by monitored data or which is calculated by air quality modeling (or 
other methods determined by the Administrator of EPA to be reliable) not 
to exceed any primary or secondary ambient air quality standards 
established by EPA.
    Best available control technology (BACT) means an emission 
limitation based on the maximum degree of reduction for each air 
pollutant subject to regulation, taking into account energy, 
environmental and economic impacts, and other costs. The BACT shall be 
verified on a case-by-case basis by the Regional Supervisor and may 
include reductions achieved through the application of processes, 
systems, and techniques for the control of each air pollutant.
    Emission offsets means emission reductions obtained from facilities, 
either onshore or offshore, other than the facility or facilities 
covered by the proposed Exploration Plan or Development and Production 
Plan.
    Existing facility is an OCS facility described in an Exploration 
Plan or a Development and Production Plan submitted or approved prior to 
June 2, 1980.
    Facility means any installation or device permanently or temporarily 
attached to the seabed which is used for exploration, development, and 
production activities for oil, gas, or sulphur and which emits or has 
the potential to emit any air pollutant from one or more sources. All 
equipment directly associated with the installation or device shall be 
considered part of a single facility if the equipment is dependent on, 
or affects the processes of, the installation or device. During 
production, multiple installations or devices will be considered to be a 
single facility if the installations or devices are directly related to 
the production of oil, gas, or sulphur at a single site. Any vessel used 
to transfer production from an offshore facility shall be considered 
part of the facility while physically attached to it.
    Nonattainment area means, for any air pollutant, an area which is 
shown by monitored data or which is calculated by air quality modeling 
(or other methods determined by the Administrator of EPA to be reliable) 
to exceed any primary or secondary ambient air quality standard 
established by EPA.
    Projected emissions means emissions, either controlled or 
uncontrolled, from a source(s).
    Source means an emission point. Several sources may be included 
within a single facility.
    Temporary facility means activities associated with the construction 
of platforms offshore or with facilities related to exploration for or 
development of offshore oil and gas resources which are conducted in one 
location for less than 3 years.
    Volatile organic compound (VOC) means any organic compound which is 
emitted to the atmosphere as a vapor. The unreactive compounds are 
exempt from the above definition.

[53 FR 10690, Apr. 1, 1988, as amended at 56 FR 32100, July 15, 1991. 
Redesignated and amended at 63 FR 29479, 29485, May 29, 1998]



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

[[Page 335]]

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. 250.218 or 
Sec. 250.249 of this part and to submit only that information required 
to make the necessary findings under paragraphs (d) through (i) of this 
section. The lessee shall submit this information within 120 days of the 
Regional Supervisor's determination or within a longer period of time at 
the discretion of the Regional Supervisor. The lessee shall comply with 
the requirements of this section as necessary.
    (c) Revised facilities. All revised Exploration Plans and 
Development and Production Plans shall include the information required 
to make the necessary findings under paragraphs (d) through (i) of this 
section. The lessee shall comply with the requirements of this section 
as necessary.
    (d) Exemption formulas. To determine whether a facility described in 
a new, modified, or revised Exploration Plan or Development and 
Production Plan is exempt from further air quality review, the lessee 
shall use the highest annual-total amount of emissions from the facility 
for each air pollutant calculated in Sec. 250.249(a) or Sec.  
250.218(a) of this part and compare these emissions to the emission 
exemption amount ``E'' for each air pollutant calculated using the 
following formulas: E=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 ([micro]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 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

[[Page 336]]

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 ([micro]g/m\3\)
------------------------------------------------------------------------
                                                    Averaging times
                                              --------------------------
                Air pollutant                   Annual
                                                 mean   24-hour   3-hour
                                                 \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 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

[[Page 337]]

other facilities in the area, significantly affect the air quality of an 
onshore area, then the Regional Supervisor shall require the lessee to 
submit additional information to determine whether emission control 
measures are necessary. The lessee shall be given the opportunity to 
present information to the Regional Supervisor which demonstrates that 
the exempt facility is not significantly affecting the air quality of an 
onshore area of the State.
    (k) Emission monitoring requirements. The lessee shall monitor, in a 
manner approved or prescribed by the Regional Supervisor, emissions from 
the facility. The lessee shall submit this information monthly in a 
manner and form approved or prescribed by the Regional Supervisor.
    (l) Collection of meteorological data. The Regional Supervisor may 
require the lessee to collect, for a period of time and in a manner 
approved or prescribed by the Regional Supervisor, and submit 
meteorological data from a facility.

[53 FR 10690, Apr. 1, 1988; 53 FR 19856, May 31, 1988; 53 FR 26067, July 
11, 1988. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 
70 FR 51518, Aug. 30, 2005]



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. 250.218 or 250.249 of this part 
and submit only that information required to make the necessary findings 
under paragraphs (b) through (e) of this section. The lessee shall 
submit this information within 120 days of the Regional Supervisor's 
determination or within a longer period of time at the discretion of the 
Regional Supervisor. The lessee shall comply with the requirements of 
this section as necessary.
    (b) Exemption formulas. To determine whether an existing facility is 
exempt from further air quality review, the lessee shall use the highest 
annual total amount of emissions from the facility for each air 
pollutant calculated in Sec. 250.218(a) or 250.249(a) of this part and 
compare these emissions to the emission exemption amount ``E'' for each 
air pollutant calculated using the following formulas: 
E=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

[[Page 338]]

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 ([micro]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, and submit 
meteorological data from a facility.

[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11, 1988. Redesignated and 
amended at 63 FR 29479, 29485, May 29, 1998; 64 FR 72794, Dec. 28, 1999; 
70 FR 51519, Aug. 30, 2005]



                Subpart D_Oil and Gas Drilling Operations

                          General Requirements



Sec. 250.400  Who is subject to the requirements of this subpart?

    The requirements of this subpart apply to lessees, operating rights 
owners, operators, and their contractors and subcontractors.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.401  What must I do to keep wells under control?

    You must take necessary precautions to keep wells under control at 
all times. You must:

[[Page 339]]

    (a) Use the best available and safest drilling technology to monitor 
and evaluate well conditions and to minimize the potential for the well 
to flow or kick;
    (b) Have a person onsite during drilling operations who represents 
your interests and can fulfill your responsibilities;
    (c) Ensure that the toolpusher, operator's representative, or a 
member of the drilling crew maintains continuous surveillance on the rig 
floor from the beginning of drilling operations until the well is 
completed or abandoned, unless you have secured the well with blowout 
preventers (BOPs), bridge plugs, cement plugs, or packers;
    (d) Use personnel trained according to the provisions of subpart O; 
and
    (e) Use and maintain equipment and materials necessary to ensure the 
safety and protection of personnel, equipment, natural resources, and 
the environment.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.402  When and how must I secure a well?

    Whenever you interrupt drilling operations, you must install a 
downhole safety device, such as a cement plug, bridge plug, or packer. 
You must install the device at an appropriate depth within a properly 
cemented casing string or liner.
    (a) Among the events that may cause you to interrupt drilling 
operations are:
    (1) Evacuation of the drilling crew;
    (2) Inability to keep the drilling rig on location; or
    (3) Repair to major drilling or well-control equipment.
    (b) For floating drilling operations, the District Manager may 
approve the use of blind or blind-shear rams or pipe rams and an inside 
BOP if you don't have time to install a downhole safety device or if 
special circumstances occur.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.403  What drilling unit movements must I report?

    (a) You must report the movement of all drilling units on and off 
drilling locations to the District Manager. This includes both MODU and 
platform rigs. You must inform the District Manager 24 hours before:
    (1) The arrival of an MODU on location;
    (2) The movement of a platform rig to a platform;
    (3) The movement of a platform rig to another slot;
    (4) The movement of an MODU to another slot; and
    (5) The departure of an MODU from the location.
    (b) You must provide the District Manager with the rig name, lease 
number, well number, and expected time of arrival or departure.
    (c) In the Gulf of Mexico OCS Region, you must report drilling unit 
movements on form MMS-144, Rig Movement Notification Report.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.404  What are the requirements for the crown block?

    You must have a crown block safety device that prevents the 
traveling block from striking the crown block. You must check the device 
for proper operation at least once per week and after each drill-line 
slipping operation and record the results of this operational check in 
the driller's report.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.405  What are the safety requirements for diesel engines used on a 

drilling rig?

    You must equip each diesel engine with an air take device to shut 
down the diesel engine in the event of a runaway.
    (a) For a diesel engine that is not continuously manned, you must 
equip the engine with an automatic shutdown device;
    (b) For a diesel engine that is continuously manned, you may equip 
the engine with either an automatic or remote manual air intake shutdown 
device;
    (c) You do not have to equip a diesel engine with an air intake 
device if it meets one of the following criteria:
    (1) Starts a larger engine;
    (2) Powers a firewater pump;
    (3) Powers an emergency generator;
    (4) Powers a BOP accumulator system;

[[Page 340]]

    (5) Provides air supply to divers or confined entry personnel;
    (6) Powers temporary equipment on a nonproducing platform;
    (7) Powers an escape capsule; or
    (8) Powers a portable single-cylinder rig washer.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.406  What additional safety measures must I take when I conduct 

drilling operations on a platform that has producing wells or has other 

hydrocarbon flow?

    You must take the following safety measures when you conduct 
drilling operations on a platform with producing wells or that has other 
hydrocarbon flow:
    (a) You must install an emergency shutdown station near the 
driller's console;
    (b) You must shut in all producible wells located in the affected 
wellbay below the surface and at the wellhead when:
    (1) You move a drilling rig or related equipment on and off a 
platform. This includes rigging up and rigging down activities within 
500 feet of the affected platform;
    (2) You move or skid a drilling unit between wells on a platform;
    (3) A mobile offshore drilling unit (MODU) moves within 500 feet of 
a platform. You may resume production once the MODU is in place, 
secured, and ready to begin drilling operations.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.407  What tests must I conduct to determine reservoir 

characteristics?

    You must determine the presence, quantity, quality, and reservoir 
characteristics of oil, gas, sulphur, and water in the formations 
penetrated by logging, formation sampling, or well testing.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.408  May I use alternative procedures or equipment during drilling 

operations?

    You may use alternative procedures or equipment during drilling 
operations after receiving approval from the District Manager. You must 
identify and discuss your proposed alternative procedures or equipment 
in your Application for Permit to Drill (APD) (Form MMS-123) (see Sec. 
250.414(h)). Procedures for obtaining approval are described in section 
250.141 of this part.

[68 FR 8423, Feb. 20, 2003, as amended at 72 FR 25201, May 4, 2007]



Sec. 250.409  May I obtain departures from these drilling requirements?

    The District Manager may approve departures from the drilling 
requirements specified in this subpart. You may apply for a departure 
from drilling requirements by writing to the District Manager. You 
should identify and discuss the departure you are requesting in your APD 
(see Sec. 250.414(h)).

[68 FR 8423, Feb. 20, 2003]

                     Applying for a Permit To Drill



Sec. 250.410  How do I obtain approval to drill a well?

    You must obtain written approval from the District Manager before 
you begin drilling any well or before you sidetrack, bypass, or deepen a 
well. To obtain approval, you must:
    (a) Submit the information required by Sec. 250.411 through 
250.418;
    (b) Include the well in your approved Exploration Plan (EP), 
Development and Production Plan (DPP), or Development Operations 
Coordination Document (DOCD);
    (c) Meet the oil spill financial responsibility requirements for 
offshore facilities as required by 30 CFR part 253; and
    (d) Submit the following to the District Manager:
    (1) An original and two complete copies of Form MMS-123, Application 
for Permit to Drill (APD), and Form MMS-123S, Supplemental APD 
Information Sheet;
    (2) A separate public information copy of forms MMS-123 and MMS-123S 
that meets the requirements of Sec. 250.186; and
    (3) Payment of the service fee listed in Sec. 250.125.

[68 FR 8423, Feb. 20, 2003, as amended at 71 FR 40911, July 19, 2006; 72 
FR 25201, May 4, 2007]

[[Page 341]]



Sec. 250.411  What information must I submit with my application?

    In addition to forms MMS-123 and MMS-123S, you must include the 
information described in the following table.

------------------------------------------------------------------------
 Information that you must include with an         Where to find a
                    APD                              description
------------------------------------------------------------------------
(a) Plat that shows locations of the         Sec.  250.412
 proposed well.
(b) Design criteria used for the proposed    Sec.  250.413
 well.
(c) Drilling prognosis.....................  Sec.  250.414
(d) Casing and cementing programs..........  Sec.  250.415
(e) Diverter and BOP systems descriptions..  Sec.  250.416
(f) Requirements for using an MODU.........  Sec.  250.417
(g) Additional information.................  Sec.  250.418
------------------------------------------------------------------------


[68 FR 8423, Feb. 20, 2003]



Sec. 250.412  What requirements must the location plat meet?

    The location plat must:
    (a) Have a scale of 1:24,000 (1 inch = 2,000 feet);
    (b) Show the surface and subsurface locations of the proposed well 
and all the wells in the vicinity;
    (c) Show the surface and subsurface locations of the proposed well 
in feet or meters from the block line;
    (d) Contain the longitude and latitude coordinates, and either 
Universal Transverse Mercator grid-system coordinates or state plane 
coordinates in the Lambert or Transverse Mercator Projection system for 
the surface and subsurface locations of the proposed well; and
    (e) State the units and geodetic datum (including whether the datum 
is North American Datum 27 or 83) for these coordinates. If the datum 
was converted, you must state the method used for this conversion, since 
the various methods may produce different values.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.413  What must my description of well drilling design criteria 

address?

    Your description of well drilling design criteria must address:
    (a) Pore pressures;
    (b) Formation fracture gradients, adjusted for water depth;
    (c) Potential lost circulation zones;
    (d) Drilling fluid weights;
    (e) Casing setting depths;
    (f) Maximum anticipated surface pressures. For this section, maximum 
anticipated surface pressures are the pressures that you reasonably 
expect to be exerted upon a casing string and its related wellhead 
equipment. In calculating maximum anticipated surface pressures, you 
must consider: drilling, completion, and producing conditions; drilling 
fluid densities to be used below various casing strings; fracture 
gradients of the exposed formations; casing setting depths; total well 
depth; formation fluid types; safety margins; and other pertinent 
conditions. You must include the calculations used to determine the 
pressures for the drilling and the completion phases, including the 
anticipated surface pressure used for designing the production string;
    (g) A single plot containing estimated pore pressures, formation 
fracture gradients, proposed drilling fluid weights, and casing setting 
depths in true vertical measurements;
    (h) A summary report of the shallow hazards site survey that 
describes the geological and manmade conditions if not previously 
submitted; and
    (i) Permafrost zones, if applicable.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.414  What must my drilling prognosis include?

    Your drilling prognosis must include a brief description of the 
procedures you will follow in drilling the well. This prognosis includes 
but is not limited to the following:
    (a) Projected plans for coring at specified depths;
    (b) Projected plans for logging;
    (c) Planned safe drilling margin between proposed drilling fluid 
weights and estimated pore pressures. This safe drilling margin may be 
shown on the plot required by Sec. 250.413(g);
    (d) Estimated depths to the top of significant marker formations;
    (e) Estimated depths to significant porous and permeable zones 
containing fresh water, oil, gas, or abnormally pressured formation 
fluids;
    (f) Estimated depths to major faults;
    (g) Estimated depths of permafrost, if applicable;
    (h) A list and description of all requests for using alternative 
procedures

[[Page 342]]

or departures from the requirements of this subpart in one place in the 
APD. You must explain how the alternative procedures afford an equal or 
greater degree of protection, safety, or performance, or why you need 
the departures; and
    (i) Projected plans for well testing (refer to Sec. 250.460 for 
safety requirements).

[68 FR 8423, Feb. 20, 2003]



Sec. 250.415  What must my casing and cementing programs include?

    Your casing and cementing programs must include:
    (a) Hole sizes and casing sizes, including: weights; grades; 
collapse, and burst values; types of connection; and setting depths 
(measured and true vertical depth (TVD));
    (b) Casing design safety factors for tension, collapse, and burst 
with the assumptions made to arrive at these values;
    (c) Type and amount of cement (in cubic feet) planned for each 
casing string; and
    (d) In areas containing permafrost, setting depths for conductor and 
surface casing based on the anticipated depth of the permafrost. Your 
program must provide protection from thaw subsidence and freezeback 
effect, proper anchorage, and well control.
    (e) A statement of how you evaluated the best practices included in 
API RP 65, Recommended Practice for Cementing Shallow Water Flow Zones 
in Deep Water Wells (incorporated by reference as specified in Sec. 
250.198), if you drill a well in water depths greater than 500 feet and 
are in either of the following two areas:
    (1) An ``area with an unknown shallow water flow potential'' is a 
zone or geologic formation where neither the presence nor absence of 
potential for a shallow water flow has been confirmed.
    (2) An ``area known to contain a shallow water flow hazard'' is a 
zone or geologic formation for which drilling has confirmed the presence 
of shallow water flow.

[68 FR 8423, Feb. 20, 2003, as amended at 72 FR 8903, Feb. 28, 2007]



Sec. 250.416  What must I include in the diverter and BOP descriptions?

    You must include in the diverter and BOP descriptions:
    (a) A description of the diverter system and its operating 
procedures;
    (b) A schematic drawing of the diverter system (plan and elevation 
views) that shows:
    (1) The size of the annular BOP installed in the diverter housing;
    (2) Spool outlet internal diameter(s);
    (3) Diverter-line lengths and diameters; burst strengths and radius 
of curvature at each turn; and
    (4) Valve type, size, working pressure rating, and location;
    (c) A description of the BOP system and system components, including 
pressure ratings of BOP equipment and proposed BOP test pressures;
    (d) A schematic drawing of the BOP system that shows the inside 
diameter of the BOP stack, number and type of preventers, location of 
choke and kill lines, and associated valves; and
    (e) Information that shows the blind-shear rams installed in the BOP 
stack (both surface and subsea stacks) are capable of shearing the drill 
pipe in the hole under maximum anticipated surface pressures.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.417  What must I provide if I plan to use a mobile offshore drilling 

unit (MODU)?

    If you plan to use a MODU, you must provide:
    (a) Fitness requirements. You must provide information and data to 
demonstrate the drilling unit's capability to perform at the proposed 
drilling location. This information must include the maximum 
environmental and operational conditions that the unit is designed to 
withstand, including the minimum air gap necessary for both hurricane 
and non-hurricane seasons. If sufficient environmental information and 
data are not available at the time you submit your APD, the District 
Manager may approve your APD but require you to collect and report this 
information during operations. Under this circumstance, the District 
Manager has the right to revoke the approval of the APD if information 
collected during operations show that the

[[Page 343]]

drilling unit is not capable of performing at the proposed location.
    (b) Foundation requirements. You must provide information to show 
that site-specific soil and oceanographic conditions are capable of 
supporting the proposed drilling unit. If you provided sufficient site-
specific information in your EP, DPP, or DOCD, you may reference that 
information. The District Manager may require you to conduct additional 
surveys and soil borings before approving the APD if additional 
information is needed to make a determination that the conditions are 
capable of supporting the drilling unit.
    (c) Frontier areas. (1) If the design of the drilling unit you plan 
to use in a frontier area is unique or has not been proven for use in 
the proposed environment, the District Manager may require you to submit 
a third-party review of the unit's design. If required, you must obtain 
the third-party review according to Sec. 250.915 through Sec.  250.918. 
You may submit this information before submitting an APD.
    (2) If you plan to drill in a frontier area, you must have a 
contingency plan that addresses design and operating limitations of the 
drilling unit. Your plan must identify the actions necessary to maintain 
safety and prevent damage to the environment. Actions must include the 
suspension, curtailment, or modification of drilling or rig operations 
to remedy various operational or environmental situations (e.g. vessel 
motion, riser offset, anchor tensions, wind speed, wave height, 
currents, icing or ice-loading, settling, tilt or lateral movement, 
resupply capability).
    (d) U.S. Coast Guard (USCG) documentation. You must provide the 
current Certificate of Inspection or Letter of Compliance from the USCG. 
You must also provide current documentation of any operational 
limitations imposed by an appropriate classification society.
    (e) Floating drilling unit. If you use a floating drilling unit, you 
must indicate that you have a contingency plan for moving off location 
in an emergency situation.
    (f) Inspection of unit. The drilling unit must be available for 
inspection by the District Manager before commencing operations.
    (g) Once the District Manager has approved a MODU for use, you do 
not need to re-submit the information required by this section for 
another APD to use the same MODU unless changes in equipment affect its 
rated capacity to operate in the District.

[68 FR 8423, Feb. 20, 2003, as amended at 72 FR 25201, May 4, 2007]



Sec. 250.418  What additional information must I submit with my APD?

    You must include the following with the APD:
    (a) Rated capacities of the drilling rig and major drilling 
equipment, if not already on file with the appropriate District office;
    (b) A drilling fluids program that includes the minimum quantities 
of drilling fluids and drilling fluid materials, including weight 
materials, to be kept at the site;
    (c) A proposed directional plot if the well is to be directionally 
drilled;
    (d) A Hydrogen Sulfide Contingency Plan (see Sec. 250.490), if 
applicable, and not previously submitted;
    (e) A welding plan (see Sec. Sec. 250.109 to 250.113) if not 
previously submitted;
    (f) In areas subject to subfreezing conditions, evidence that the 
drilling equipment, BOP systems and components, diverter systems, and 
other associated equipment and materials are suitable for operating 
under such conditions;
    (g) A request for approval if you plan to wash out or displace some 
cement to facilitate casing removal upon well abandonment; and
    (h) Such other information as the District Manager may require.

[68 FR 8423, Feb. 20, 2003]

                    Casing and Cementing Requirements



Sec. 250.420  What well casing and cementing requirements must I meet?

    You must case and cement all wells. Your casing and cementing 
programs must meet the requirements of this section and of Sec. Sec. 
250.421 through 250.428.
    (a) Casing and cementing program requirements. Your casing and 
cementing programs must:

[[Page 344]]

    (1) Properly control formation pressures and fluids;
    (2) Prevent the direct or indirect release of fluids from any 
stratum through the wellbore into offshore waters;
    (3) Prevent communication between separate hydrocarbon-bearing 
strata;
    (4) Protect freshwater aquifers from contamination; and
    (5) Support unconsolidated sediments.
    (b) Casing requirements. (1) You must design casing (including 
liners) to withstand the anticipated stresses imposed by tensile, 
compressive, and buckling loads; burst and collapse pressures; thermal 
effects; and combinations thereof.
    (2) The casing design must include safety measures that ensure well 
control during drilling and safe operations during the life of the well.
    (c) Cementing requirements. You must design and conduct your 
cementing jobs so that cement composition, placement techniques, and 
waiting times ensure that the cement placed behind the bottom 500 feet 
of casing attains a minimum compressive strength of 500 psi before 
drilling out of the casing or before commencing completion operations.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.421  What are the casing and cementing requirements by type of 

casing string?

    The table in this section identifies specific design, setting, and 
cementing requirements for casing strings and liners. For the purposes 
of subpart D, the casing strings in order of normal installation are as 
follows: drive or structural, conductor, surface, intermediate, and 
production casings (including liners). The District Manager may approve 
or prescribe other casing and cementing requirements where appropriate.

------------------------------------------------------------------------
                                        Casing             Cementing
           Casing type               requirements        requirements
------------------------------------------------------------------------
(a) Drive or Structural.........  Set by driving,     If you drilled a
                                   jetting, or         portion of this
                                   drilling to the     hole, you must
                                   minimum depth as    use enough cement
                                   approved or         to fill the
                                   prescribed by the   annular space
                                   District Manager.   back to the
                                                       mudline.
(b) Conductor...................  Design casing and   Use enough cement
                                   select setting      to fill the
                                   depths based on     calculated
                                   relevant            annular space
                                   engineering and     back to the
                                   geologic factors.   mudline.
                                   These factors      Verify annular
                                   include the         fill by observing
                                   presence or         cement returns.
                                   absence of          If you cannot
                                   hydrocarbons,       observe cement
                                   potential           returns, use
                                   hazards, and        additional cement
                                   water depths.       to ensure fill-
                                  Set casing           back to the
                                   immediately         mudline.
                                   before drilling    For drilling on an
                                   into formations     artificial island
                                   known to contain    or when using a
                                   oil or gas. If      glory hole, you
                                   you encounter oil   must discuss the
                                   or gas or           cement fill level
                                   unexpected          with the District
                                   formation           Manager.
                                   pressure before
                                   the planned
                                   casing point, you
                                   must set casing
                                   immediately.
(c) Surface.....................  Design casing and   Use enough cement
                                   select setting      to fill the
                                   depths based on     calculated
                                   relevant            annular space to
                                   engineering and     at least 200 feet
                                   geologic factors.   inside the
                                   These factors       conductor casing.
                                   include the        When geologic
                                   presence or         conditions such
                                   absence of          as near-surface
                                   hydrocarbons,       fractures and
                                   potential           faulting exist,
                                   hazards, and        you must use
                                   water depths.       enough cement to
                                                       fill the
                                                       calculated
                                                       annular space to
                                                       the mudline.
(d) Intermediate................  Design casing and   Use enough cement
                                   select setting      to cover and
                                   depth based on      isolate all
                                   anticipated or      hydrocarbon-
                                   encountered         bearing zones and
                                   geologic            isolate abnormal
                                   characteristics     pressure
                                   or wellbore         intervals from
                                   conditions.         normal pressure
                                                       intervals in the
                                                       well.
                                                      As a minimum, you
                                                       must cement the
                                                       annular space 500
                                                       feet above the
                                                       casing shoe and
                                                       500 feet above
                                                       each zone to be
                                                       isolated.
(e) Production..................  Design casing and   Use enough cement
                                   select setting      to cover or
                                   depth based on      isolate all
                                   anticipated or      hydrocarbon-
                                   encountered         bearing zones
                                   geologic            above the shoe.
                                   characteristics    As a minimum, you
                                   or wellbore         must cement the
                                   conditions.         annular space at
                                                       least 500 feet
                                                       above the casing
                                                       shoe and 500 feet
                                                       above the
                                                       uppermost
                                                       hydrocarbon-
                                                       bearing zone.

[[Page 345]]

 
(f) Liners......................  If you use a liner  Same as cementing
                                   as conductor or     requirements for
                                   surface casing,     specific casing
                                   you must set the    types. For
                                   top of the liner    example, a liner
                                   at least 200 feet   used as
                                   above the           intermediate
                                   previous casing/    casing must be
                                   liner shoe.         cemented
                                  If you use a liner   according to the
                                   as an               cementing
                                   intermediate        requirements for
                                   string below a      intermediate
                                   surface string or   casing.
                                   production casing
                                   below an
                                   intermediate
                                   string, you must
                                   set the top of
                                   the liner at
                                   least 100 feet
                                   above the
                                   previous casing
                                   shoe..
------------------------------------------------------------------------


[68 FR 8423, Feb. 20, 2003]



Sec. 250.422  When may I resume drilling after cementing?

    (a) After cementing surface, intermediate, or production casing (or 
liners), you may resume drilling after the cement has been held under 
pressure for 12 hours. For conductor casing, you may resume drilling 
after the cement has been held under pressure for 8 hours. One 
acceptable method of holding cement under pressure is to use float 
valves to hold the cement in place.
    (b) If you plan to nipple down your diverter or BOP stack during the 
8- or 12-hour waiting time, you must determine, before nippling down, 
when it will be safe to do so. You must base your determination on a 
knowledge of formation conditions, cement composition, effects of 
nippling down, presence of potential drilling hazards, well conditions 
during drilling, cementing, and post cementing, as well as past 
experience.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.423  What are the requirements for pressure testing casing?

    The table in this section describes the minimum test pressures for 
each string of casing. You may not resume drilling or other down-hole 
operations until you obtain a satisfactory pressure test. If the 
pressure declines more than 10 percent in a 30-minute test or if there 
is another indication of a leak, you must re-cement, repair the casing, 
or run additional casing to provide a proper seal. The District Manager 
may approve or require other casing test pressures.

------------------------------------------------------------------------
                Casing type                     Minimum test pressure
------------------------------------------------------------------------
(a) Drive or Structural...................  Not required
(b) Conductor.............................  200 psi
(c) Surface, Intermediate, and Production.  70 percent of its minimum
                                             internal yield
------------------------------------------------------------------------


[68 FR 8423, Feb. 20, 2003]



Sec. 250.424  What are the requirements for prolonged drilling operations?

    If wellbore operations continue for more than 30 days within a 
casing string run to the surface:
    (a) You must stop drilling operations as soon as practicable, and 
evaluate the effects of the prolonged operations on continued drilling 
operations and the life of the well. At a minimum, you must:
    (1) Caliper or pressure test the casing; and
    (2) Report the results of your evaluation to the District Manager 
and obtain approval of those results before resuming operations.
    (b) If casing integrity has deteriorated to a level below minimum 
safety factors, you must:
    (1) Repair the casing or run another casing string; and
    (2) Obtain approval from the District Manager before you begin 
repairs.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.425  What are the requirements for pressure testing liners?

    (a) You must test each drilling liner (and liner-lap) to a pressure 
at least equal to the anticipated pressure to which the liner will be 
subjected during the formation pressure-integrity test below that liner 
shoe, or subsequent liner shoes if set. The District Manager may approve 
or require other liner test pressures.
    (b) You must test each production liner (and liner-lap) to a minimum 
of 500 psi above the formation fracture

[[Page 346]]

pressure at the casing shoe into which the liner is lapped.
    (c) You may not resume drilling or other down-hole operations until 
you obtain a satisfactory pressure test. If the pressure declines more 
than 10 percent in a 30-minute test or if there is another indication of 
a leak, you must re-cement, repair the liner, or run additional casing/
liner to provide a proper seal.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.426  What are the recordkeeping requirements for casing and liner 

pressure tests?

    You must record the time, date, and results of each pressure test in 
the driller's report maintained under standard industry practice. In 
addition, you must record each test on a pressure chart and have your 
onsite representative sign and date the test as being correct.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.427  What are the requirements for pressure integrity tests?

    You must conduct a pressure integrity test below the surface casing 
or liner and all intermediate casings or liners. The District Manager 
may require you to run a pressure-integrity test at the conductor casing 
shoe if warranted by local geologic conditions or the planned casing 
setting depth. You must conduct each pressure integrity test after 
drilling at least 10 feet but no more than 50 feet of new hole below the 
casing shoe. You must test to either the formation leak-off pressure or 
to an equivalent drilling fluid weight if identified in an approved APD.
    (a) You must use the pressure integrity test and related hole-
behavior observations, such as pore-pressure test results, gas-cut 
drilling fluid, and well kicks to adjust the drilling fluid program and 
the setting depth of the next casing string. You must record all test 
results and hole-behavior observations made during the course of 
drilling related to formation integrity and pore pressure in the 
driller's report.
    (b) While drilling, you must maintain the safe drilling margin 
identified in the approved APD. When you cannot maintain this safe 
margin, you must suspend drilling operations and remedy the situation.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.428  What must I do in certain cementing and casing situations?

    The table in this section describes actions that lessees must take 
when certain situations occur during casing and cementing activities.

------------------------------------------------------------------------
 If you encounter the following
           situation:                       Then you must . . .
------------------------------------------------------------------------
(a) Have unexpected formation     Submit a revised casing program to the
 pressures or conditions that      District Manager for approval.
 warrant revising your casing
 design.
(b) Need to increase casing       Submit those changes to the District
 setting depths more than 100      Manager for approval.
 feet true vertical depth (TVD)
 from the approved APD due to
 conditions encountered during
 drilling operations.
(c) Have indication of            (1) Pressure test the casing shoe; (2)
 inadequate cement job (such as    Run a temperature survey; (3) Run a
 lost returns, cement              cement bond log; or (4) Use a
 channeling, or failure of         combination of these techniques.
 equipment).
(d) Inadequate cement job.......  Re-cement or take other remedial
                                   actions as approved by the District
                                   Manager.
(e) Primary cement job that did   Isolate those intervals from normal
 not isolate abnormal pressure     pressures by squeeze cementing before
 intervals.                        you complete; suspend operations; or
                                   abandon the well, whichever occurs
                                   first.
(f) Decide to produce a well      Have at least two cemented casing
 that was not originally           strings (does not include liners) in
 contemplated for production.      the well. Note: All producing wells
                                   must have at least two cemented
                                   casing strings.
(g) Want to drill a well without  Submit geologic data and information
 setting conductor casing.         to the District Manager that
                                   demonstrates the absence of shallow
                                   hydrocarbons or hazards. This
                                   information must include logging and
                                   drilling fluid-monitoring from wells
                                   previously drilled within 500 feet of
                                   the proposed well path down to the
                                   next casing point.
(h) Need to use less than         Submit information to the District
 required cement for the surface   Manager that demonstrates the use of
 casing during floating drilling   less cement is necessary.
 operations to provide
 protection from burst and
 collapse pressures.
(i) Cement across a permafrost    Use cement that sets before it freezes
 zone.                             and has a low heat of hydration.

[[Page 347]]

 
(j) Leave the annulus opposite a  Fill the annulus with a liquid that
 permafrost zone uncemented.       has a freezing point below the
                                   minimum permafrost temperature and
                                   minimizes opposite a corrosion.
------------------------------------------------------------------------


[68 FR 8423, Feb. 20, 2003]

                      Diverter System Requirements



Sec. 250.430  When must I install a diverter system?

    You must install a diverter system before you drill a conductor or 
surface hole. The diverter system consists of a diverter sealing 
element, diverter lines, and control systems. You must design, install, 
use, maintain, and test the diverter system to ensure proper diversion 
of gases, water, drilling fluid, and other materials away from 
facilities and personnel.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.431  What are the diverter design and installation requirements?

    You must design and install your diverter system to:
    (a) Use diverter spool outlets and diverter lines that have a 
nominal diameter of at least 10 inches for surface wellhead 
configurations and at least 12 inches for floating drilling operations;
    (b) Use dual diverter lines arranged to provide for downwind 
diversion capability;
    (c) Use at least two diverter control stations. One station must be 
on the drilling floor. The other station must be in a readily accessible 
location away from the drilling floor;
    (d) Use only remote-controlled valves in the diverter lines. All 
valves in the diverter system must be full-opening. You may not install 
manual or butterfly valves in any part of the diverter system;
    (e) Minimize the number of turns (only one 90-degree turn allowed 
for each line for bottom-founded drilling units) in the diverter lines, 
maximize the radius of curvature of turns, and target all right angles 
and sharp turns;
    (f) Anchor and support the entire diverter system to prevent 
whipping and vibration; and
    (g) Protect all diverter-control instruments and lines from possible 
damage by thrown or falling objects.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.432  How do I obtain a departure to diverter design and installation 

requirements?

    The table below describes possible departures from the diverter 
requirements and the conditions required for each departure. To obtain 
one of these departures, you must have discussed the departure in your 
APD and received approval from the District Manager.

------------------------------------------------------------------------
   If you want a departure to:               Then you must...
------------------------------------------------------------------------
(a) Use flexible hose for         Use flexible hose that has integral
 diverter lines instead of rigid   end couplings.
 pipe.
(b) Use only one spool outlet     (1) Have branch lines that meet the
 for your diverter system.         minimum internal diameter
                                   requirements; and (2) Provide
                                   downwind diversion capability.
(c) Use a spool with an outlet    Use a spool that has dual outlets with
 with an internal diameter of      an internal diameter of at least 8
 less than 10 inches on a          inches.
 surface wellhead.
(d) Use a single diverter line    Maintain an appropriate vessel heading
 for floating drilling             to provide for downwind diversion.
 operations on a dynamically
 positioned drillship.
------------------------------------------------------------------------


[68 FR 8423, Feb. 20, 2003]

[[Page 348]]



Sec. 250.433  What are the diverter actuation and testing requirements?

    When you install the diverter system, you must actuate the diverter 
sealing element, diverter valves, and diverter-control systems and 
control stations. You must also flow-test the vent lines.
    (a) For drilling operations with a surface wellhead configuration, 
you must actuate the diverter system at least once every 24-hour period 
after the initial test. After you have nippled up on conductor casing, 
you must pressure-test the diverter-sealing element and diverter valves 
to a minimum of 200 psi. While the diverter is installed, you must 
conduct subsequent pressure tests within 7 days after the previous test.
    (b) For floating drilling operations with a subsea BOP stack, you 
must actuate the diverter system within 7 days after the previous 
actuation.
    (c) You must alternate actuations and tests between control 
stations.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.434  What are the recordkeeping requirements for diverter actuations 

and tests?

    You must record the time, date, and results of all diverter 
actuations and tests in the driller's report. In addition, you must:
    (a) Record the diverter pressure test on a pressure chart;
    (b) Require your onsite representative to sign and date the pressure 
test chart;
    (c) Identify the control station used during the test or actuation;
    (d) Identify problems or irregularities observed during the testing 
or actuations and record actions taken to remedy the problems or 
irregularities; and
    (e) Retain all pressure charts and reports pertaining to the 
diverter tests and actuations at the facility for the duration of 
drilling the well.

[68 FR 8423, Feb. 20, 2003]

               Blowout Preventer (BOP) System Requirements



Sec. 250.440  What are the general requirements for BOP systems and system 

components?

    You must design, install, maintain, test, and use the BOP system and 
system components to ensure well control. The working-pressure rating of 
each BOP component must exceed maximum anticipated surface pressures. 
The BOP system includes the BOP stack and associated BOP systems and 
equipment.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.441  What are the requirements for a surface BOP stack?

    (a) When you drill with a surface BOP stack, you must install the 
BOP system before drilling below surface casing. The surface BOP stack 
must include at least four remote-controlled, hydraulically operated 
BOPs, consisting of an annular BOP, two BOPs equipped with pipe rams, 
and one BOP equipped with blind or blind-shear rams.
    (b) No later than February 21, 2006, your surface BOP stack must 
include at least four remote-controlled, hydraulically operated BOPs 
consisting of an annular BOP, two BOPs equipped with pipe rams, and one 
BOP equipped with blind-shear rams. The blind-shear rams must be capable 
of shearing the drill pipe that is in the hole.
    (c) You must install an accumulator system that provides 1.5 times 
the volume of fluid capacity necessary to close and hold closed all BOP 
components. The system must perform with a minimum pressure of 200 psi 
above the precharge pressure without assistance from a charging system. 
If you supply the accumulator regulators by rig air and do not have a 
secondary source of pneumatic supply, you must equip the regulators with 
manual overrides or other devices to ensure capability of hydraulic 
operations if rig air is lost.
    (d) In addition to the stack and accumulator system, you must 
install the associated BOP systems and equipment required by the 
regulations in this subpart.

[68 FR 8423, Feb. 20, 2003]

[[Page 349]]



Sec. 250.442  What are the requirements for a subsea BOP stack?

    (a) When you drill with a subsea BOP stack, you must install the BOP 
system before drilling below surface casing. The District Manager may 
require you to install a subsea BOP system before drilling below the 
conductor casing if proposed casing setting depths or local geology 
indicate the need.
    (b) Your subsea BOP stack must include at least four remote-
controlled, hydraulically operated BOPs consisting of an annular BOP, 
two BOPs equipped with pipe rams, and one BOP equipped with blind-shear 
rams.
    (c) You must install an accumulator closing system to provide fast 
closure of the BOP components and to operate all critical functions in 
case of a loss of the power fluid connection to the surface. The 
accumulator system must meet or exceed the provisions of Section 13.3, 
Accumulator Volumetric Capacity, in API RP 53, Recommended Practices for 
Blowout Prevention Equipment Systems for Drilling Wells (incorporated by 
reference as specified in Sec. 250.198). The District Manager may 
approve a suitable alternative method.
    (d) The BOP system must include an operable dual-pod control system 
to ensure proper and independent operation of the BOP system.
    (e) Before removing the marine riser, you must displace the riser 
with seawater. You must maintain sufficient hydrostatic pressure or take 
other suitable precautions to compensate for the reduction in pressure 
and to maintain a safe and controlled well condition.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.443  What associated systems and related equipment must all BOP 

systems include?

    All BOP systems must include the following associated systems and 
related equipment:
    (a) An automatic backup to the primary accumulator-charging system. 
The power source must be independent from the power source for the 
primary accumulator-charging system. The independent power source must 
possess sufficient capability to close and hold closed all BOP 
components.
    (b) At least two BOP control stations. One station must be on the 
drilling floor. You must locate the other station in a readily 
accessible location away from the drilling floor.
    (c) Side outlets on the BOP stack for separate kill and choke lines. 
If your stack does not have side outlets, you must install a drilling 
spool with side outlets.
    (d) A choke and a kill line on the BOP stack. You must equip each 
line with two full-opening valves, one of which must be remote-
controlled. For a subsea BOP system, both valves in each line must be 
remote-controlled. In addition:
    (1) You must install the choke line above the bottom ram;
    (2) You may install the kill line below the bottom ram; and
    (3) For a surface BOP system, on the kill line you may install a 
check valve and a manual valve instead of the remote-controlled valve. 
To use this configuration, both manual valves must be readily accessible 
and you must install the check valve between the manual valves and the 
pump.
    (e) A fill-up line above the uppermost BOP.
    (f) Locking devices installed on the ram-type BOPs.
    (g) A wellhead assembly with a rated working pressure that exceeds 
the maximum anticipated surface pressure.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.444  What are the choke manifold requirements?

    (a) Your BOP system must include a choke manifold that is suitable 
for the anticipated surface pressures, anticipated methods of well 
control, the surrounding environment, and the corrosiveness, volume, and 
abrasiveness of drilling fluids and well fluids that you may encounter.
    (b) Choke manifold components must have a rated working pressure at 
least as great as the rated working pressure of the ram BOPs. If your 
choke manifold has buffer tanks downstream of choke assemblies, you must 
install isolation valves on any bleed lines.
    (c) Valves, pipes, flexible steel hoses, and other fittings upstream 
of the choke manifold must have a rated working pressure at least as 
great as

[[Page 350]]

the rated working pressure of the ram BOPs.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.445  What are the requirements for kelly valves, inside BOPs, and 

drill-string safety valves?

    You must use or provide the following BOP equipment during drilling 
operations:
    (a) A kelly valve installed below the swivel (upper kelly valve);
    (b) A kelly valve installed at the bottom of the kelly (lower kelly 
valve). You must be able to strip the lower kelly valve through the BOP 
stack;
    (c) If you drill with a mud motor and use drill pipe instead of a 
kelly, you must install one kelly valve above, and one strippable kelly 
valve below, the joint of drill pipe used in place of a kelly;
    (d) On a top-drive system equipped with a remote-controlled valve, 
you must install a strippable kelly-type valve below the remote-
controlled valve;
    (e) An inside BOP in the open position located on the rig floor. You 
must be able to install an inside BOP for each size connection in the 
drill string;
    (f) A drill-string safety valve in the open position located on the 
rig floor. You must have a drill-string safety valve available for each 
size connection in the drill string;
    (g) When running casing, you must have a safety valve in the open 
position available on the rig floor to fit the casing string being run 
in the hole;
    (h) All required manual and remote-controlled kelly valves, drill-
string safety valves, and comparable-type valves (i.e. kelly-type valve 
in a top-drive system) must be essentially full-opening; and
    (i) The drilling crew must have ready access to a wrench to fit each 
manual valve.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.446  What are the BOP maintenance and inspection requirements?

    (a) You must maintain your BOP system to ensure that the equipment 
functions properly. BOP maintenance must meet or exceed the provisions 
of Sections 17.10 and 18.10, Inspections; Sections 17.11 and 18.11, 
Maintenance; and Sections 17.12 and 18.12, Quality Management, described 
in API RP 53, Recommended Practices for Blowout Prevention Equipment 
Systems for Drilling Wells (incorporated by reference as specified in 
Sec. 250.198).
    (b) You must visually inspect your surface BOP system on a daily 
basis. You must visually inspect your subsea BOP system and marine riser 
at least once every 3 days if weather and sea conditions permit. You may 
use television cameras to inspect subsea equipment.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.447  When must I pressure test the BOP system?

    You must pressure test your BOP system (this includes the choke 
manifold, kelly valves, inside BOP, and drill-string safety valve):
    (a) When installed;
    (b) Before 14 days have elapsed since your last BOP pressure test. 
You must begin to test your BOP system before midnight on the 14th day 
following the conclusion of the previous test. However, the District 
Manager may require more frequent testing if conditions or BOP 
performance warrant; and
    (c) Before drilling out each string of casing or a liner. The 
District Manager may allow you to omit this test if you didn't remove 
the BOP stack to run the casing string or liner and the required BOP 
test pressures for the next section of the hole are not greater than the 
test pressures for the previous BOP test. You must indicate in your APD 
which casing strings and liners meet these criteria.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.448  What are the BOP pressure tests requirements?

    When you pressure test the BOP system, you must conduct a low-
pressure and a high-pressure test for each BOP component. You must 
conduct the low-pressure test before the high-pressure test. Each 
individual pressure test must hold pressure long enough to demonstrate 
that the tested component(s) holds the required pressure. Required test 
pressures are as follows:

[[Page 351]]

    (a) Low-pressure test. All low-pressure tests must be between 200 
and 300 psi. Any initial pressure above 300 psi must be bled back to a 
pressure between 200 and 300 psi before starting the test. If the 
initial pressure exceeds 500 psi, you must bleed back to zero and 
reinitiate the test.
    (b) High-pressure test for ram-type BOPs, the choke manifold, and 
other BOP components. The high-pressure test must equal the rated 
working pressure of the equipment or be 500 psi greater than your 
calculated maximum anticipated surface pressure (MASP) for the 
applicable section of hole. Before you may test BOP equipment to the 
MASP plus 500 psi, the District Manager must have approved those test 
pressures in your APD.
    (c) High pressure test for annular-type BOPs. The high pressure test 
must equal 70 percent of the rated working pressure of the equipment or 
to a pressure approved in your APD.
    (d) Duration of pressure test. Each test must hold the required 
pressure for 5 minutes. However, for surface BOP systems and surface 
equipment of a subsea BOP system, a 3-minute test duration is acceptable 
if you record your test pressures on the outermost half of a 4-hour 
chart, on a 1-hour chart, or on a digital recorder. If the equipment 
does not hold the required pressure during a test, you must correct the 
problem and retest the affected component(s).

[68 FR 8423, Feb. 20, 2003]



Sec. 250.449  What additional BOP testing requirements must I meet?

    You must meet the following additional BOP testing requirements:
    (a) Use water to test a surface BOP system;
    (b) Stump test a subsea BOP system before installation. You must use 
water to conduct this test. You may use drilling fluids to conduct 
subsequent tests of a subsea BOP system;
    (c) Alternate tests between control stations and pods;
    (d) Pressure test the blind or blind-shear ram BOP during stump 
tests and at all casing points;
    (e) The interval between any blind or blind-shear ram BOP pressure 
tests may not exceed 30 days;
    (f) Pressure test variable bore-pipe ram BOPs against the largest 
and smallest sizes of pipe in use, excluding drill collars and bottom-
hole tools;
    (g) Pressure test affected BOP components following the 
disconnection or repair of any well-pressure containment seal in the 
wellhead or BOP stack assembly;
    (h) Function test annular and ram BOPs every 7 days between pressure 
tests; and
    (i) Actuate safety valves assembled with proper casing connections 
before running casing.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.450  What are the recordkeeping requirements for BOP tests?

    You must record the time, date, and results of all pressure tests, 
actuations, and inspections of the BOP system, system components, and 
marine riser in the driller's report. In addition, you must:
    (a) Record BOP test pressures on pressure charts;
    (b) Require your onsite representative to sign and date BOP test 
charts and reports as correct;
    (c) Document the sequential order of BOP and auxiliary equipment 
testing and the pressure and duration of each test. For subsea BOP 
systems, you must also record the closing times for annular and ram 
BOPs. You may reference a BOP test plan if it is available at the 
facility;
    (d) Identify the control station and pod used during the test;
    (e) Identify any problems or irregularities observed during BOP 
system testing and record actions taken to remedy the problems or 
irregularities; and
    (f) Retain all records, including pressure charts, driller's report, 
and referenced documents pertaining to BOP tests, actuations, and 
inspections at the facility for the duration of drilling.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.451  What must I do in certain situations involving BOP equipment or 

systems?

    The table in this section describes actions that lessees must take 
when certain situations occur with BOP systems during drilling 
activities.

[[Page 352]]



------------------------------------------------------------------------
 If you encounter the following situation:       Then you must . . .
------------------------------------------------------------------------
(a) BOP equipment does not hold the         Correct the problem and
 required pressure during a test.            retest the affected
                                             equipment.
(b) Need to repair or replace a surface or  First place the well in a
 subsea BOP system.                          safe, controlled condition
                                             (e.g., before drilling out
                                             a casing shoe or after
                                             setting a cement plug,
                                             bridge plug, or a packer).
(c) Need to postpone a BOP test due to      Record the reason for
 well-control problems such as lost          postponing the test in the
 circulation, formation fluid influx, or     driller's report and
 stuck drill pipe.                           conduct the required BOP
                                             test on the first trip out
                                             of the hole.
(d) BOP control station or pod that does    Suspend further drilling
 not function properly.                      operations until that
                                             station or pod is operable.
(e) Want to drill with a tapered drill-     Install two or more sets of
 string.                                     conventional or variable-
                                             bore pipe rams in the BOP
                                             stack to provide for the
                                             following: two sets of rams
                                             must be capable of sealing
                                             around the larger-size
                                             drill string and one set of
                                             pipe rams must be capable
                                             of sealing around the
                                             smaller-size drill string.
(f) Install casing rams in a BOP stack....  Test the ram bonnets before
                                             running casing.
(g) Want to use an annular BOP with a       Demonstrate that your well
 rated working pressure less than the        control procedures or the
 anticipated surface pressure.               anticipated well conditions
                                             will not place demands
                                             above its rated working
                                             pressure and obtain
                                             approval from the District
                                             Manager.
(h) Use a subsea BOP system in an ice-      Install the BOP stack in a
 scour area.                                 glory hole. The glory hole
                                             must be deep enough to
                                             ensure that the top of the
                                             stack is below the deepest
                                             probable ice-scour depth.
------------------------------------------------------------------------


[68 FR 8423, Feb. 20, 2003]

                       Drilling Fluid Requirements



Sec. 250.455  What are the general requirements for a drilling fluid program?

    You must design and implement your drilling fluid program to prevent 
the loss of well control. This program must address drilling fluid safe 
practices, testing and monitoring equipment, drilling fluid quantities, 
and drilling fluid-handling areas.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.456  What safe practices must the drilling fluid program follow?

    Your drilling fluid program must include the following safe 
practices:
    (a) Before starting out of the hole with drill pipe, you must 
properly condition the drilling fluid. You must circulate a volume of 
drilling fluid equal to the annular volume with the drill pipe just off-
bottom. You may omit this practice if documentation in the driller's 
report shows:
    (1) No indication of formation fluid influx before starting to pull 
the drill pipe from the hole;
    (2) The weight of returning drilling fluid is within 0.2 pounds per 
gallon (1.5 pounds per cubic foot) of the drilling fluid entering the 
hole; and
    (3) Other drilling fluid properties are within the limits 
established by the program approved in the APD.
    (b) Record each time you circulate drilling fluid in the hole in the 
driller's report;
    (c) When coming out of the hole with drill pipe, you must fill the 
annulus with drilling fluid before the hydrostatic pressure decreases by 
75 psi, or every five stands of drill pipe, whichever gives a lower 
decrease in hydrostatic pressure. You must calculate the number of 
stands of drill pipe and drill collars that you may pull before you must 
fill the hole. You must also calculate the equivalent drilling fluid 
volume needed to fill the hole. Both sets of numbers must be posted near 
the driller's station. You must use a mechanical, volumetric, or 
electronic device to measure the drilling fluid required to fill the 
hole;
    (d) You must run and pull drill pipe and downhole tools at 
controlled rates so you do not swab or surge the well;
    (e) When there is an indication of swabbing or influx of formation 
fluids, you must take appropriate measures to control the well. You must 
circulate and condition the well, on or near-bottom, unless well or 
drilling-fluid conditions prevent running the drill pipe back to the 
bottom;
    (f) You must calculate and post near the driller's console the 
maximum pressures that you may safely contain under a shut-in BOP for 
each casing string. The pressures posted must consider the surface 
pressure at which the formation at the shoe would break down, the rated 
working pressure of the BOP stack, and 70 percent of casing burst (or 
casing test as approved by the District Manager). As a minimum, you must 
post the following two pressures:

[[Page 353]]

    (1) The surface pressure at which the shoe would break down. This 
calculation must consider the current drilling fluid weight in the hole; 
and
    (2) The lesser of the BOP's rated working pressure or 70 percent of 
casing-burst pressure (or casing test otherwise approved by the District 
Manager);
    (g) You must install an operable drilling fluid-gas separator and 
degasser before you begin drilling operations. You must maintain this 
equipment throughout the drilling of the well;
    (h) Before pulling drill-stem test tools from the hole, you must 
circulate or reverse-circulate the test fluids in the hole. If 
circulating out test fluids is not feasible, you may bullhead test 
fluids out of the drill-stem test string and tools with an appropriate 
kill weight fluid;
    (i) When circulating, you must test the drilling fluid at least once 
each tour, or more frequently if conditions warrant. Your tests must 
conform to industry-accepted practices and include density, viscosity, 
and gel strength; hydrogenion concentration; filtration; and any other 
tests the District Manager requires for monitoring and maintaining 
drilling fluid quality, prevention of downhole equipment problems and 
for kick detection. You must record the results of these tests in the 
drilling fluid report; and
    (j) In areas where permafrost and/or hydrate zones are present or 
may be present, you must control drilling fluid temperatures to drill 
safely through those zones.

[68 FR 8423, Feb. 20, 2003; 68 FR 14274, Mar. 24, 2003]



Sec. 250.457  What equipment is required to monitor drilling fluids?

    Once you establish drilling fluid returns, you must install and 
maintain the following drilling fluid-system monitoring equipment 
throughout subsequent drilling operations. This equipment must have the 
following indicators on the rig floor:
    (a) Pit level indicator to determine drilling fluid-pit volume gains 
and losses. This indicator must include both a visual and an audible 
warning device;
    (b) Volume measuring device to accurately determine drilling fluid 
volumes required to fill the hole on trips;
    (c) Return indicator devices that indicate the relationship between 
drilling fluid-return flow rate and pump discharge rate. This indicator 
must include both a visual and an audible warning device; and
    (d) Gas-detecting equipment to monitor the drilling fluid returns. 
The indicator may be located in the drilling fluid-logging compartment 
or on the rig floor. If the indicators are only in the logging 
compartment, you must continually man the equipment and have a means of 
immediate communication with the rig floor. If the indicators are on the 
rig floor only, you must install an audible alarm.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.458  What quantities of drilling fluids are required?

    (a) You must use, maintain, and replenish quantities of drilling 
fluid and drilling fluid materials at the drill site as necessary to 
ensure well control. You must determine those quantities based on known 
or anticipated drilling conditions, rig storage capacity, weather 
conditions, and estimated time for delivery.
    (b) You must record the daily inventories of drilling fluid and 
drilling fluid materials, including weight materials and additives in 
the drilling fluid report.
    (c) If you do not have sufficient quantities of drilling fluid and 
drilling fluid material to maintain well control, you must suspend 
drilling operations.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.459  What are the safety requirements for drilling fluid-handling 

areas?

    You must classify drilling fluid-handling areas according to API RP 
500, Recommended Practice for Classification of Locations for Electrical 
Installations at Petroleum Facilities, Classified as Class I, Division 1 
and Division 2 (incorporated by reference as specified in Sec. 
250.198); or API RP 505, Recommended Practice for Classification

[[Page 354]]

of Locations for Electrical Installations at Petroleum Facilities, 
Classified as Class 1, Zone 0, Zone 1, and Zone 2 (incorporated by 
reference as specified in Sec. 250.198). In areas where dangerous 
concentrations of combustible gas may accumulate, you must install and 
maintain a ventilation system and gas monitors. Drilling fluid-handling 
areas must have the following safety equipment:
    (a) A ventilation system capable of replacing the air once every 5 
minutes or 1.0 cubic feet of air-volume flow per minute, per square foot 
of area, whichever is greater. In addition:
    (1) If natural means provide adequate ventilation, then a mechanical 
ventilation system is not necessary;
    (2) If a mechanical system does not run continuously, then it must 
activate when gas detectors indicate the presence of 1 percent or more 
of combustible gas by volume; and
    (3) If discharges from a mechanical ventilation system may be 
hazardous, then you must maintain the drilling fluid-handling area at a 
negative pressure. You must protect the negative pressure area by using 
at least one of the following: a pressure-sensitive alarm, open-door 
alarms on each access to the area, automatic door-closing devices, air 
locks, or other devices approved by the District Manager;
    (b) Gas detectors and alarms except in open areas where adequate 
ventilation is provided by natural means. You must test and recalibrate 
gas detectors quarterly. No more than 90 days may elapse between tests;
    (c) Explosion-proof or pressurized electrical equipment to prevent 
the ignition of explosive gases. Where you use air for pressuring 
equipment, you must locate the air intake outside of and as far as 
practicable from hazardous areas; and
    (d) Alarms that activate when the mechanical ventilation system 
fails.

[68 FR 8423, Feb. 20, 2003]

                       Other Drilling Requirements



Sec. 250.460  What are the requirements for conducting a well test?

    (a) If you intend to conduct a well test, you must include your 
projected plans for the test with your APD (form MMS-123) or in an 
Application for Permit to Modify (APM) (form MMS-124). Your plans must 
include at least the following information:
    (1) Estimated flowing and shut-in tubing pressures;
    (2) Estimated flow rates and cumulative volumes;
    (3) Time duration of flow, buildup, and drawdown periods;
    (4) Description and rating of surface and subsurface test equipment;
    (5) Schematic drawing, showing the layout of test equipment;
    (6) Description of safety equipment, including gas detectors and 
fire-fighting equipment;
    (7) Proposed methods to handle or transport produced fluids; and
    (8) Description of the test procedures.
    (b) You must give the District Manager at least 24-hours notice 
before starting a well test.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.461  What are the requirements for directional and inclination 

surveys?

    For this subpart, MMS classifies a well as vertical if the 
calculated average of inclination readings does not exceed 3 degrees 
from the vertical.
    (a) Survey requirements for a vertical well. (1) You must conduct 
inclination surveys on each vertical well and record the results. Survey 
intervals may not exceed 1,000 feet during the normal course of 
drilling;
    (2) You must also conduct a directional survey that provides both 
inclination and azimuth, and digitally record the results in electronic 
format:
    (i) Within 500 feet of setting surface or intermediate casing;
    (ii) Within 500 feet of setting any liner; and
    (iii) When you reach total depth.
    (b) Survey requirements for directional well. You must conduct 
directional surveys on each directional well and digitally record the 
results. Surveys must give both inclination and azimuth at intervals not 
to exceed 500 feet during the normal course of drilling. Intervals 
during angle-changing portions of the hole may not exceed 100 feet.
    (c) Measurement while drilling. You may use measurement-while-
drilling

[[Page 355]]

technology if it meets the requirements of this section.
    (d) Composite survey requirements. (1) Your composite directional 
survey must show the interval from the bottom of the conductor casing to 
total depth. In the absence of conductor casing, the survey must show 
the interval from the bottom of the drive or structural casing to total 
depth; and
    (2) You must correct all surveys to Universal-Transverse-Mercator-
Grid-north or Lambert-Grid-north after making the magnetic-to-true-north 
correction. Surveys must show the magnetic and grid corrections used and 
include a listing of the directionally computed inclinations and 
azimuths.
    (e) If you drill within 500 feet of an adjacent lease, the Regional 
Supervisor may require you to furnish a copy of the well's directional 
survey to the affected leaseholder. This could occur when the adjoining 
leaseholder requests a copy of the survey for the protection of 
correlative rights.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.462  What are the requirements for well-control drills?

    You must conduct a weekly well-control drill with each drilling 
crew. Your drill must familiarize the crew with its roles and functions 
so that all crew members can perform their duties promptly and 
efficiently.
    (a) Well-control drill plan. You must prepare a well control drill 
plan for each well. Your plan must outline the assignments for each crew 
member and establish times to complete each portion of the drill. You 
must post a copy of the well control drill plan on the rig floor or 
bulletin board.
    (b) Timing of drills. You must conduct each drill during a period of 
activity that minimizes the risk to drilling operations. The timing of 
your drills must cover a range of different operations, including 
drilling with a diverter, on-bottom drilling, and tripping.
    (c) Recordkeeping requirements. For each drill, you must record the 
following in the driller's report:
    (1) The time to be ready to close the diverter or BOP system; and
    (2) The total time to complete the entire drill.
    (d) MMS ordered drill. An MMS authorized representative may require 
you to conduct a well control drill during an MMS inspection. The MMS 
representative will consult with your onsite representative before 
requiring the drill.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.463  Who establishes field drilling rules?

    (a) The District Manager may establish field drilling rules 
different from the requirements of this subpart when geological and 
engineering information shows that specific operating requirements are 
appropriate. You must comply with field drilling rules and 
nonconflicting requirements of this subpart. The District Manager may 
amend or cancel field drilling rules at any time.
    (b) You may request the District Manager to establish, amend, or 
cancel field drilling rules.

[68 FR 8423, Feb. 20, 2003]

            Applying for a Permit To Modify and Well Records



Sec. 250.465  When must I submit an Application for Permit to Modify (APM) or 

an End of Operations Report to MMS?

    (a) You must submit an APM (form MMS-124) or an End of Operations 
Report (form MMS-125) and other materials to the Regional Supervisor as 
shown in the following table. You must also submit a public information 
copy of each form.

------------------------------------------------------------------------
           When you               Then you must             And
------------------------------------------------------------------------
(1) Intend to revise your       Submit form MMS-   Receive written or
 drilling plan, change major     124 or request     oral approval from
 drilling equipment, or          oral approval.     the District Manager
 plugback.                                          before you begin the
                                                    intended operation.
                                                    If you get an
                                                    approval, you must
                                                    submit form MMS-124
                                                    no later than the
                                                    end of the 3rd
                                                    business day
                                                    following the oral
                                                    approval. In all
                                                    cases, or you must
                                                    meet the additional
                                                    requirements in
                                                    paragraph (b) of
                                                    this section.

[[Page 356]]

 
(2) Determine a well's final    Immediately        Submit a plat
 surface location, water         Submit a form      certified by a
 depth, and the rotary kelly     MMS-124.           registered land
 bushing elevation.                                 surveyor that meets
                                                    the requirements of
                                                    Sec.  250.412.
(3) Move a drilling unit from   Submit forms MMS-  Submit appropriate
 a wellbore before completing    124 and MMS-125    copies of the well
 a well.                         within 30 days     records.
                                 after the
                                 suspension of
                                 wellbore
                                 operations.
------------------------------------------------------------------------

    (b) If you intend to perform any of the actions specified in 
paragraph (a)(1) of this section, you must meet the following additional 
requirements:
    (1) Your APM (Form MMS-124) must contain a detailed statement of the 
proposed work that would materially change from the approved APD. The 
submission of your APM must be accompanied by payment of the service fee 
listed in Sec. 250.125;
    (2) Your form MMS-124 must include the present status of the well, 
depth of all casing strings set to date, well depth, present production 
zones and productive capability, and all other information specified; 
and
    (3) Within 30 days after completing this work, you must submit form 
MMS-124 with detailed information about the work to the District 
Manager, unless you have already provided sufficient information in a 
Well Activity Report, form MMS-133 (Sec. 250.468(b)).

[68 FR 8423, Feb. 20, 2003, as amended at 71 FR 40911, July 19, 2006]



Sec. 250.466  What records must I keep?

    You must keep complete, legible, and accurate records for each well. 
You must keep drilling records onsite while drilling activities 
continue. After completion of drilling activities, you must keep all 
drilling and other well records for the time periods shown in Sec. 
250.467. You may keep these records at a location of your choice. The 
records must contain complete information on all of the following:
    (a) Well operations;
    (b) Descriptions of formations penetrated;
    (c) Content and character of oil, gas, water, and other mineral 
deposits in each formation;
    (d) Kind, weight, size, grade, and setting depth of casing;
    (e) All well logs and surveys run in the wellbore;
    (f) Any significant malfunction or problem; and
    (g) All other information required by the District Manager in the 
interests of resource evaluation, waste prevention, conservation of 
natural resources, and the protection of correlative rights, safety, and 
environment.

[68 FR 8423, Feb. 20, 2003, as amended at 72 FR 25201, May 4, 2007]



Sec. 250.467  How long must I keep records?

    You must keep records for the time periods shown in the following 
table.

------------------------------------------------------------------------
   You must keep records relating to                  Until
------------------------------------------------------------------------
(a) Drilling...........................  Ninety days after you complete
                                          drilling operations.
(b) Casing and liner pressure tests,     Two years after the completion
 diverter tests, and BOP tests.           of drilling operations.
(c) Completion of a well or of any       You permanently plug and
 workover activity that materially        abandon the well or until you
 alters the completion configuration or   forward the records with a
 affects a hydrocarbon-bearing zone.      lease assignment.
------------------------------------------------------------------------


[68 FR 8423, Feb. 20, 2003]

[[Page 357]]



Sec. 250.468  What well records am I required to submit?

    (a) You must submit copies of logs or charts of electrical, 
radioactive, sonic, and other well-logging operations; directional and 
vertical-well surveys; velocity profiles and surveys; and analysis of 
cores to MMS. Each Region will provide specific instructions for 
submitting well logs and surveys.
    (b) For drilling operations in the GOM OCS Region, you must submit 
form MMS-133, Well Activity Report, to the District Manager on a weekly 
basis.
    (c) For drilling operations in the Pacific or Alaska OCS Regions, 
you must submit form MMS-133, Well Activity Report, to the District 
Manager on a daily basis.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.469  What other well records could I be required to submit?

    The District Manager or Regional Supervisor may require you to 
submit copies of any or all of the following well records.
    (a) Well records as specified in Sec. 250.466;
    (b) Paleontological interpretations or reports identifying 
microscopic fossils by depth and/or washed samples of drill cuttings 
that you normally maintain for paleontological determinations. The 
Regional Supervisor may issue a Notice to Lessees that prescribes the 
manner, timeframe, and format for submitting this information;
    (c) Service company reports on cementing, perforating, acidizing, 
testing, or other similar services; or
    (d) Other reports and records of operations.

[68 FR 8423, Feb. 20, 2003]

                            Hydrogen Sulfide



Sec. 250.490  Hydrogen sulfide.

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

[[Page 358]]

    (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 Manager for approval. Do not begin 
operations before the District Manager approves your plan. You must keep 
a copy of the approved plan in the field, and you must follow the plan 
at all times. Your plan must include:
    (1) Safety procedures and rules that you will follow concerning 
equipment, drills, and smoking;
    (2) Training you provide for employees, contractors, and visitors;
    (3) Job position and title of the person responsible for the overall 
safety of personnel;
    (4) Other key positions, how these positions fit into your 
organization, and what the functions, duties, and responsibilities of 
those job positions are;
    (5) Actions that you will take when the concentration of 
H2S in the atmosphere reaches 20 ppm, who will be responsible 
for those actions, and a description of the audible and visual alarms to 
be activated;
    (6) Briefing areas where personnel will assemble during an 
H2S alert. You must have at least two briefing areas on each 
facility and use the briefing area that is upwind of the H2S 
source at any given time;
    (7) Criteria you will use to decide when to evacuate the facility 
and procedures you will use to safely evacuate all personnel from the 
facility by vessel, capsule, or lifeboat. If you use helicopters during 
H2S alerts, describe the types of H2S emergencies 
during which you consider the risk of helicopter activity to be 
acceptable and the precautions you will take during the flights;
    (8) Procedures you will use to safely position all vessels attendant 
to the facility. Indicate where you will locate the vessels with respect 
to wind direction. Include the distance from the facility and what 
procedures you will use to safely relocate the vessels in an emergency;
    (9) How you will provide protective-breathing equipment for all 
personnel, including contractors and visitors;
    (10) The agencies and facilities you will notify in case of a 
release of H2S (that constitutes an emergency), how you will 
notify them, and their telephone numbers. Include all facilities that 
might be exposed to atmospheric concentrations of 20 ppm or more of 
H2S;
    (11) The medical personnel and facilities you will use if needed, 
their addresses, and telephone numbers;
    (12) H2S detector locations in production facilities 
producing gas containing 20 ppm or more of H2S. Include an 
``H2S Detector Location Drawing'' showing:
    (i) All vessels, flare outlets, wellheads, and other equipment 
handling production containing H2S;
    (ii) Approximate maximum concentration of H2S in the gas 
stream; and
    (iii) Location of all H2S sensors included in your 
contingency plan;
    (13) Operational conditions when you expect to flare gas containing 
H2S including the estimated maximum gas flow rate, 
H2S concentration, and duration of flaring;
    (14) Your assessment of the risks to personnel during flaring and 
what precautionary measures you will take;
    (15) Primary and alternate methods to ignite the flare and 
procedures for sustaining ignition and monitoring the status of the 
flare (i.e., ignited or extinguished);
    (16) Procedures to shut off the gas to the flare in the event the 
flare is extinguished;
    (17) Portable or fixed sulphur dioxide (SO2)-detection 
system(s) you will use

[[Page 359]]

to determine SO2 concentration and exposure hazard when 
H2S is burned;
    (18) Increased monitoring and warning procedures you will take when 
the SO2 concentration in the atmosphere reaches 2 ppm;
    (19) Personnel protection measures or evacuation procedures you will 
initiate when the SO2 concentration in the atmosphere reaches 
5 ppm;
    (20) Engineering controls to protect personnel from SO2; 
and
    (21) Any special equipment, procedures, or precautions you will use 
if you conduct any combination of drilling, well-completion, well-
workover, and production operations simultaneously.
    (g) Training program--(1) When and how often do employees need to be 
trained? All operators and contract personnel must complete an 
H2S training program to meet the requirements of this 
section:
    (i) Before beginning work at the facility; and
    (ii) Each year, within 1 year after completion of the previous 
class.
    (2) What training documentation do I need? For each individual 
working on the platform, either:
    (i) You must have documentation of this training at the facility 
where the individual is employed; or
    (ii) The employee must carry a training completion card.
    (3) What training do I need to give to visitors and employees 
previously trained on another facility?--(i) Trained employees or 
contractors transferred from another facility must attend a supplemental 
briefing on your H2S equipment and procedures before 
beginning duty at your facility;
    (ii) Visitors who will remain on your facility more than 24 hours 
must receive the training required for employees by paragraph (g)(4) of 
this section; and
    (iii) Visitors who will depart before spending 24 hours on the 
facility are exempt from the training required for employees, but they 
must, upon arrival, complete a briefing that includes:
    (A) Information on the location and use of an assigned respirator; 
practice in donning and adjusting the assigned respirator; information 
on the safe briefing areas, alarm system, and hazards of H2S 
and SO2; and
    (B) Instructions on their responsibilities in the event of an 
H2S release.
    (4) What training must I provide to all other employees? You must 
train all individuals on your facility on the:
    (i) Hazards of H2S and of SO2 and the 
provisions for personnel safety contained in the H2S 
Contingency Plan;
    (ii) Proper use of safety equipment which the employee may be 
required to use;
    (iii) Location of protective breathing equipment, H2S 
detectors and alarms, ventilation equipment, briefing areas, warning 
systems, evacuation procedures, and the direction of prevailing winds;
    (iv) Restrictions and corrective measures concerning beards, 
spectacles, and contact lenses in conformance with ANSI Z88.2, American 
National Standard for Respiratory Protection (incorporated by reference 
as specified in Sec. 250.198);
    (v) Basic first-aid procedures applicable to victims of 
H2S exposure. During all drills and training sessions, you 
must address procedures for rescue and first aid for H2S 
victims;
    (vi) Location of:
    (A) The first-aid kit on the facility;
    (B) Resuscitators; and
    (C) Litter or other device on the facility.
    (vii) Meaning of all warning signals.
    (5) Do I need to post safety information? You must prominently post 
safety information on the facility and on vessels serving the facility 
(i.e., basic first-aid, escape routes, instructions for use of life 
boats, etc.).
    (h) Drills. (1) When and how often do I need to conduct drills on 
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:

[[Page 360]]

    (i) Drilling, well-completion, and well-workover operations at the 
facility until operations are completed; and
    (ii) Production operations at the facility or at the nearest field 
office for 1 year.
    (i) Visual and audible warning systems--(1) How must I install wind 
direction equipment? You must install wind-direction equipment in a 
location visible at all times to individuals on or in the immediate 
vicinity of the facility.
    (2) When do I need to display operational danger signs, display 
flags, or activate visual or audible alarms?--(i) You must display 
warning signs at all times on facilities with wells capable of producing 
H2S and on facilities that process gas containing 
H2S in concentrations of 20 ppm or more.
    (ii) In addition to the signs, you must activate audible alarms and 
display flags or activate flashing red lights when atmospheric 
concentration of H2S reaches 20 ppm.
    (3) What are the requirements for signs? Each sign must be a high-
visibility yellow color with black lettering as follows:

------------------------------------------------------------------------
               Letter height                           Wording
------------------------------------------------------------------------
12 inches.................................  Danger.
                                            Poisonous Gas.
                                            Hydrogen Sulfide.
7 inches..................................  Do not approach if red flag
                                             is flying.
(Use appropriate wording at right)........  Do not approach if red
                                             lights are flashing.
------------------------------------------------------------------------

    (4) May I use existing signs? You may use existing signs containing 
the words ``Danger-Hydrogen Sulfide-H2S,'' provided the words 
``Poisonous Gas. Do Not Approach if Red Flag is Flying'' or ``Red Lights 
are Flashing'' in lettering of a minimum of 7 inches in height are 
displayed on a sign immediately adjacent to the existing sign.
    (5) What are the requirements for flashing lights or flags? You must 
activate a sufficient number of lights or hoist a sufficient number of 
flags to be visible to vessels and aircraft. Each light must be of 
sufficient intensity to be seen by approaching vessels or aircraft any 
time it is activated (day or night). Each flag must be red, rectangular, 
a minimum width of 3 feet, and a minimum height of 2 feet.
    (6) What is an audible warning system? An audible warning system is 
a public address system or siren, horn, or other similar warning device 
with a unique sound used only for H2S.
    (7) Are there any other requirements for visual or audible warning 
devices? Yes, you must:
    (i) Illuminate all signs and flags at night and under conditions of 
poor visibility; and
    (ii) Use warning devices that are suitable for the electrical 
classification of the area.
    (8) What actions must I take when the alarms are activated? When the 
warning devices are activated, the designated responsible persons must 
inform personnel of the level of danger and issue instructions on the 
initiation of appropriate protective measures.
    (j) 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 Manager may require mud 
sensors in the possum belly in cases where the ambient air sensors in 
the mud-return system do not consistently detect the presence of 
H2S.
    (4) How often must I observe the sensors? During drilling, well-
completion and well-workover operations, you must continuously observe 
the H2S levels indicated by the monitors in the work areas 
during the following operations:
    (i) When you pull a wet string of drill pipe or workover string;

[[Page 361]]

    (ii) When circulating bottoms-up after a drilling break;
    (iii) During cementing operations;
    (iv) During logging operations; and
    (v) When circulating to condition mud or other well-control fluid.
    (5) Where must I have sensors for production operations? On a 
platform where gas containing H2S of 20 ppm or greater is 
produced, processed, or otherwise handled:
    (i) You must have a sensor in rooms, buildings, deck areas, or low-
laying deck areas not otherwise covered by paragraph (j)(2) of this 
section, where atmospheric concentrations of H2S could reach 
20 ppm or more. You must have at least one sensor per 400 square feet of 
deck area or fractional part of 400 square feet;
    (ii) You must have a sensor in buildings where personnel have their 
living quarters;
    (iii) You must have a sensor within 10 feet of each vessel, 
compressor, wellhead, manifold, or pump, which could release enough 
H2S to result in atmospheric concentrations of 20 ppm at a 
distance of 10 feet from the component;
    (iv) You may use one sensor to detect H2S around multiple 
pieces of equipment, provided the sensor is located no more than 10 feet 
from each piece, except that you need to use at least two sensors to 
monitor compressors exceeding 50 horsepower;
    (v) You do not need to have sensors near wells that are shut in at 
the master valve and sealed closed;
    (vi) When you determine where to place sensors, you must consider:
    (A) The location of system fittings, flanges, valves, and other 
devices subject to leaks to the atmosphere; and
    (B) Design factors, such as the type of decking and the location of 
fire walls; and
    (vii) The District Manager may require additional sensors or other 
monitoring capabilities, if warranted by site specific conditions.
    (6) How must I functionally test the H2S Detectors?--(i) 
Personnel trained to calibrate the particular H2S detector 
equipment being used must test detectors by exposing them to a known 
concentration in the range of 10 to 30 ppm of H2S.
    (ii) If the results of any functional test are not within 2 ppm or 
10 percent, whichever is greater, of the applied concentration, 
recalibrate the instrument.
    (7) How often must I test my detectors?--(i) When conducting 
drilling, drill stem testing, well-completion, or well-workover 
operations in areas classified as H2S present or 
H2S unknown, test all detectors at least once every 24 hours. 
When drilling, begin functional testing before the bit is 1,500 feet 
(vertically) above the potential H2S zone.
    (ii) When conducting production operations, test all detectors at 
least every 14 days between tests.
    (iii) If equipment requires calibration as a result of two 
consecutive functional tests, the District Manager may require that 
H2S-detection and H2S-monitoring equipment be 
functionally tested and calibrated more frequently.
    (8) What documentation must I keep?--(i) You must maintain records 
of testing and calibrations (in the drilling or production operations 
report, as applicable) at the facility to show the present status and 
history of each device, including dates and details concerning:
    (A) Installation;
    (B) Removal;
    (C) Inspection;
    (D) Repairs;
    (E) Adjustments; and
    (F) Reinstallation.
    (ii) Records must be available for inspection by MMS personnel.
    (9) What are the requirements for nearby vessels? If vessels are 
stationed overnight alongside facilities in areas of H2S 
present or H2S unknown, you must equip vessels with an 
H2S-detection system that activates audible and visual alarms 
when the concentration of H2S in the atmosphere reaches 20 
ppm. This requirement does not apply to vessels positioned upwind and at 
a safe distance from the facility in accordance with the positioning 
procedure described in the approved H2S Contingency Plan.
    (10) What are the requirements for nearby facilities? The District 
Manager may require you to equip nearby facilities with portable or 
fixed H2S detector(s)

[[Page 362]]

and to test and calibrate those detectors. To invoke this requirement, 
the District Manager will consider dispersion modeling results from a 
possible release to determine if 20 ppm H2S concentration 
levels could be exceeded at nearby facilities.
    (11) What must I do to protect against SO2 if I burn gas 
containing H2S? You must:
    (i) Monitor the SO2 concentration in the air with 
portable or strategically placed fixed devices capable of detecting a 
minimum of 2 ppm of SO2;
    (ii) Take readings at least hourly and at any time personnel detect 
SO2 odor or nasal irritation;
    (iii) Implement the personnel protective measures specified in the 
H2S Contingency Plan if the SO2 concentration in 
the work area reaches 2 ppm; and
    (iv) Calibrate devices every 3 months if you use fixed or portable 
electronic sensing devices to detect SO2.
    (12) May I use alternative measures? You may follow alternative 
measures instead of those in paragraph (j)(11) of this section if you 
propose and the Regional Supervisor approves the alternative measures.
    (13) What are the requirements for protective-breathing equipment? 
In an area classified as H2S present or H2S 
unknown, you must:
    (i) Provide all personnel, including contractors and visitors on a 
facility, with immediate access to self-contained pressure-demand-type 
respirators with hoseline capability and breathing time of at least 15 
minutes.
    (ii) Design, select, use, and maintain respirators in conformance 
with ANSI Z88.2 (incorporated by reference as specified in Sec. 
250.198).
    (iii) Make available at least two voice-transmission devices, which 
can be used while wearing a respirator, for use by designated personnel.
    (iv) Make spectacle kits available as needed.
    (v) Store protective-breathing equipment in a location that is 
quickly and easily accessible to all personnel.
    (vi) Label all breathing-air bottles as containing breathing-quality 
air for human use.
    (vii) Ensure that vessels attendant to facilities carry appropriate 
protective-breathing equipment for each crew member. The District 
Manager may require additional protective-breathing equipment on certain 
vessels attendant to the facility.
    (viii) During H2S alerts, limit helicopter flights to and 
from facilities to the conditions specified in the H2S 
Contingency Plan. During authorized flights, the flight crew and 
passengers must use pressure-demand-type respirators. You must train all 
members of flight crews in the use of the particular type(s) of 
respirator equipment made available.
    (ix) As appropriate to the particular operation(s), (production, 
drilling, well-completion or well-workover operations, or any 
combination of them), provide a system of breathing-air manifolds, 
hoses, and masks at the facility and the briefing areas. You must 
provide a cascade air-bottle system for the breathing-air manifolds to 
refill individual protective-breathing apparatus bottles. The cascade 
air-bottle system may be recharged by a high-pressure compressor 
suitable for providing breathing-quality air, provided the compressor 
suction is located in an uncontaminated atmosphere.
    (k) Personnel safety equipment--(1) What additional personnel-safety 
equipment do I need? You must ensure that your facility has:
    (i) Portable H2S detectors capable of detecting a 10 ppm 
concentration of H2S in the air available for use by all 
personnel;
    (ii) Retrieval ropes with safety harnesses to retrieve incapacitated 
personnel from contaminated areas;
    (iii) Chalkboards and/or note pads for communication purposes 
located on the rig floor, shale-shaker area, the cement-pump rooms, 
well-bay areas, production processing equipment area, gas compressor 
area, and pipeline-pump area;
    (iv) Bull horns and flashing lights; and
    (v) At least three resuscitators on manned facilities, and a number 
equal to the personnel on board, not to exceed three, on normally 
unmanned facilities, complete with face masks, oxygen bottles, and spare 
oxygen bottles.
    (2) What are the requirements for ventilation equipment? You must:

[[Page 363]]

    (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 OCS facility. You must 
report these gas releases to the District Manager immediately by oral 
communication, with a written follow-up report within 15 days, pursuant 
to Sec. Sec. 250.188 through 250.190.
    (m) Do I need to use special drilling, completion and workover 
fluids or procedures? When working in an area classified as 
H2S present or H2S unknown:
    (1) You may use either water- or oil-base muds in accordance with 
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 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.

[[Page 364]]

    (2) Perform well testing with the minimum number of personnel in the 
immediate vicinity of the rig floor and with the appropriate test 
equipment to safely and adequately perform the test. During the test, 
you must continuously monitor H2S levels.
    (3) Not burn produced gases except through a flare which meets the 
requirements of paragraph (q)(6) of this section. Before flaring gas 
containing H2S, you must activate SO2 monitoring 
equipment in accordance with paragraph (j)(11) of this section. If you 
detect SO2 in excess of 2 ppm, you must implement the 
personnel protective measures in your H2S Contingency Plan, 
required by paragraph (f) of this section. You must also follow the 
requirements of 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 Manager. Water cushions must be thoroughly inhibited in order 
to prevent H2S attack on metals. You must flush the test 
string fluid treated for this purpose after completion of the test.
    (6) Use surface test units and related equipment that is designed 
for H2S service.
    (p) Metallurgical properties of equipment. When operating in a zone 
with H2S present, you must use equipment that is constructed 
of materials with metallurgical properties that resist or prevent 
sulfide stress cracking (also known as hydrogen embrittlement, stress 
corrosion cracking, or H2S embrittlement), chloride-stress 
cracking, hydrogen-induced cracking, and other failure modes. You must 
do all of the following:
    (1) Use tubulars and other equipment, casing, tubing, drill pipe, 
couplings, flanges, and related equipment that is designed for 
H2S service.
    (2) Use BOP system components, wellhead, pressure-control equipment, 
and related equipment exposed to H\2\S-bearing fluids in conformance 
with NACE Standard MR0175-03 (incorporated by reference as specified in 
Sec. 250.198).
    (3) Use temporary downhole well-security devices such as retrievable 
packers and bridge plugs that are designed for H2S service.
    (4) When producing in zones bearing H2S, use equipment 
constructed of materials capable of resisting or preventing sulfide 
stress cracking.
    (5) Keep the use of welding to a minimum during the installation or 
modification of a production facility. Welding must be done in a manner 
that ensures resistance to sulfide stress cracking.
    (q) General requirements when operating in an H2S zone--
(1) Coring operations. When you conduct coring operations in 
H2S-bearing zones, all personnel in the working area must 
wear protective-breathing equipment at least 10 stands in advance of 
retrieving the core barrel. Cores to be transported must be sealed and 
marked for the presence of H2S.
    (2) Logging operations. You must treat and condition well-control 
fluid in use for logging operations to minimize the effects of 
H2S on the logging equipment.
    (3) Stripping operations. Personnel must monitor displaced well-
control fluid returns and wear 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

[[Page 365]]

wear on tool joints, and joint imbalance.
    (6) Flare system. The flare outlet must be of a diameter that allows 
easy nonrestricted flow of gas. You must locate flare line outlets on 
the downside of the facility and as far from the facility as is 
feasible, taking into account the prevailing wind directions, the wake 
effects caused by the facility and adjacent structure(s), and the height 
of all such facilities and structures. You must equip the flare outlet 
with an automatic ignition system including a pilot-light gas source or 
an equivalent system. You must have alternate methods for igniting the 
flare. You must pipe to the flare system used for H2S all 
vents from production process equipment, tanks, relief valves, burst 
plates, and similar devices.
    (7) Corrosion mitigation. You must use effective means of monitoring 
and controlling corrosion caused by acid gases (H2S and 
CO2) in both the downhole and surface portions of a 
production system. You must take specific corrosion monitoring and 
mitigating measures in areas of unusually severe corrosion where 
accumulation of water and/or higher concentration of H2S 
exists.
    (8) Wireline lubricators. Lubricators which may be exposed to fluids 
containing H2S must be of H2S-resistant materials.
    (9) Fuel and/or instrument gas. You must not use gas containing 
H2S for instrument gas. You must not use gas containing 
H2S for fuel gas without the prior approval of the District 
Manager.
    (10) Sensing lines and devices. Metals used for sensing line and 
safety-control devices which are necessarily exposed to H2S-
bearing fluids must be constructed of H2S-corrosion resistant 
materials or coated so as to resist H2S corrosion.
    (11) Elastomer seals. You must use H2S-resistant 
materials for all seals which may be exposed to fluids containing 
H2S.
    (12) Water disposal. If you dispose of produced water by means other 
than subsurface injection, you must submit to the District Manager an 
analysis of the anticipated H2S content of the water at the 
final treatment vessel and at the discharge point. The District Manager 
may require that the water be treated for removal of H2S. The 
District Manager may require the submittal of an updated analysis if the 
water disposal rate or the potential H2S content increases.
    (13) Deck drains. You must equip open deck drains with traps or 
similar devices to prevent the escape of H2S gas into the 
atmosphere.
    (14) Sealed voids. You must take precautions to eliminate sealed 
spaces in piping designs (e.g., slip-on flanges, reinforcing pads) which 
can be invaded by atomic hydrogen when H2S is present.

[62 FR 3795, Jan. 27, 1997. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998; 65 FR 15864, Mar. 24, 2000. Redesignated and 
amended at 68 FR 8423, 8434, Feb. 20, 2003; 71 FR 19645, Apr. 17, 2006; 
72 FR 12096, Mar. 15, 2007; 72 FR 25201, May 4, 2007]



            Subpart E_Oil and Gas Well-Completion Operations



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

[[Page 366]]

and related equipment, unless otherwise approved by the District 
Manager. A closed surface-controlled subsurface safety valve of the 
pump-through type may be used in lieu of the pump-through-type tubing 
plug, provided that the surface control has been locked out of 
operation. The well from which the rig or related equipment is to be 
moved shall also be equipped with a back-pressure valve prior to 
removing the blowout preventer (BOP) system and installing the tree.

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



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. 250.490 of this part), 
the lessee shall take appropriate precautions to protect life and 
property on the platform or completion unit, including, but not limited 
to operations such as blowing the well down, dismantling wellhead 
equipment and flow lines, circulating the well, swabbing, and pulling 
tubing, pumps, and packers. The lessee shall comply with the 
requirements in Sec. 250.490 of this part as well as the appropriate 
requirements of this subpart.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998; 68 FR 8434, Feb. 20, 2003]



Sec. 250.505  Subsea completions.

    No subsea well completion shall be commenced until the lessee 
obtains written approval from the District Manager 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.



Sec. Sec. 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

[[Page 367]]

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 Manager to determine specific operating 
requirements, field well-completion rules may be established on the 
District Manager's initiative or in response to a request from a lessee. 
Such rules may modify the specific requirements of this subpart. After 
field well-completion rules have been established, well-completion 
operations in the field shall be conducted in accordance with such rules 
and other requirements of this subpart. Field well-completion rules may 
be amended or canceled for cause at any time upon the initiative of the 
District Manager or upon the request of a lessee.



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

    (a) No well-completion operation may begin until the lessee receives 
written approval from the District Manager. If completion is planned and 
the data are available at the time you submit the Application for Permit 
to Drill and Supplemental APD Information Sheet (Forms MMS-123 and MMS-
123S), you may request approval for a well-completion on those forms 
(see Sec. Sec. 250.410 through 250.418 of this part). If the District 
Manager has not approved the completion or if the completion objective 
or plans have significantly changed, you must submit an Application for 
Permit to Modify (Form MMS-124) for approval of such operations.
    (b) You must submit the following with Form MMS-124 (or with Form 
MMS-123; Form MMS-123S):
    (1) A brief description of the well-completion procedures to be 
followed, a statement of the expected surface pressure, and type and 
weight of completion fluids;
    (2) A schematic drawing of the well showing the proposed producing 
zone(s) and the subsurface well-completion equipment to be used;
    (3) For multiple completions, a partial electric log showing the 
zones proposed for completion, if logs have not been previously 
submitted;
    (4) When the well-completion is in a zone known to contain 
H2S or a zone where the presence of H2S is 
unknown, information pursuant to Sec. 250.490 of this part; and
    (5) Payment of the service fee listed in Sec. 250.125.
    (c) Within 30 days after completion, you must submit to the District 
Manager an End of Operations Report (Form MMS-125), including a 
schematic of the tubing and subsurface equipment.
    (d) You must submit public information copies of Form MMS-125 
according to Sec. 250.186.

[53 FR 10690, Apr. 1, 1988, as amended at 58 FR 49928, Sept. 24, 1993. 
Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 64 FR 
72794, Dec. 28, 1999; 68 FR 8434, Feb. 20, 2003; 71 FR 19646, Apr. 17, 
2006; 71 FR 40911, July 19, 2006; 72 FR 25201, May 4, 2007]



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

[[Page 368]]

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 must meet 
the appropriate standards from the following table:

------------------------------------------------------------------------
                                           The minimum BOP stack must
                 When                               include
------------------------------------------------------------------------
(1) The expected pressure is less      Three BOPs consisting of an
 than 5,000 psi.                        annular, one set of pipe rams,
                                        and one set of blind or blind-
                                        shear rams.
(2) The expected pressure is 5,000     Four BOPs consisting of an
 psi or greater or you use multiple     annular, two sets of pipe rams,
 tubing strings.                        and one set of blind or blind-
                                        shear rams.
(3) You handle multiple tubing         Four BOPs consisting of an
 strings simultaneously.                annular, one set of pipe rams,
                                        one set of dual pipe rams, and
                                        one set of blind or blind-shear
                                        rams.
(4) You use a tapered drill string...  At least one set of pipe rams
                                        that are capable of sealing
                                        around each size of drill
                                        string. If the expected pressure
                                        is greater than 5,000 psi, then
                                        you must have at least two sets
                                        of pipe rams that are capable of
                                        sealing around the larger size
                                        drill string. You may substitute
                                        one set of variable bore rams
                                        for two sets of pipe rams.
(5) It is after February 21, 2006....  At least one set of blind-shear
                                        rams. The blind-shear rams must
                                        be capable of shearing the drill
                                        pipe or tubing in the hole.
------------------------------------------------------------------------

    (c) The BOP systems for well completions shall be equipped with the 
following:
    (1) A hydraulic-actuating system that provides sufficient 
accumulator capacity to supply 1.5 times the volume necessary to close 
all BOP equipment units with a minimum pressure of 200 psi above the 
precharge pressure without assistance from a charging system. No later 
than December 1, 1988, accumulator regulators supplied by rig air and 
without a secondary source of pneumatic supply, shall be equipped with 
manual overrides, or alternately, other devices provided to ensure 
capability of hydraulic operations if rig air is lost.
    (2) A secondary power source, independent from the primary power 
source, with sufficient capacity to close all BOP system components and 
hold them closed.
    (3) Locking devices for the pipe-ram preventers.
    (4) At least one remote BOP-control station and one BOP-control 
station on the rig floor.
    (5) A choke line and a kill line each equipped with two full opening 
valves and a choke manifold. At least one of the valves on the choke 
line shall be remotely controlled. At least one of the valves on the 
kill line shall be remotely controlled, except that a check valve on the 
kill line in lieu of the remotely controlled valve may be installed 
provided that two readily accessible manual valves are in place and the 
check valve is placed between the manual valves and the pump. This 
equipment shall have a pressure rating at least equivalent to the ram 
preventers.

[[Page 369]]

    (d) An inside BOP or a spring-loaded, back-pressure safety valve and 
an essentially full-opening, work-string safety valve in the open 
position shall be maintained on the rig floor at all times during well-
completion operations. A wrench to fit the work-string safety valve 
shall be readily available. Proper connections shall be readily 
available for inserting valves in the work string.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50616, Dec. 8, 1989; 58 
FR 49928, Sept. 24, 1993. Redesignated at 62 29479, May 29, 1998, as 
amended at 68 FR 8434, Feb. 20, 2003]



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 Manager may require testing every 7 days if conditions or BOP 
performance warrant.
    (b) BOP test pressures. When you test the BOP system, you must 
conduct a low pressure and a high pressure test for each BOP component. 
Each individual pressure test must hold pressure long enough to 
demonstrate that the tested component(s) holds the required pressure. 
The District Manager may approve or require other test pressures or 
practices. Required test pressures are as follows:
    (1) All low pressure tests must be between 200 and 300 psi. Any 
initial pressure above 300 psi must be bled back to a pressure between 
200 and 300 psi before starting the test. If the initial pressure 
exceeds 500 psi, you must bleed back to zero and reinitiate the test. 
You must conduct the low pressure test before the high pressure test.
    (2) For ram-type BOP's, choke manifold, and other BOP equipment, the 
high pressure test must equal the rated working pressure of the 
equipment.
    (3) For annular-type BOP's, the high pressure test must equal 70 
percent of the rated working pressure of the equipment.
    (c) Duration of pressure test. Each test must hold the required 
pressure for 5 minutes.
    (1) For surface BOP systems and surface equipment of a subsea BOP 
system, a 3-minute test duration is acceptable if you record your test 
pressures on the outermost half of a 4-hour chart, on a 1-hour chart, or 
on a digital recorder.
    (2) If the equipment does not hold the required pressure during a 
test, you must remedy the problem and retest the affected component(s).
    (d) Additional BOP testing requirements. You must:
    (1) Use water to test the surface BOP system;
    (2) Stump test a subsurface BOP system before installation. You must 
use water to stump test a subsea BOP system. You may use drilling or 
completion fluids to conduct subsequent tests of a subsea BOP system;
    (3) Alternate tests between control stations and pods. If a control 
station or pod is not functional, you must suspend further completion 
operations until that station or pod is operable;
    (4) Pressure test the blind or blind-shear ram at least every 30 
days;
    (5) Function test annulars and rams every 7 days;
    (6) Pressure-test variable bore-pipe rams against all sizes of pipe 
in use, excluding drill collars and bottom-hole tools; and
    (7) Test affected BOP components following the disconnection or 
repair of any well-pressure containment seal in the wellhead or BOP 
stack assembly;
    (e) Postponing BOP tests. You may postpone a BOP test if you have 
well-control problems. You must conduct the required BOP test as soon as 
possible (i.e., first trip out of the hole) after the problem has been 
remedied. You must record the reason for postponing any test in the 
driller's report.
    (f) Weekly crew drills. You must conduct a weekly drill to 
familiarize all personnel engaged in well-completion operations with 
appropriate safety measures.
    (g) BOP inspections. You must visually inspect your BOP system and 
marine riser at least once each day if weather and sea conditions 
permit.

[[Page 370]]

You may use television cameras to inspect this equipment. The District 
Manager may approve alternate methods and frequencies to inspect a 
marine riser.
    (h) BOP maintenance. You must maintain your BOP system to ensure 
that the equipment functions properly.
    (i) BOP test records. You must record the time, date, and results of 
all pressure tests, actuations, crew drills, and inspections of the BOP 
system, system components, and marine riser in the driller's report. In 
addition, you must:
    (1) Record BOP test pressures on pressure charts;
    (2) Have your onsite representative certify (sign and date) BOP test 
charts and reports as correct;
    (3) Document the sequential order of BOP and auxiliary equipment 
testing and the pressure and duration of each test. You may reference a 
BOP test plan if it is available at the facility;
    (4) Identify the control station or pod used during the test;
    (5) Identify any problems or irregularities observed during BOP 
system and equipment testing and record actions taken to remedy the 
problems or irregularities;
    (6) Retain all records including pressure charts, driller's report, 
and referenced documents pertaining to BOP tests, actuations, and 
inspections at the facility for the duration of the completion activity; 
and
    (7) After completion of the well, you must retain all the records 
listed in paragraph (i)(6) of this section for a period of 2 years at 
the facility, at the lessee's field office nearest the OCS facility, or 
at another location conveniently available to the District Manager.
    (j) Alternate methods. The District Manager may require, or approve, 
more frequent testing, as well as different test pressures and 
inspection methods, or other practices.

[63 FR 29607, June 1, 1998]



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 Manager.
    (c) When the tree is installed, the wellhead shall be equipped so 
that all annuli can be monitored for sustained pressure. If sustained 
casing pressure is observed on a well, the lessee shall immediately 
notify the District Manager.
    (d) Wellhead, tree, and related equipment shall have a pressure 
rating greater than the shut-in tubing pressure and shall be designed, 
installed, used, maintained, and tested so as to achieve and maintain 
pressure control. New wells completed as flowing or gas-lift wells shall 
be equipped with a minimum of one master valve and one surface safety 
valve, installed above the master valve, in the vertical run of the 
tree.
    (e) Subsurface safety equipment shall be installed, maintained, and 
tested in compliance with 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:
    Expected surface pressure means the highest pressure predicted to be 
exerted upon the surface of a well. In calculating expected surface 
pressure, you must consider reservoir pressure as well as applied 
surface pressure.

[[Page 371]]

    Routine operations mean any of the following operations conducted on 
a well with the tree installed:
    (a) Cutting paraffin;
    (b) Removing and setting pump-through-type tubing plugs, gas-lift 
valves, and subsurface safety valves which can be removed by wireline 
operations;
    (c) Bailing sand;
    (d) Pressure surveys;
    (e) Swabbing;
    (f) Scale or corrosion treatment;
    (g) Caliper and gauge surveys;
    (h) Corrosion inhibitor treatment;
    (i) Removing or replacing subsurface pumps;
    (j) Through-tubing logging (diagnostics);
    (k) Wireline fishing; and
    (l) Setting and retrieving other subsurface flow-control devices.
    Workover operations mean the work conducted on wells after the 
initial completion for the purpose of maintaining or restoring the 
productivity of a well.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 71 FR 11313, Mar. 7, 2006]



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 
Manager. A closed surface-controlled subsurface safety valve of the 
pump-through-type may be used in lieu of the pump-through-type tubing 
plug provided that the surface control has been locked out of operation. 
The well to which a well-workover rig or related equipment is to be 
moved shall also be equipped with a back-pressure valve prior to 
removing the tree and installing and testing the blowout-preventer (BOP) 
system. The well from which a well-workover rig or related equipment is 
to be moved shall also be equipped with a back pressure valve prior to 
removing the BOP system and installing the tree. Coiled tubing units, 
snubbing units, or wireline units may be moved onto a platform without 
shutting in wells.



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.



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. 250.490 of this part), 
the lessee shall take appropriate precautions to protect life and 
property on the platform or rig, including but not limited to operations 
such as blowing the well down, dismantling wellhead equipment and flow 
lines, circulating the well, swabbing, and pulling tubing, pumps and 
packers. The lessee shall comply with the requirements in Sec. 250.490 
of this part as well as the appropriate requirements of this subpart.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998; 64 FR 9065, Feb. 24, 1999; 68 FR 8435, Feb. 20, 
2003]



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 
Manager 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]

[[Page 372]]



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.



Sec. Sec. 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 Manager to determine specific operating 
requirements, field well-workover rules may be established on the 
District Manager's initiative or in response to a request from a lessee. 
Such rules may modify the specific requirements of this subpart. After 
field well-workover rules have been established, well-workover 
operations in the field shall be conducted in accordance with such rules 
and other requirements of this subpart. Field well-workover rules may be 
amended or canceled for cause at any time upon the initiative of the 
District Manager or upon the request of a lessee.



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 Manager. Approval for these 
operations must be requested on Form MMS-124, Application for Permit to 
Modify.
    (b) You must submit the following with Form MMS-124:
    (1) A brief description of the well-workover procedures to be 
followed, a statement of the expected surface pressure, and type and 
weight of workover fluids;
    (2) When changes in existing subsurface equipment are proposed, a 
schematic drawing of the well showing the zone proposed for workover and 
the workover equipment to be used;
    (3) Where the well-workover is in a zone known to contain 
H2S or a zone where the presence of H2S is 
unknown, information pursuant to Sec. 250.490 of this part; and
    (4) Payment of the service fee listed in Sec. 250.125.
    (c) The following additional information shall be submitted with 
Form

[[Page 373]]

MMS-124 if completing to a new zone is proposed:
    (1) Reason for abandonment of present producing zone including 
supportive well test data, and
    (2) A statement of anticipated or known pressure data for the new 
zone.
    (d) Within 30 days after completing the well-workover operation, 
except routine operations, Form MMS-124, Application for Permit to 
Modify, shall be submitted to the District Manager, showing the work as 
performed. In the case of a well-workover operation resulting in the 
initial recompletion of a well into a new zone, a Form MMS-125, End of 
Operations Report, shall be submitted to the District Manager and shall 
include a new schematic of the tubing subsurface equipment if any 
subsurface equipment has been changed.

[53 FR 10690, Apr. 1, 1988, as amended at 58 FR 49928, Sept. 24, 1993. 
Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 65 FR 
35824, June 6, 2000; 68 FR 8435, Feb. 20, 2003; 71 FR 40912, July 19, 
2006; 72 FR 25201, May 4, 2007]



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.



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 must meet the appropriate standards from the following 
table:

------------------------------------------------------------------------
                                           The minimum BOP stack must
                 When                               include
------------------------------------------------------------------------
(1) The expected pressure is less      Three BOPs consisting of an
 than 5,000 psi.                        annular, one set of pipe rams,
                                        and one set of blind or blind-
                                        shear rams.
(2) The expected pressure is 5,000     Four BOPs consisting of an
 psi or greater or you use multiple     annular, two sets of pipe rams,
 tubing strings.                        and one set of blind or blind-
                                        shear rams.

[[Page 374]]

 
(3) You handle multiple tubing         Four BOPs consisting of an
 strings simultaneously.                annular, one set of pipe rams,
                                        one set of dual pipe rams, and
                                        one set of blind or blind-shear
                                        rams.
(4) You use a tapered drill string...  At least one set of pipe rams
                                        that are capable of sealing
                                        around each size of drill
                                        string. If the expected pressure
                                        is greater than 5,000 psi, then
                                        you must have at least two sets
                                        of pipe rams that are capable of
                                        sealing around the larger size
                                        drill string. You may substitute
                                        one set of variable bore rams
                                        for two sets of pipe rams.
(5) It is after February 21, 2006....  At least one set of blind-shear
                                        rams. The blind-shear rams must
                                        be capable of shearing the drill
                                        pipe or tubing in the hole.
------------------------------------------------------------------------

    (c) The BOP systems for well-workover operations with the tree 
removed shall be equipped with the following:
    (1) A hydraulic-actuating system that provides sufficient 
accumulator capacity to supply 1.5 times the volume necessary to close 
all BOP equipment units with a minimum pressure of 200 psi above the 
precharge pressure without assistance from a charging system. No later 
than December 1, 1988, accumulator regulators supplied by rig air and 
without a secondary source of pneumatic supply, shall be equipped with 
manual overrides, or alternately, other devices provided to ensure 
capability of hydraulic operations if rig air is lost;
    (2) A secondary power source, independent from the primary power 
source, with sufficient capacity to close all BOP system components and 
hold them closed;
    (3) Locking devices for the pipe-ram preventers;
    (4) At least one remote BOP-control station and one BOP-control 
station on the rig floor; and
    (5) A choke line and a kill line each equipped with two full opening 
valves and a choke manifold. At least one of the valves on the choke-
line shall be remotely controlled. At least one of the valves on the 
kill line shall be remotely controlled, except that a check valve on the 
kill line in lieu of the remotely controlled valve may be installed 
provided two readily accessible manual valves are in place and the check 
valve is placed between the manual valves and the pump. This equipment 
shall have a pressure rating at least equivalent to the ram preventers.
    (d) The minimum BOP-system components for well-workover operations 
with the tree in place and performed through the wellhead inside of 
conventional tubing using small-diameter jointed pipe (usually \3/4\ 
inch to 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) For coiled tubing operations with the production tree in place, 
you must meet the following minimum requirements for the BOP system:
    (1) BOP system components must be in the following order from the 
top down:

------------------------------------------------------------------------
                                    BOP system when     BOP system for
BOP system when expected surface   expected surface   wells with returns
pressures are less than or equal     pressures are     taken through an
          to 3,500 psi            greater than 3,500   outlet on the BOP
                                          psi                stack
------------------------------------------------------------------------
Stripper or annular-type well     Stripper or         Stripper or
 control component.                annular-type well   annular-type well
                                   control component.  control
                                                       component.
Hydraulically-operated blind      Hydraulically-      Hydraulically-
 rams.                             operated blind      operated blind
                                   rams.               rams.
Hydraulically-operated shear      Hydraulically-      Hydraulically-
 rams.                             operated shear      operated shear
                                   rams.               rams.
Kill line inlet.................  Kill line inlet...  Kill line inlet.
Hydraulically-operated two-way    Hydraulically-      Hydraulically-
 slip rams.                        operated two-way    operated two-way
                                   slip rams.          slip rams.
                                                      Hydraulically-
                                                       operated pipe
                                                       rams.
Hydraulically-operated pipe rams  Hydraulically-      A flow tee or
                                   operated pipe       cross.
                                   rams..             Hydraulically-
                                  Hydraulically-       operated pipe
                                   operated blind-     rams.
                                   shear rams. These  Hydraulically-
                                   rams should be      operated blind-
                                   located as close    shear rams on
                                   to the tree as      wells with
                                   practical.          surface pressures
                                                       3,500
                                                       psi. As an
                                                       option, the pipe
                                                       rams can be
                                                       placed below the
                                                       blind-shear rams.
                                                       The blind-shear
                                                       rams should be
                                                       located as close
                                                       to the tree as
                                                       practical.
------------------------------------------------------------------------


[[Page 375]]

    (2) You may use a set of hydraulically-operated combination rams for 
the blind rams and shear rams.
    (3) You may use a set of hydraulically-operated combination rams for 
the hydraulic two-way slip rams and the hydraulically-operated pipe 
rams.
    (4) You must attach a dual check valve assembly to the coiled tubing 
connector at the downhole end of the coiled tubing string for all coiled 
tubing well-workover operations. If you plan to conduct operations 
without downhole check valves, you must describe alternate procedures 
and equipment in Form MMS-124, Application for Permit to Modify and have 
it approved by the District Manager.
    (5) You must have a kill line and a separate choke line. You must 
equip each line with two full-opening valves and at least one of the 
valves must be remotely controlled. You may use a manual valve instead 
of the remotely controlled valve on the kill line if you install a check 
valve between the two full-opening manual valves and the pump or 
manifold. The valves must have a working pressure rating equal to or 
greater than the working pressure rating of the connection to which they 
are attached, and you must install them between the well control stack 
and the choke or kill line. For operations with expected surface 
pressures greater than 3,500 psi, the kill line must be connected to a 
pump or manifold. You must not use the kill line inlet on the BOP stack 
for taking fluid returns from the wellbore.
    (6) You must have a hydraulic-actuating system that provides 
sufficient accumulator capacity to close-open-close each component in 
the BOP stack. This cycle must be completed with at least 200 psi above 
the pre-charge pressure, without assistance from a charging system.
    (7) All connections used in the surface BOP system from the tree to 
the uppermost required ram must be flanged, including the connections 
between the well control stack and the first full-opening valve on the 
choke line and the kill line.
    (f) The minimum BOP-system components for well-workover operations 
with the tree in place and performed by moving tubing or drill pipe in 
or out of a well under pressure utilizing equipment specifically 
designed for that purpose, i.e., snubbing operations, shall include the 
following:
    (1) One set of pipe rams hydraulically operated, and
    (2) Two sets of stripper-type pipe rams hydraulically operated with 
spacer spool.
    (g) An inside BOP or a spring-loaded, back-pressure safety valve and 
an essentially full-opening, work-string safety valve in the open 
position shall be maintained on the rig floor at all times during well-
workover operations when the tree is removed or during well-workover 
operations with the tree installed and using small tubing as the work 
string. A wrench to fit the work-string safety valve shall be readily 
available. Proper connections shall be readily available for inserting 
valves in the work string. The full-opening safety valve is not required 
for coiled tubing or snubbing operations.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50616, Dec. 8, 1989; 58 
FR 49928, Sept. 24, 1993. Redesignated at 63 FR 29479, May 29, 1998, as 
amended at 68 FR 8435, Feb. 20, 2003; 71 FR 11313, Mar. 7, 2006; 71 FR 
29710, May 23, 2006]



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

    (a) BOP pressure tests. When you pressure test the BOP system you 
must conduct a low-pressure test and a high-pressure test for each 
component. You must conduct the low-pressure test before the high-
pressure test. For purposes of this section, BOP system components 
include ram-type BOP's, related control equipment, choke and kill lines, 
and valves, manifolds, strippers, and safety valves. Surface BOP systems 
must be pressure tested with water.
    (1) Low pressure tests. All BOP system components must be 
successfully tested to a low pressure between 200 and 300 psi. Any 
initial pressure equal to or greater than 300 psi must be bled back to a 
pressure between 200 and 300 psi before starting the test. If the 
initial pressure exceeds 500 psi, you must bleed back to zero before 
starting the test.

[[Page 376]]

    (2) High pressure tests. All BOP system components must be 
successfully tested to the rated working pressure of the BOP equipment, 
or as otherwise approved by the District Manager. The annular-type BOP 
must be successfully tested at 70 percent of its rated working pressure 
or as otherwise approved by the District Manager.
    (3) Other testing requirements. Variable bore pipe rams must be 
pressure tested against the largest and smallest sizes of tubulars in 
use (jointed pipe, seamless pipe) in the well.
    (b) The BOP systems shall be tested at the following times:
    (1) When installed;
    (2) At least every 7 days, alternating between control stations and 
at staggered intervals to allow each crew to operate the equipment. If 
either control system is not functional, further operations shall be 
suspended until the nonfunctional, system is operable. The test every 7 
days is not required for blind or blind-shear rams. The blind or blind-
shear rams shall be tested at least once every 30 days during operation. 
A longer period between blowout preventer tests is allowed when there is 
a stuck pipe or pressure-control operation and remedial efforts are 
being performed. The tests shall be conducted as soon as possible and 
before normal operations resume. The reason for postponing testing shall 
be entered into the operations log.
    (3) Following repairs that require disconnecting a pressure seal in 
the assembly, the affected seal will be pressure tested.
    (c) All personnel engaged in well-workover operations shall 
participate in a weekly BOP drill to familiarize crew members with 
appropriate safety measures.
    (d) You may conduct a stump test for the BOP system on location. A 
plan describing the stump test procedures must be included in your Form 
MMS-124, Application for Permit to Modify, and must be approved by the 
District Manager.
    (e) You must test the coiled tubing connector to a low pressure of 
200 to 300 psi, followed by a high pressure test to the rated working 
pressure of the connector or the expected surface pressure, whichever is 
less. You must successfully pressure test the dual check valves to the 
rated working pressure of the connector, the rated working pressure of 
the dual check valve, expected surface pressure, or the collapse 
pressure of the coiled tubing, whichever is less.
    (f) You must record test pressures during BOP and coiled tubing 
tests on a pressure chart, or with a digital recorder, unless otherwise 
approved by the District Manager. The test interval for each BOP system 
component must be 5 minutes, except for coiled tubing operations, which 
must include a 10 minute high-pressure test for the coiled tubing 
string. Your representative at the facility must certify that the charts 
are correct.
    (g) The time, date, and results of all pressure tests, actuations, 
inspections, and crew drills of the BOP system, system components, and 
marine risers shall be recorded in the operations log. The BOP tests 
shall be documented in accordance with the following:
    (1) The documentation shall indicate the sequential order of BOP and 
auxiliary equipment testing and the pressure and duration of each test. 
As an alternate, the documentation in the operations log may reference a 
BOP test plan that contains the required information and is retained on 
file at the facility.
    (2) The control station used during the test shall be identified in 
the operations log. For a subsea system, the pod used during the test 
shall be identified in the operations log.
    (3) Any problems or irregularities observed during BOP and auxiliary 
equipment testing and any actions taken to remedy such problems or 
irregularities shall be noted in the operations log.
    (4) Documentation required to be entered in the operation log may 
instead be referenced in the operations log. All records including 
pressure charts, operations log, and referenced documents pertaining to 
BOP tests, actuations, and inspections, shall be available for MMS 
review at the facility for the duration of well-workover activity. 
Following completion of the well-workover activity, all such records 
shall be retained for a period of 2 years

[[Page 377]]

at the facility, at the lessee's filed office nearest the OCS facility, 
or at another location conveniently available to the District Manager.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 56 
FR 1915, Jan. 18, 1991. Redesignated at 63 FR 29479, May 29, 1998; 71 FR 
11313, Mar. 7, 2006]



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 Manager.
    (c) When reinstalling the tree, the wellhead shall be equipped so 
that all annuli can be monitored for sustained pressure. If sustained 
casing pressure is observed on a well, the lessee shall immediately 
notify the District Manager.
    (d) Wellhead, tree, and related equipment shall have a pressure 
rating greater than the shut-in tubing pressure and shall be designed, 
installed, used, maintained, and tested so as to achieve and maintain 
pressure control. The tree shall be equipped with a minimum of one 
master valve and one surface safety valve in the vertical run of the 
tree when it is reinstalled.
    (e) Subsurface safety equipment shall be installed, maintained, and 
tested in compliance with 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.
    (c) When the lubricator is initially installed on the well, it shall 
be successfully pressure tested to the expected shut-in surface 
pressure.

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

Subpart G [Reserved]



             Subpart H_Oil and Gas Production Safety Systems



Sec. 250.800  General requirements.

    (a) Production safety equipment shall be designed, installed, used, 
maintained, and tested in a manner to assure the safety and protection 
of the human, marine, and coastal environments. Production safety 
systems operated in subfreezing climates shall utilize equipment and 
procedures selected with consideration of floating ice, icing, and other 
extreme environmental conditions that may occur in the area. Production 
shall not commence until the production safety system has been approved 
and a preproduction inspection has been requested by the lessee.
    (b) For all new floating production systems (FPSs) (e.g., column-
stabilized-units (CSUs); floating production, storage and offloading 
facilities (FPSOs); tension-leg platforms (TLPs); spars, etc.), you must 
do all of the following:
    (1) Comply with API RP 14J (incorporated by reference as specified 
in 30 CFR 250.198);
    (2) Meet the drilling and production riser standards of API RP 2RD 
(incorporated by reference as specified in 30 CFR 250.198);
    (3) Design all stationkeeping systems for floating facilities to 
meet the standards of API RP 2SK (incorporated by reference as specified 
in 30 CFR

[[Page 378]]

250.198), as well as relevant U.S. Coast Guard regulations; and
    (4) Design stationkeeping systems for floating facilities to meet 
structural requirements in subpart I, Sec. Sec. 250.900 through 250.921 
of this part.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 70 FR 41574, July 19, 2005]



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 
Manager to be incapable of natural flowing. These devices may consist of 
a surface-controlled subsurface safety valve (SSSV), a subsurface-
controlled SSSV, an injection valve, a tubing plug, or a tubing/annular 
subsurface safety device, and any associated safety valve lock or 
landing nipple.
    (b) Specifications for SSSV's. Surface-controlled and subsurface-
controlled SSSV's and safety valve locks and landing nipples installed 
in the OCS shall conform to the requirements in 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 Manager's satisfaction 
that one of the following criteria are met:
    (1) Wells not previously equipped with surface-controlled SSSV's 
shall be so equipped when the tubing is first removed and reinstalled,
    (2) The subsurface-controlled SSSV is installed in wells completed 
from a single-well or multiwell satellite caisson or seafloor 
completions, or
    (3) The subsurface-controlled SSSV is installed in wells with a 
surface-controlled SSSV that has become inoperable and cannot be 
repaired without removal and reinstallation of the tubing.
    (e) Design, installation, and operation of SSSV's. The SSSV's shall 
be designed, installed, operated, and maintained to ensure reliable 
operation.
    (1) The device shall be installed at a depth of 100 feet or more 
below the seafloor within 2 days after production is established. When 
warranted by conditions such as permafrost, unstable bottom conditions, 
hydrate formation, or paraffins, an alternate setting depth of the 
subsurface safety device may be approved by the District Manager.
    (2) Until a subsurface safety device is installed, the well shall be 
attended in the immediate vicinity so that emergency actions may be 
taken while the well is open to flow. During testing and inspection 
procedures, the well shall not be left unattended while open to 
production unless a properly operating subsurface-safety device has been 
installed in the well.
    (3) The well shall not be open to flow while the subsurface safety 
device is removed, except when flowing of the well is necessary for a 
particular operation such as cutting paraffin, bailing sand, or similar 
operations.
    (4) All SSSV's must be inspected, installed, maintained, and tested 
in accordance with American Petroleum Institute Recommended Practice 
14B, Recommended Practice for Design, Installation, Repair, and 
Operation of Subsurface Safety Valve Systems (incorporated by reference 
as specified in Sec. 250.198).
    (f) Subsurface safety devices in shut-in wells. New completions 
(perforated but not placed on production) and completions shut in for a 
period of 6 months shall be equipped with either (1) a pump-through-type 
tubing plug; (2) a surface-controlled SSSV, provided the surface control 
has been rendered inoperative; or (3) an injection valve capable of 
preventing backflow. The setting

[[Page 379]]

depth of the subsurface safety device shall be approved by the District 
Manager on a case-by-case basis, when warranted by conditions such as 
permafrost, unstable bottom conditions, hydrate formations, and 
paraffins.
    (g) Subsurface safety devices in injection wells. A surface-
controlled SSSV or an injection valve capable of preventing backflow 
shall be installed in all injection wells. This requirement is not 
applicable if the District Manager concurs that the well is incapable of 
flowing. The lessee shall verify the no-flow condition of the well 
annually.
    (h) Temporary removal for routine operations. (1) Each wireline- or 
pumpdown-retrievable subsurface safety device may be removed, without 
further authorization or notice, for a routine operation which does not 
require the approval of a Form MMS-124, Application for Permit to 
Modify, in 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 
Manager.
    (4) The well shall not be allowed to flow while the subsurface 
safety device is removed, except when flowing the well is necessary for 
that particular operation. The provisions of this paragraph are not 
applicable to the testing and inspection procedures in 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; 72 FR 12096, Mar. 15, 2007; 72 FR 25201, May 4, 
2007]



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. You must protect all platform production facilities 
with a basic and ancillary surface safety system designed, analyzed, 
installed, tested, and maintained in operating condition in accordance 
with API RP 14C (incorporated by reference as specified in Sec. 
250.198). If you use processing components other than those for which 
Safety Analysis Checklists are included in API RP 14C you must utilize 
the analysis technique and documentation specified therein to determine 
the effects and requirements of these components on the safety system. 
Safety device requirements for pipelines are under Sec. 250.1004.
    (c) Specification for surface safety valves (SSV) and underwater 
safety valves (USV). All wellhead SSV's, USV's, and their actuators 
which are

[[Page 380]]

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 SSVs and USVs must be inspected, 
installed, maintained, and tested in accordance with API RP 14H, 
Recommended Practice for Installation, Maintenance, and Repair of 
Surface Safety Valves and Underwater Safety Valves Offshore 
(incorporated by reference as specified in Sec. 250.198). If any SSV or 
USV does not operate properly or if any fluid flow is observed during 
the leakage test, the valve shall be repaired or replaced.
    (e) Approval of safety-systems design and installation features. 
Prior to installation, the lessee shall submit, in duplicate for 
approval to the District Manager a production safety system application 
containing information relative to design and installation features. 
Information concerning approved design and installation features shall 
be maintained by the lessee at the lessee's offshore field office 
nearest the OCS facility or other location conveniently available to the 
District Manager. All approvals are subject to field verifications. The 
application shall include the following:
    (1) A schematic flow diagram showing tubing pressure, size, 
capacity, design working pressure of separators, flare scrubbers, 
treaters, storage tanks, compressors, pipeline pumps, metering devices, 
and other hydrocarbon-handling vessels.
    (2) A schematic piping flow diagram (API RP 14C, Figure E, 
incorporated by reference as specified in Sec. 250.198) and the related 
Safety analysis Function Evaluation chart (API RP 14C, subsection 4.3c, 
incorporated by reference as specified in Sec. 250.198).
    (3) A schematic piping diagram showing the size and maximum 
allowable working pressures as determined in accordance with API RP 14E, 
Design and Installation of Offshore Production Platform Piping Systems 
(incorporated by reference as specified in Sec. 250.198).
    (4) Electrical system information including the following:
    (i) A plan for each platform deck outlining all hazardous areas 
classified according to API RP 500, Recommended Practice for 
Classification of Locations for Electrical Installations at Petroleum 
Facilities Classified as Class I, Division 1 and Division 2, or API RP 
505, Recommended Practice for Classification of Locations for Electrical 
Installations at Petroleum Facilities Classified as Class I, Zone 0, 
Zone 1, and Zone 2 (incorporated by reference as specified in Sec. 
250.198), and outlining areas in which potential ignition sources, other 
than electrical, are to be installed. The area outlined will include the 
following information:
    (A) All major production equipment, wells, and other significant 
hydrocarbon sources and a description of the type of decking, ceiling, 
walls (e.g., grating or solid) and firewalls; and
    (B) Location of generators, control rooms, panel boards, major 
cabling/conduit routes, and identification of the primary wiring method 
(e.g., type cable, conduit, or wire).
    (ii) Elementary electrical schematic of any platform safety shut-
down system with a functional legend.
    (5) Certification that the design for the mechanical and electrical 
systems to be installed were approved by registered professional 
engineers. After these systems are installed, the lessee shall submit a 
statement to the District Manager certifying that new installations 
conform to the approved designs of this subpart.
    (6) The design and schematics of the installation and maintenance of 
all fire- and gas-detection systems shall include the following:
    (i) Type, location, and number of detection sensors;
    (ii) Type and kind of alarms, including emergency equipment to be 
activated;
    (iii) Method used for detection;
    (iv) Method and frequency of calibration; and
    (v) A functional block diagram of the detection system, including 
the electric power supply.
    (7) The service fee listed in Sec. 250.125. The fee you must pay 
will be determined by the number of components

[[Page 381]]

involved in the review and approval process.

[53 FR 10690, Apr. 1, 1988, as amended at 61 FR 60024, Nov. 26, 1996. 
Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 65 FR 219, 
Jan. 4, 2000; 67 FR 51759, Aug. 9, 2002; 71 FR 40912, July 19, 2006; 72 
FR 12096, Mar. 15, 2007; 72 FR 25201, May 4, 2007]



Sec. 250.803  Additional production system requirements.

    (a) For all production platforms, you must comply with the following 
production safety system requirements, in addition to the requirements 
of Sec. 250.802 of this subpart and the requirements of API RP 14C 
(incorporated by reference as specified in 30 CFR 250.198).
    (b) Design, installation, and operation of additional production 
systems--(1) Pressure and fired vessels. Pressure and fired vessels must 
be designed, fabricated, and code stamped in accordance with the 
applicable provisions of Sections I, IV, and VIII of the American 
Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code. 
Pressure and fired vessels must have maintenance inspection, rating, 
repair, and alteration performed in accordance with the applicable 
provisions of API Pressure Vessel Inspection Code: In-Service 
Inspection, Rating, Repair, and Alteration, API 510 (except Sections 6.5 
and 8.5) (incorporated by reference as specified in Sec. 250.198).
    (i) Pressure relief valves shall be designed, installed, and 
maintained in accordance with applicable provisions of sections I, IV, 
and VIII of the ASME Boiler and Pressure Vessel Code. The relief valves 
shall conform to the valve-sizing and pressure-relieving requirements 
specified in these documents; however, the relief valves, except 
completely redundant relief valves, shall be set no higher than the 
maximum-allowable working pressure of the vessel. All relief valves and 
vents shall be piped in such a way as to prevent fluid from striking 
personnel or ignition sources.
    (ii) Steam generators operating at less than 15 pounds per square 
inch gauge (psig) shall be equipped with a level safety low (LSL) sensor 
which will shut off the fuel supply when the water level drops below the 
minimum safe level. Steam generators operating at greater than 15 psig 
require, in addition to an LSL, a water-feeding device which will 
automatically control the water level.
    (iii) The lessee shall use pressure recorders to establish the new 
operating pressure ranges of pressure vessels at any time when there is 
a change in operating pressures that requires new settings for the high-
pressure shut-in sensor and/or the low-pressure shut-in sensor as 
provided herein. The pressure-recorder charts used to determine current 
operating pressure ranges shall be maintained at the lessee's field 
office nearest the OCS facility or at other locations conveniently 
available to the District Manager. The high-pressure shut-in sensor 
shall be set no higher than 15 percent or 5 psi, whichever is greater, 
above the highest operating pressure of the vessel. This setting shall 
also be set sufficiently below (5 percent or 5 psi, whichever is 
greater) the relief valve's set pressure to assure that the pressure 
source is shut in before the relief valve activates. The low-pressure 
shut-in sensor shall activate no lower than 15 percent or 5 psi, 
whichever is greater, below the lowest pressure in the operating range. 
The activation of low-pressure sensors on pressure vessels which operate 
at less than 5 psi shall be approved by the District Manager on a case-
by-case basis.
    (2) Flowlines. (i) You must equip flowlines from wells with high- 
and low-pressure shut-in sensors located in accordance with section A.1 
and Figure A1 of API RP 14C (incorporated by reference as specified in 
Sec. 250.198). The lessee shall use pressure recorders to establish the 
new operating pressure ranges of flowlines at any time when there is a 
significant change in operating pressures. The most recent pressure-
recorder charts used to determine operating pressure ranges shall be 
maintained at the lessee's field office nearest the OCS facility or at 
other locations conveniently available to the District Manager. The 
high-pressure shut-in sensor(s) shall be set no higher than 15 percent 
or 5 psi, whichever is greater, above the highest operating pressure of 
the line. But in all cases, it shall be set sufficiently below the 
maximum shut-in wellhead pressure or the

[[Page 382]]

gas-lift supply pressure to assure actuation of the SSV. The low-
pressure shut-in sensor(s) shall be set no lower than 15 percent or 5 
psi, whichever is greater, below the lowest operating pressure of the 
line in which it is installed.
    (ii) If a well flows directly to the pipeline before separation, the 
flowline and valves from the well located upstream of and including the 
header inlet valve(s) shall have a working pressure equal to or greater 
than the maximum shut-in pressure of the well unless the flowline is 
protected by one of the following:
    (A) A relief valve which vents into the platform flare scrubber or 
some other location approved by the District Manager. The platform flare 
scrubber shall be designed to handle, without liquid-hydrocarbon 
carryover to the flare, the maximum-anticipated flow of liquid 
hydrocarbons which may be relieved to the vessel.
    (B) Two SSV's with independent high-pressure sensors installed with 
adequate volume upstream of any block valve to allow sufficient time for 
the valve(s) to close before exceeding the maximum allowable working 
pressure.
    (iii) If you are installing flowlines constructed of unbonded 
flexible pipe on a floating platform, you must:
    (A) Review the manufacturer's Design Methodology Verification Report 
and the independent verification agent's (IVA's) certificate for the 
design methodology contained in that report to ensure that the 
manufacturer has complied with the requirements of API Spec 17J 
(incorporated by reference as specified in 30 CFR 250.198);
    (B) Determine that the unbonded flexible pipe is suitable for its 
intended purpose on the lease or pipeline right-of-way;
    (C) Submit to the MMS District Manager the manufacturer's design 
specifications for the unbonded flexible pipe; and
    (D) Submit to the MMS District Manager a statement certifying that 
the pipe is suitable for its intended use and that the manufacturer has 
complied with the IVA requirements of API Spec 17J (incorporated by 
reference as specified in 30 CFR 250.198).
    (3) Safety sensors. All shutdown devices, valves, and pressure 
sensors shall function in a manual reset mode. Sensors with integral 
automatic reset shall be equipped with an appropriate device to override 
the automatic reset mode. All pressure sensors shall be equipped to 
permit testing with an external pressure source.
    (4) ESD. The ESD must conform to the requirements of Appendix C, 
section C1, of API RP 14C (incorporated by reference as specified in 
Sec. 250.198), and the following:
    (i) The manually operated ESD valve(s) shall be quick-opening and 
nonrestricted to enable the rapid actuation of the shutdown system. Only 
ESD stations at the boat landing may utilize a loop of breakable 
synthetic tubing in lieu of a valve.
    (ii) Closure of the SSV shall not exceed 45 seconds after automatic 
detection of an abnormal condition or actuation of an ESD. The surface-
controlled SSSV shall close in not more than 2 minutes after the shut-in 
signal has closed the SSV. Design-delayed closure time greater than 2 
minutes shall be justified by the lessee based on the individual well's 
mechanical/production characteristics and be approved by the District 
Manager.
    (iii) A schematic of the ESD which indicates the control functions 
of all safety devices for the platforms shall be maintained by the 
lessee on the platform or at the lessee's field office nearest the OCS 
facility or other location conveniently available to the District 
Manager.
    (5) Engines--(i) Engine exhaust. You must equip engine exhausts to 
comply with the insulation and personnel protection requirements of API 
RP 14C, section 4.2c(4) (incorporated by reference as specified in Sec. 
250.198). Exhaust piping from diesel engines must be equipped with spark 
arresters.
    (ii) Diesel engine air intake. No later than May 31, 1989, diesel 
engine air intakes shall be equipped with a device to shutdown the 
diesel engine in the event of runaway. Diesel engines which are 
continuously attended shall be equipped with either remote operated

[[Page 383]]

manual or automatic shutdown devices. Diesel engines which are not 
continuously attended shall be equipped with automatic shutdown devices.
    (6) Glycol dehydration units. A pressure relief system or an 
adequate vent shall be installed on the glycol regenerator (reboiler) 
which will prevent overpressurization. The discharge of the relief valve 
shall be vented in a nonhazardous manner.
    (7) Gas compressors. You must equip compressor installations with 
the following protective equipment as required in API RP 14C, Sections 
A4 and A8 (incorporated by reference as specified in Sec. 250.198).
    (i) A Pressure Safety High (PSH), a Pressure Safety Low (PSL), a 
Pressure Safety Valve (PSV), and a Level Safety High (LSH), and an LSL 
to protect each interstage and suction scrubber.
    (ii) A Temperature Safety High (TSH) on each compressor discharge 
cylinder.
    (iii) The PSH and PSL shut-in sensors and LSH shut-in controls 
protecting compressor suction and interstage scrubbers shall be 
designated to actuate automatic shutdown valves (SDV) located in each 
compressor suction and fuel gas line so that the compressor unit and the 
associated vessels can be isolated from all input sources. All automatic 
SDV's installed in compressor suction and fuel gas piping shall also be 
actuated by the shutdown of the prime mover. Unless otherwise approved 
by the District Manager, gas--well gas affected by the closure of the 
automatic SDV on a compressor suction shall be diverted to the pipeline 
or shut in at the wellhead.
    (iv) A blowdown valve is required on the discharge line of all 
compressor installations of 1,000 horsepower (746 kilowatts) or greater.
    (8) Firefighting systems. Firefighting systems for both open and 
totally enclosed platforms installed for extreme weather conditions or 
other reasons shall conform to subsection 5.2, Firewater systems, of API 
RP 14G, Fire Prevention and Control Open Type Offshore Production 
Platforms, and shall require approval of the District Manager. The 
following additional requirements shall apply for both open- and closed-
production platforms:
    (i) A firewater system consisting of rigid pipe with firehose 
stations or fixed firewater monitors shall be installed. The firewater 
system shall be installed to provide needed protection in all areas 
where production-handling equipment is located. A fixed waterspray 
system shall be installed in enclosed well-bay areas where hydrocarbon 
vapors may accumulate.
    (ii) Fuel or power for firewater pump drivers shall be available for 
at least 30 minutes of run time during a platform shut-in. If necessary, 
an alternate fuel or power supply shall be installed to provide for this 
pump-operating time unless an alternate firefighting system has been 
approved by the District Manager.
    (iii) A firefighting system using chemicals may be used in lieu of a 
water system if the District Manager determines that the use of a 
chemical system provides equivalent fire-protection control.
    (iv) A diagram of the firefighting system showing the location of 
all firefighting equipment shall be posted in a prominent place on the 
facility or structure.
    (v) For operations in subfreezing climates, the lessee shall furnish 
evidence to the District Manager that the firefighting system is 
suitable for the conditions.
    (9) Fire- and gas-detection system. (i) Fire (flame, heat, or smoke) 
sensors shall be installed in all enclosed classified areas. Gas sensors 
shall be installed in all inadequately ventilated, enclosed classified 
areas. Adequate ventilation is defined as ventilation which is 
sufficient to prevent accumulation of significant quantities of vapor-
air mixture in concentrations over 25 percent of the lower explosive 
limit (LEL). One approved method of providing adequate ventilation is a 
change of air volume each 5 minutes or 1 cubic foot of air-volume flow 
per minute per square foot of solid floor area, whichever is greater. 
Enclosed areas (e.g., buildings, living quarters, or doghouses) are 
defined as those areas confined on more than four of their six possible 
sides by walls, floors, or ceilings more restrictive to air flow than 
grating or fixed open louvers and

[[Page 384]]

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 Manager may require the installation and 
maintenance of a gas detector or alarm in any potentially hazardous 
area.
    (v) Fire- and gas-detection systems must be an approved type, 
designed and installed according to API RP 14C, API RP 14G, and either 
API RP 14F or API RP 14FZ (the preceding four documents incorporated by 
reference as specified in Sec. 250.198).
    (10) Electrical equipment. Electrical equipment and systems shall be 
designed, installed, and maintained in accordance with the requirements 
in Sec. 250.114 of this part.
    (11) Erosion. A program of erosion control shall be in effect for 
wells or fields having a history of sand production. The erosion-control 
program may include sand probes, X-ray, ultrasonic, or other 
satisfactory monitoring methods. Records by lease, indicating the wells 
which have erosion-control programs in effect and the results of the 
programs, shall be maintained by the lessee for a period of 2 years and 
shall be made available to MMS upon request.
    (c) General platform operations. (1) Surface or subsurface safety 
devices shall not be bypassed or blocked out of service unless they are 
temporarily out of service for startup, maintenance, or testing 
procedures. Only the minimum number of safety devices shall be taken out 
of service. Personnel shall monitor the bypassed or blocked-out 
functions until the safety devices are placed back in service. Any 
surface or subsurface safety device which is temporarily out of service 
shall be flagged.
    (2) When wells are disconnected from producing facilities and blind 
flanged, equipped with a tubing plug, or the master valves have been 
locked closed, you are not required to comply with the provisions of API 
RP 14C (incorporated by reference as specified in Sec. 250.198) or this 
regulation concerning the following:
    (i) Automatic fail-close SSV's on wellhead assemblies, and
    (ii) The PSH and PSL shut-in sensors in flowlines from wells.
    (3) When pressure or atmospheric vessels are isolated from 
production facilities (e.g., inlet valve locked closed or inlet blind-
flanged) and are to remain isolated for an extended period of time, 
safety device compliance with API RP 14C or this subpart is not 
required.
    (4) All open-ended lines connected to producing facilities and wells 
shall be plugged or blind-flanged, except those lines designed to be 
open-ended such as flare or vent lines.
    (d) Welding and burning practices and procedures. All welding, 
burning, and hot-tapping activities shall be conducted according to the 
specific requirements in Sec. Sec. 250.109 through 250.113 of this 
part.

[53 FR 10690, Apr. 1, 1988; 53 FR 12227, Apr. 13, 1988, as amended at 55 
FR 47753, Nov. 15, 1990; 61 FR 60025, Nov. 26, 1996. Redesignated and 
amended at 63 FR 29479, 29485, May 29, 1998; 65 FR 219, Jan. 4, 2000; 67 
FR 51759, Aug. 9, 2002; 68 FR 43298, July 22, 2003; 68 FR 65172, Nov. 
19, 2003; 70 FR 7403, Feb. 14, 2005; 70 FR 41575, July 19, 2005; 72 FR 
12096, Mar. 15, 2007]



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 must be in accordance with API RP 14C, Appendix D (incorporated 
by reference as specified in Sec. 250.198), and the following:

[[Page 385]]

    (1) Testing requirements for subsurface safety devices are as 
follows:
    (i) Each surface-controlled subsurface safety device installed in a 
well, including such devices in shut-in and injection wells, shall be 
tested in place for proper operation when installed or reinstalled and 
thereafter at intervals not exceeding 6 months. If the device does not 
operate properly, or if a liquid leakage rate in excess of 200 cubic 
centimeters per minute or a gas leakage rate in excess of 5 cubic feet 
per minute is observed, the device shall be removed, repaired and 
reinstalled, or replaced. Testing shall be in accordance with API RP 14B 
to ensure proper operation.
    (ii) Each subsurface-controlled SSSV installed in a well shall be 
removed, inspected, and repaired or adjusted, as necessary, and 
reinstalled or replaced at intervals not exceeding 6 months for those 
valves not installed in a landing nipple and 12 months for those valves 
installed in a landing nipple.
    (iii) Each tubing plug installed in a well shall be inspected for 
leakage by opening the well to possible flow at intervals not exceeding 
6 months. If a liquid leakage rate in excess of 200 cubic centimeters 
per minute or a gas leakage rate in excess of 5 cubic feet per minute is 
observed, the device shall be removed, repaired and reinstalled, or 
replaced. An additional tubing plug may be installed in lieu of removal.
    (iv) Injection valves shall be tested in the manner as outlined for 
testing tubing plugs in paragraph (a)(1)(iii) of this section. Leakage 
rates outlined in paragraph (a)(1)(iii) of this section shall apply.
    (2) All PSV's shall be tested for operation at least once every 12 
months. These valves shall be either bench-tested or equipped to permit 
testing with an external pressure source. Weighted disk vent valves used 
as PSV's on atmospheric tanks may be disassembled and inspected in lieu 
of function testing.
    (3) The following safety devices (excluding electronic pressure 
transmitters and level sensors) must be tested at least once each 
calendar month, but at no time will more than 6 weeks elapse between 
tests:
    (i) All PSH and PSL,
    (ii) All LSH and LSL controls,
    (iii) All automatic inlet SDV's which are actuated by a sensor on a 
vessel or compressor, and
    (iv) All SDV's in liquid discharge lines and actuated by vessel low-
level sensors.
    (4) The following electronic pressure transmitters and level sensors 
must be tested at least once every 3 months, but at no time may more 
than 120 days elapse between tests:
    (i) All PSH and PSL, and
    (ii) All LSH and LSL controls.
    (5) All SSV's and USV's shall be tested for operation and for 
leakage at least once each calendar month, but at no time shall more 
than 6 weeks elapse between tests. The SSV's and USV's must be tested in 
accordance with the test procedures specified in API RP 14H 
(incorporated by reference as specified in Sec. 250.198). If the SSV or 
USV does not operate properly or if any fluid flow is observed during 
the leakage test, the valve shall be repaired or replaced.
    (6) All flowline Flow Safety Valves (FSV) shall be checked for 
leakage at least once each calendar month, but at no time shall more 
than 6 weeks elapse between tests. The FSV's must be tested for leakage 
in accordance with the test procedures specified in API RP 14C, Appendix 
D, section D4, table D2, subsection D (incorporated by reference as 
specified in Sec. 250.198). If the leakage measured exceeds a liquid 
flow of 200 cubic centimeters per minute or a gas flow of 5 cubic feet 
per minute, the FSV's shall be repaired or replaced.
    (7) The TSH shutdown controls installed on compressor installations 
which can be nondestructively tested shall be tested every 6 months and 
repaired or replaced as necessary.
    (8) All pumps for firewater systems shall be inspected and operated 
weekly.
    (9) All fire- (flame, heat, or smoke) detection systems shall be 
tested for operation and recalibrated every 3 months provided that 
testing can be performed in a nondestructive manner. Open flame or 
devices operating at temperatures which could ignite a methane-air 
mixture shall not be used. All combustible gas-detection systems shall 
be calibrated every 3 months.
    (10) All TSH devices shall be tested at least once every 12 months, 
excluding

[[Page 386]]

those addressed in paragraph (a)(7) of this section and those which 
would be destroyed by testing. Burner safety low and flow safety low 
devices shall also be tested at least once every 12 months.
    (11) The ESD shall be tested for operation at least once each 
calendar month, but at no time shall more than 6 weeks elapse between 
tests. The test shall be conducted by alternating ESD stations monthly 
to close at least one wellhead SSV and verify a surface-controlled SSSV 
closure for that well as indicated by control circuitry actuation.
    (12) Prior to the commencement of production, the lessee shall 
notify the District Manager when the lessee is ready to conduct a 
preproduction test and inspection of the integrated safety system. The 
lessee shall also notify the District Manager upon commencement of 
production in order that a complete inspection may be conducted.
    (b) Records. The lessee shall maintain records for a period of 2 
years for each subsurface and surface safety device installed. These 
records shall be maintained by the lessee at the lessee's field office 
nearest the OCS facility or other locations conveniently available to 
the District Manager. These records shall be available for review by a 
representative of MMS. The records shall show the present status and 
history of each device, including dates and details of installation, 
removal, inspection, testing, repairing, adjustments, and 
reinstallation.

[53 FR 10690, Apr. 1, 1988, as amended at 55 FR 47753, Nov. 15, 1990; 62 
FR 5331, Feb. 5, 1997. Redesignated at 63 FR 29479, May 29, 1998, as 
amended at 65 FR 35824, June 6, 2000; 67 FR 51760, Aug. 9, 2002; 68 FR 
47, Jan. 2, 2003]



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
    (ii) API Spec Q1, Specification for Quality Programs for the 
Petroleum, Petrochemical and Natural Gas Industry (incorporated by 
reference as specified in Sec. 250.198).
    (3) All SSV's and USV's must meet the technical specifications of 
API Spec 6A and 6AV1. All SSSVs must meet the technical specifications 
of API Specification 14A.
    (4) For information on all standards mentioned in this section, see 
Sec. 250.198.
    (b) Use of noncertified SPPE. (1) Before April 1, 1998, you may 
continue to use and install noncertified SPPE if it was in your 
inventory as of April 1, 1988, and was included in a list of 
noncertified SPPE submitted to MMS prior to August 29, 1988.
    (2) On or after April 1, 1998:
    (i) You may not install additional noncertified SPPE; and
    (ii) When noncertified SPPE that is already in service requires 
offsite repair, remanufacturing, or hot work such as welding, you must 
replace it with certified SPPE.
    (c) Recognizing other quality assurance programs. The MMS will 
consider recognizing other quality assurance programs covering the 
manufacture of SPPE. If you want MMS to evaluate other quality assurance 
programs, submit relevant information about the program and reasons for 
recognition by

[[Page 387]]

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; 65 FR 76935, Dec. 8, 2000; 72 
FR 12096, Mar. 15, 2007]



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. 250.490 of this part, shall be conducted in 
accordance with that section and other relevant requirements of subpart 
H, Production Safety Systems.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998; 68 FR 8435, Feb. 20, 2003]



                   Subpart I_Platforms and Structures

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

                   General Requirements for Platforms



Sec. 250.900  What general requirements apply to all platforms?

    (a) You design, fabricate, install, use, maintain, inspect, and 
assess all platforms and related structures on the Outer Continental 
Shelf (OCS) so as to ensure their structural integrity for the safe 
conduct of drilling, workover, and production operations. In doing this, 
you must consider the specific environmental conditions at the platform 
location.
    (b) You must also submit an application under Sec. 250.905 of this 
subpart and obtain the approval of the Regional Supervisor before 
performing any of the activities described in the following table:

------------------------------------------------------------------------
  Activity requiring application and      Conditions for conducting the
               approval                             activity
------------------------------------------------------------------------
(1) Install a platform. This includes   (i) You must adhere to the
 placing a newly constructed platform    requirements of this subpart,
 at a location or moving an existing     including the industry
 platform to a new site.                 standards in Sec.  250.901.
                                        (ii) If you are installing a
                                         floating platform, you must
                                         also adhere to U.S. Coast Guard
                                         (USCG) regulations for the
                                         fabrication, installation, and
                                         inspection of floating OCS
                                         facilities.
(2) Major modification to any           (i) You must adhere to the
 platform. This includes any             requirements of this subpart,
 structural changes that materially      including the industry
 alter the approved plan or cause a      standards in Sec.  250.901.
 major deviation from approved          (ii) Before you make a major
 operations and any modification that    modification to a floating
 increases loading on a platform by 10   platform, you must obtain
 percent or more.                        approval from both the MMS and
                                         the USCG for the modification.
(3) Major repair of damage to any       (i) You must adhere to the
 platform. This includes any             requirements of this subpart,
 corrective operations involving         including the industry
 structural members affecting the        standards in Sec.  250.901.
 structural integrity of a portion or   (ii) Before you make a major
 all of the platform.                    repair to a floating platform,
                                         you must obtain approval from
                                         both the MMS and the USCG for
                                         the repair.
(4) Convert an existing platform at     (i) The Regional Supervisor will
 the current location for a new          determine on a case-by-case
 purpose.                                basis the requirements for an
                                         application for conversion of
                                         an existing platform at the
                                         current location.
                                        (ii) At a minimum, your
                                         application must include: the
                                         converted platform's intended
                                         use; and a demonstration of the
                                         adequacy of the design and
                                         structural condition of the
                                         converted platform.
                                        (iii) If a floating platform,
                                         you must also adhere to USCG
                                         regulations for the
                                         fabrication, installation, and
                                         inspection of floating OCS
                                         facilities.
(5) Convert an existing mobile          (i) The Regional Supervisor will
 offshore drilling unit (MODU) for a     determine on a case-by-case
 new purpose.                            basis the requirements for an
                                         application for conversion of
                                         an existing MODU.
                                        (ii) At a minimum, your
                                         application must include: the
                                         converted MODU's intended
                                         location and use; a
                                         demonstration of the adequacy
                                         of the design and structural
                                         condition of the converted
                                         MODU; and a demonstration that
                                         the level of safety for the
                                         converted MODU is at least
                                         equal to that of re-used
                                         platforms.
                                        (iii) You must also adhere to
                                         USCG regulations for the
                                         fabrication, installation, and
                                         inspection of floating OCS
                                         facilities.
------------------------------------------------------------------------

    (c) Under emergency conditions, you may make repairs to primary 
structural elements to restore an existing

[[Page 388]]

permitted condition without an application or prior approval. You must 
notify the Regional Supervisor of the damage that occurred within 24 
hours, and you must notify the Regional Supervisor of the repairs that 
were made within 24 hours of completing the repairs. If you make 
emergency repairs on a floating platform, you must also notify the USCG.
    (d) You must determine if your new platform or major modification to 
an existing platform is subject to the Platform Verification Program 
(PVP). Section 250.910 of this subpart fully describes the facilities 
that are subject to the PVP. If you determine that your platform is 
subject to the PVP, you must follow the requirements of Sec. Sec. 
250.909-250.918 of this subpart.
    (e) MMS will cancel your approved platform installation permits one 
year after the approval is granted if the platform is not installed. If 
MMS cancels your permit approval, you must resubmit your application.

[70 FR 41575, July 19, 2005; 71 FR 16859, Apr. 4, 2006]



Sec. 250.901  What industry standards must your platform meet?

    (a) In addition to the other requirements of this subpart, your 
plans for platform design, analysis, fabrication, installation, use, 
maintenance, inspection and assessment must, as appropriate, conform to:
    (1) American Concrete Institute (ACI) Standard 318, Building Code 
Requirements for Reinforced Concrete, plus Commentary, (incorporated by 
reference as specified in Sec. 250.198);
    (2) ACI 357R, Guide for the Design and Construction of Fixed 
Offshore Concrete Structures, (incorporated by reference as specified in 
Sec. 250.198);
    (3) ANSI/AISC 360-05, Specification for Structural Steel Buildings, 
(incorporated by reference as specified in Sec. 250.198);
    (4) American Petroleum Institute (API) Recommended Practice (RP) 
2A--WSD, Recommended Practice for Planning, Designing, and Constructing 
Fixed Offshore Platforms-Working Stress Design, (incorporated by 
reference as specified in Sec. 250.198);
    (5) API RP 2FPS, Recommended Practice for Planning, Designing, and 
Constructing Floating Production Systems, (incorporated by reference as 
specified in Sec. 250.198);
    (6) API RP 2RD, Design of Risers for Floating Production Systems 
(FPSs) and Tension-Leg Platforms (TLPs), (incorporated by reference as 
specified in Sec. 250.198);
    (7) API RP 2SK, Recommended Practice for Design and Analysis of 
Station Keeping Systems for Floating Structures, (incorporated by 
reference as specified in Sec. 250.198);
    (8) API RP 2SM, Recommended Practice for Design, Manufacture, 
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore 
Mooring, (incorporated by reference as specified in Sec. 250.198);
    (9) API RP 2T, Recommended Practice for Planning, Designing and 
Constructing Tension Leg Platforms, (incorporated by reference as 
specified in Sec. 250.198);
    (10) API RP 14J, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities, (incorporated by reference 
as specified in Sec. 250.198);
    (11) American Society for Testing and Materials (ASTM) Standard C 
33-99a, Standard Specification for Concrete Aggregates, (incorporated by 
reference as specified in Sec. 250.198);
    (12) ASTM Standard C 94/C 94M-99, Standard Specification for Ready-
Mixed Concrete, (incorporated by reference as specified in Sec. 
250.198);
    (13) ASTM Standard C 150-99, Standard Specification for Portland 
Cement, (incorporated by reference as specified in Sec. 250.198);
    (14) ASTM Standard C 330-99, Standard Specification for Lightweight 
Aggregates for Structural Concrete, (incorporated by reference as 
specified in Sec. 250.198);
    (15) ASTM Standard C 595-98, Standard Specification for Blended 
Hydraulic Cements, (incorporated by reference as specified in Sec. 
250.198);
    (16) AWS D1.1, Structural Welding Code--Steel, including Commentary, 
(incorporated by reference as specified in Sec. 250.198);
    (17) AWS D1.4, Structural Welding Code--Reinforcing Steel, 
(incorporated by reference as specified in Sec. 250.198);

[[Page 389]]

    (18) AWS D3.6M, Specification for Underwater Welding, (incorporated 
by reference as specified in Sec. 250.198);
    (19) NACE Standard MR0175, Sulfide Stress Cracking Resistant 
Metallic Materials for Oilfield Equipment, (incorporated by reference as 
specified in Sec. 250.198);
    (20) NACE Standard RP 01-76-94, Standard RP, Corrosion Control of 
Steel Fixed Offshore Platforms Associated with Petroleum Production, 
(incorporated by reference as specified in Sec. 250.198).
    (b) You must follow the requirements contained in the documents 
listed under paragraph (a) of this section insofar as they do not 
conflict with other provisions of 30 CFR Part 250. You may use 
applicable provisions of these documents, as approved by the Regional 
Supervisor, for the design, fabrication, and installation of platforms 
such as spars, since standards specifically written for such structures 
do not exist. You may also use alternative codes, rules, or standards, 
as approved by the Regional Supervisor, under the conditions enumerated 
in Sec. 250.141.
    (c) For information on the standards mentioned in this section, and 
where they may be obtained, see Sec. 250.198 of this part.
    (d) The following chart summarizes the applicability of the industry 
standards listed in this section for fixed and floating platforms:

------------------------------------------------------------------------
            Industry standard                   Applicable to . . .
------------------------------------------------------------------------
ACI Standard 318, Building Code            Fixed and floating platform,
 Requirements for Reinforced Concrete,      as appropriate.
 Plus Commentary;.
AISC Standard Specification for
 Structural Steel Buildings, Allowable
 Stress Design and Plastic Design;.
ASTM Standard C33-99a, Standard
 Specification for Concrete Aggregates;.
ASTM Standard C94/C94M-99, Standard
 Specification for Ready-Mixed Concrete;.
ASTM Standard C150-99, Standard
 Specification for Portland Cement;.
ASTM Standard C330-99, Standard
 Specification for Lightweight Aggregates
 for Structural Concrete;.
ASTM Standard C 595-98, Standard
 Specification for Blended Hydraulic
 Cements;.
AWS D1.1, Structural Welding Code--Steel;
AWS D1.4, Structural Welding Code--
 Reinforcing Steel;.
AWS D3.6M, Specification for Underwater
 Welding;.
NACE Standard RP 01-76-94, Standard
 Recommended Practice (RP), Corrosion
 Control of Steel Fixed Offshore
 Platforms Associated with Petroleum
 Production;.
API RP 2A--WSD, RP for Planning,
 Designing, and Constructing Fixed
 Offshore Platforms--Working Stress
 Design;.
ACI357R, Guide for the Design and          Fixed platforms.
 Construction of Fixed Offshore Concrete
 Structures;.
API RP 14J, RP for Design and Hazards      Floating platforms.
 Analysis for Offshore Production
 Facilities;.
API RP 2FPS, RP for Planning, Designing,
 and Constructing, Floating Production
 Systems;.
API RP 2RD, Design of Risers for Floating
 Production Systems (FPSs) and Tension-
 Leg Platforms (TLPs);.
API RP 2SK, RP for Design and Analysis of
 Station Keeping Systems for Floating
 Structures;.
API RP 2T, RP for Planning, Designing,
 and Constructing Tension Leg Platforms;.
API RP 2SM, RP for Design, Manufacture,
 Installation, and Maintenance of
 Synthetic Fiber Ropes for Offshore
 Mooring.
------------------------------------------------------------------------


[70 FR 41575, July 19, 2005, as amended at 72 FR 12096, Mar. 15, 2007]



Sec. 250.902  What are the requirements for platform removal and location 

clearance?

    You must remove all structures according to Sec. Sec. 250.1725 
through 250.1730 of Subpart Q--Decommissioning Activities of this part.



Sec. 250.903  What records must I keep?

    (a) You must compile, retain, and make available to MMS 
representatives for the functional life of all platforms:
    (1) The as-built drawings;
    (2) The design assumptions and analyses;
    (3) A summary of the fabrication and installation nondestructive 
examination records;
    (4) The inspection results from the inspections required by Sec. 
250.919 of this subpart; and
    (5) Records of repairs not covered in the inspection report 
submitted under Sec. 250.919(b).
    (b) You must record and retain the original material test results of 
all primary structural materials during all

[[Page 390]]

stages of construction. Primary material is material that, should it 
fail, would lead to a significant reduction in platform safety, 
structural reliability, or operating capabilities. Items such as steel 
brackets, deck stiffeners and secondary braces or beams would not 
generally be considered primary structural members (or materials).
    (c) You must provide MMS with the location of these records in the 
certification statement of your application for platform approval as 
required in Sec. 250.905(j).

                        Platform Approval Program



Sec. 250.904  What is the Platform Approval Program?

    (a) The Platform Approval Program is the MMS basic approval process 
for platforms on the OCS. The requirements of the Platform Approval 
Program are described in Sec. Sec. 250.904 through 250.908 of this 
subpart. Completing these requirements will satisfy MMS criteria for 
approval of fixed platforms of a proven design that will be placed in 
the shallow water areas (<= 400 ft.) of the Gulf of Mexico OCS.
    (b) The requirements of the Platform Approval Program must be met by 
all platforms on the OCS. Additionally, if you want approval for a 
floating platform; a platform of unique design; or a platform being 
installed in deepwater ( 400 ft.) or a frontier area, you 
must also meet the requirements of the Platform Verification Program. 
The requirements of the Platform Verification Program are described in 
Sec. Sec. 250.909 through 250.918 of this subpart.



Sec. 250.905  How do I get approval for the installation, modification, or 

repair of my platform?

    The Platform Approval Program requires that you submit the 
information, documents, and fee listed in the following table for your 
proposed project.

------------------------------------------------------------------------
       Required submittal          Required contents  Other requirements
------------------------------------------------------------------------
(a) Application cover letter....  Proposed structure  You must submit
                                   designation,        three copies. If,
                                   lease number,       your facility is
                                   area, name, and     subject to the
                                   block number, and   Platform
                                   the type of         Verficiation
                                   facility your       Program (PVP),
                                   facility (e.g.,     you must submit
                                   drilling,           four copies.
                                   production,
                                   quarters). The
                                   structure
                                   designation must
                                   be unique for the
                                   field (some
                                   fields are made
                                   up of several
                                   blocks); i.e.
                                   once a platform
                                   ``A'' has been
                                   used in the field
                                   there should
                                   never be another
                                   platform ``A''
                                   even if the old
                                   platform ``A''
                                   has been removed.
                                   Single well free
                                   standing caissons
                                   should be given
                                   the same
                                   designation as
                                   the well. All
                                   other structures
                                   are to be
                                   designated by
                                   letter
                                   designations.
(b) Location plat...............  Latitude and        Your plat must be
                                   longitude           drawn to a scale
                                   coordinates,        of 1 inch equals
                                   Universal           2,000 feet and
                                   Mercator grid-      include the
                                   system              coordinates of
                                   coordinates,        the lease block
                                   state plane         boundary lines.
                                   coordinates in      You must submit
                                   the Lambert or      three
                                   Transverse
                                   Mercator
                                   Projection
                                   System, and
                                   distances in feet
                                   from the nearest
                                   block lines.
                                   These coordinates
                                   must be based on
                                   the NAD (North
                                   American Datum)
                                   27 datum plane
                                   coordinate system.
(c) Front, Side, and Plan View    Platform            Your drawing sizes
 drawings.                         dimensions and      must not exceed
                                   orientation,        11 x
                                   elevations          17.
                                   relative to         You must submit
                                   M.L.L.W. (Mean      three copies
                                   Lower Low Water),   (four copies for
                                   and pile sizes      PVP
                                   and penetration.    applications).
(d) Complete set of structural    The approved for    Your drawing sizes
 drawings.                         construction        must not exceed
                                   fabrication         11 x
                                   drawings should     17.
                                   be submitted        You must submit
                                   including; e.g.,    one copy.
                                   cathodic
                                   protection
                                   systems; jacket
                                   design; pile
                                   foundations;
                                   drilling,
                                   production, and
                                   pipeline risers
                                   and riser
                                   tensioning
                                   systems; turrets
                                   and turret-and-
                                   hull interfaces;
                                   mooring and
                                   tethering
                                   systems;
                                   foundations and
                                   anchoring systems.
(e) Summary of environmental      A summary of the    You must submit
 data.                             environmental       one copy.
                                   data described in
                                   the applicable
                                   standards
                                   referenced under
                                   Sec.  250.901(a)
                                   of this subpart
                                   and in Sec.
                                   250.198 of
                                   Subpart A, where
                                   the data is used
                                   in the design or
                                   analysis of the
                                   platform.
                                   Examples of
                                   relevant data
                                   include
                                   information on
                                   waves, wind,
                                   current, tides,
                                   temperature, snow
                                   and ice effects,
                                   marine growth,
                                   and water depth.

[[Page 391]]

 
(f) Summary of the engineering    Loading             You must submit
 design data.                      information         one copy.
                                   (e.g., live,
                                   dead,
                                   environmental),
                                   structural
                                   information
                                   (e.g., design-
                                   life; material
                                   types; cathodic
                                   protection
                                   systems; design
                                   criteria; fatigue
                                   life; jacket
                                   design; deck
                                   design;
                                   production
                                   component design;
                                   pile foundations;
                                   drilling,
                                   production, and
                                   pipeline risers
                                   and riser
                                   tensioning
                                   systems; turrets
                                   and turret-and-
                                   hull interfaces;
                                   foundations,
                                   foundation
                                   pilings and
                                   templates, and
                                   anchoring
                                   systems; mooring
                                   or tethering
                                   systems;
                                   fabrication and
                                   installation
                                   guidelines), and
                                   foundation
                                   information
                                   (e.g., soil
                                   stability, design
                                   criteria).
(g) Project-specific studies      All studies         You must submit
 used in the platform design or    pertinent to        one copy of each
 installation.                     platform design     study.
                                   or installation,
                                   e.g.,
                                   oceanographic and/
                                   or soil reports
                                   including the
                                   overall site
                                   investigative
                                   report required
                                   in section
                                   250.906.
(h) Description of the loads      Loads imposed by    You must submit
 imposed on the facility.          jacket; decks;      one copy.
                                   production
                                   components;
                                   drilling,
                                   production, and
                                   pipeline risers,
                                   and riser
                                   tensioning
                                   systems; turrets
                                   and turret-and-
                                   hull interfaces;
                                   foundations,
                                   foundation
                                   pilings and
                                   templates, and
                                   anchoring
                                   systems; and
                                   mooring or
                                   tethering systems.
(i) A copy of the in-service      This plan is        You must submit
 inspection plan.                  described in Sec.  one copy.
                                     250.919..
(j) Certification statement.....  The following       An authorized
                                   statement: ``The    company
                                   design of this      representative
                                   structure has       must sign the
                                   been certified by   statement. You
                                   a recognized        must submit one
                                   classification      copy.
                                   society, or a
                                   registered civil
                                   or structural
                                   engineer or
                                   equivalent, or a
                                   naval architect
                                   or marine
                                   engineer or
                                   equivalent,
                                   specializing in
                                   the design of
                                   offshore
                                   structures. The
                                   certified design
                                   and as-built
                                   plans and
                                   specifications
                                   will be on file
                                   at (give
                                   location)''.
(k) Payment of the service fee    ..................  ..................
 listed in Sec.  250.125.
------------------------------------------------------------------------


[70 FR 41575, July 19, 2005, as amended at 71 FR 40912, July 19, 2006]



Sec. 250.906  What must I do to obtain approval for the proposed site of my 

platform?

    (a) Shallow hazards surveys. You must perform a high-resolution or 
acoustic-profiling survey to obtain information on the conditions 
existing at and near the surface of the seafloor. You must collect 
information through this survey sufficient to determine the presence of 
the following features and their likely effects on your proposed 
platform:
    (1) Shallow faults;
    (2) Gas seeps or shallow gas;
    (3) Slump blocks or slump sediments;
    (4) Shallow water flows;
    (5) Hydrates; or
    (6) Ice scour of seafloor sediments.
    (b) Geologic surveys. You must perform a geological survey relevant 
to the design and siting of your platform. Your geological survey must 
assess:
    (1) Seismic activity at your proposed site;
    (2) Fault zones, the extent and geometry of faulting, and 
attenuation effects of geologic conditions near your site; and
    (3) For platforms located in producing areas, the possibility and 
effects of seafloor subsidence.
    (c) Subsurface surveys. Depending upon the design and location of 
your proposed platform and the results of the shallow hazard and 
geologic surveys, the Regional Supervisor may require you to perform a 
subsurface survey. This survey will include a testing program for 
investigating the stratigraphic and engineering properties of the soil 
that may affect the foundations or anchoring systems for your facility. 
The testing program must include adequate in situ testing, boring, and 
sampling to examine all important soil and rock strata to determine its 
strength classification, deformation properties, and dynamic 
characteristics. If required to perform a subsurface survey, you must 
prepare and submit to the Regional Supervisor a summary report to 
briefly describe the results of your soil testing program,

[[Page 392]]

the various field and laboratory test methods employed, and the 
applicability of these methods as they pertain to the quality of the 
samples, the type of soil, and the anticipated design application. You 
must explain how the engineering properties of each soil stratum affect 
the design of your platform. In your explanation you must describe the 
uncertainties inherent in your overall testing program, and the 
reliability and applicability of each test method.
    (d) Overall site investigation report. You must prepare and submit 
to the Regional Supervisor an overall site investigation report for your 
platform that integrates the findings of your shallow hazards surveys 
and geologic surveys, and, if required, your subsurface surveys. Your 
overall site investigation report must include analyses of the potential 
for:
    (1) Scouring of the seafloor;
    (2) Hydraulic instability;
    (3) The occurrence of sand waves;
    (4) Instability of slopes at the platform location;
    (5) Liquifaction, or possible reduction of soil strength due to 
increased pore pressures;
    (6) Degradation of subsea permafrost layers;
    (7) Cyclic loading;
    (8) Lateral loading;
    (9) Dynamic loading;
    (10) Settlements and displacements;
    (11) Plastic deformation and formation collapse mechanisms; and
    (12) Soil reactions on the platform foundations or anchoring 
systems.



Sec. 250.907  Where must I locate foundation boreholes?

    (a) For fixed or bottom-founded platforms and tension leg platforms, 
your maximum distance from any foundation pile to a soil boring must not 
exceed 500 feet.
    (b) For deepwater floating platforms which utilize catenary or taut-
leg moorings, you must take borings at the most heavily loaded anchor 
location, at the anchor points approximately 120 and 240 degrees around 
the anchor pattern from that boring, and, as necessary, other points 
throughout the anchor pattern to establish the soil profile suitable for 
foundation design purposes.



Sec. 250.908  What are the minimum structural fatigue design requirements?

    (a) API RP 2A-WSD, Recommended Practice for Planning, Designing and 
Constructing Fixed Offshore Platforms (incorporated by reference as 
specified in 30 CFR 250.198), requires that the design fatigue life of 
each joint and member be twice the intended service life of the 
structure. When designing your platform, the following table provides 
minimum fatigue life safety factors for critical structural members and 
joints.

------------------------------------------------------------------------
              If . . .                            Then . . .
------------------------------------------------------------------------
(1) There is sufficient structural   The results of the analysis must
 redundancy to prevent catastrophic   indicate a maximum calculated life
 failure of the platform or           of twice the design life of the
 structure under consideration.       platform.
(2) There is not sufficient          The results of a fatigue analysis
 structural redundancy to prevent     must indicate a minimum calculated
 catastrophic failure of the          life or three times the design
 platform or structure.               life of the platform.
(3) The desirable degree of          The results of a fatigue analysis
 redundancy is significantly          must indicate a minimum calculated
 reduced as a result of fatigue       life of three times the design
 damage.                              life of the platform.
------------------------------------------------------------------------

    (b) The documents incorporated by reference in Sec. 250.901 may 
require larger safety factors than indicated in paragraph (a) of this 
section for some key components. When the documents incorporated by 
reference require a larger safety factor than the chart in paragraph (a) 
of this section, the requirements of the incorporated document will 
prevail.

                      Platform Verification Program



Sec. 250.909  What is the Platform Verification Program?

    The Platform Verification Program is the MMS approval process for 
ensuring that floating platforms; platforms of a new or unique design; 
platforms in seismic areas; or platforms located in

[[Page 393]]

deepwater or frontier areas meet stringent requirements for design and 
construction. The program is applied during construction of new 
platforms and major modifications of, or repairs to, existing platforms. 
These requirements are in addition to the requirements of the Platform 
Approval Program described in Sec. Sec. 250.904 through 250.908 of this 
subpart.



Sec. 250.910  Which of my facilities are subject to the Platform Verification 

Program?

    (a) All new fixed or bottom-founded platforms that meet any of the 
following five conditions are subject to the Platform Verification 
Program:
    (1) Platforms installed in water depths exceeding 400 feet (122 
meters);
    (2) Platforms having natural periods in excess of 3 seconds;
    (3) Platforms installed in areas of unstable bottom conditions;
    (4) Platforms having configurations and designs which have not 
previously been used or proven for use in the area; or
    (5) Platforms installed in seismically active areas.
    (b) All new floating platforms are subject to the Platform 
Verification Program to the extent indicated in the following table:

------------------------------------------------------------------------
              If . . .                            Then . . .
------------------------------------------------------------------------
(1) Your new floating platform is a  The entire platform is subject to
 buoyant offshore facility that       the Platform Verification Program
 does not have a ship-shaped hull.    including the following associated
                                      structures:
                                     (i) Drilling, production, and
                                      pipeline risers, and riser
                                      tensioning systems (each platform
                                      must be designed to accommodate
                                      all the loads imposed by all
                                      risers and riser does not have
                                      tensioning systems);
                                     (ii) Turrets and turret-and-hull
                                      interfaces;
                                     (iii) Foundations, foundation
                                      pilings and templates, and
                                      anchoring systems; and
                                     (iv) Mooring or tethering systems.
(2) Your new floating platform is a  Only the following structures that
 buoyant offshore facility with a     may be associated with a floating
 ship-shaped hull.                    platform are subject to the
                                      Platform Verification Program:
                                     (i) Drilling, production, and
                                      pipeline risers, and riser
                                      tensioning systems (each platform
                                      must be designed to accommodate
                                      all the loads imposed by all
                                      risers and riser tensioning
                                      systems);
                                     (ii) Turrets and turret-and-hull
                                      interfaces;
                                     (iii) Foundations, foundation
                                      pilings and templates, and
                                      anchoring systems; and
                                     (iv) Mooring or tethering systems.
------------------------------------------------------------------------

    (c) If a platform is originally subject to the Platform Verification 
Program, then the conversion of that platform at that same site for a 
new purpose, or making a major modification of, or major repair to, that 
platform, is also subject to the Platform Verification Program. A major 
modification includes any modification that increases loading on a 
platform by 10 percent or more. A major repair is a corrective operation 
involving structural members affecting the structural integrity of a 
portion or all of the platform. Before you make a major modification or 
repair to a floating platform, you must obtain approval from both the 
MMS and the USCG.
    (d) The applicability of Platform Verification Program requirements 
to other types of facilities will be determined by MMS on a case-by-case 
basis.

[70 FR 41575, July 19, 2005; 71 FR 28080, May 15, 2006]



Sec. 250.911  If my platform is subject to the Platform Verification Program, 

what must I do?

    If your platform, conversion, or major modification or repair meets 
the criteria in Sec. 250.910, you must:
    (a) Design, fabricate, install, use, maintain and inspect your 
platform, conversion, or major modification or repair to your platform 
according to the requirements of this subpart, and the applicable 
documents listed in Sec. 250.901(a) of this subpart;
    (b) Comply with all the requirements of the Platform Approval 
Program

[[Page 394]]

found in Sec. Sec. 250.904 through 250.908 of this subpart.
    (c) Submit for the Regional Supervisor's approval three copies each 
of the design verification, fabrication verification, and installation 
verification plans required by Sec. 250.912;
    (d) Include your nomination of a Certified Verification Agent (CVA) 
as a part of each verification plan required by Sec. 250.912;
    (e) Follow the additional requirements in Sec. Sec. 250.913 through 
250.918;
    (f) Obtain approval for modifications to approved plans and for 
major deviations from approved installation procedures from the Regional 
Supervisor; and
    (g) Comply with applicable USCG regulations for floating OCS 
facilities.



Sec. 250.912  What plans must I submit under the Platform Verification 

Program?

    If your platform, associated structure, or major modification meets 
the criteria in Sec. 250.910, you must submit the following plans to 
the Regional Supervisor for approval:
    (a) Design verification plan. You may submit your design 
verification plan with or subsequent to the submittal of your 
Development and Production Plan (DPP) or Development Operations 
Coordination Document (DOCD). Your design verification must be conducted 
by, or be under the direct supervision of, a registered professional 
civil or structural engineer or equivalent, or a naval architect or 
marine engineer or equivalent, with previous experience in directing the 
design of similar facilities, systems, structures, or equipment. For 
floating platforms, you must ensure that the requirements of the USCG 
for structural integrity and stability, e.g., verification of center of 
gravity, etc., have been met. Your design verification plan must include 
the following:
    (1) All design documentation specified in Sec. 250.905 of this 
subpart;
    (2) Abstracts of the computer programs used in the design process; 
and
    (3) A summary of the major design considerations and the approach to 
be used to verify the validity of these design considerations.
    (b) Fabrication verification plan. The Regional Supervisor must 
approve your fabrication verification plan before you may initiate any 
related operations. Your fabrication verification plan must include the 
following:
    (1) Fabrication drawings and material specifications for artificial 
island structures and major members of concrete-gravity and steel-
gravity structures;
    (2) For jacket and floating structures, all the primary load-bearing 
members included in the space-frame analysis; and
    (3) A summary description of the following:
    (i) Structural tolerances;
    (ii) Welding procedures;
    (iii) Material (concrete, gravel, or silt) placement methods;
    (iv) Fabrication standards;
    (v) Material quality-control procedures;
    (vi) Methods and extent of nondestructive examinations for welds and 
materials; and
    (vii) Quality assurance procedures.
    (c) Installation verification plan. The Regional Supervisor must 
approve your installation verification plan before you may initiate any 
related operations. Your installation verification plan must include:
    (1) A summary description of the planned marine operations;
    (2) Contingencies considered;
    (3) Alternative courses of action; and
    (4) An identification of the areas to be inspected. You must specify 
the acceptance and rejection criteria to be used for any inspections 
conducted during installation, and for the post-installation 
verification inspection.
    (d) You must combine fabrication verification and installation 
verification plans for manmade islands or platforms fabricated and 
installed in place.



Sec. 250.913  When must I resubmit Platform Verification Program plans?

    (a) You must resubmit any design verification, fabrication 
verification, or installation verification plan to the Regional 
Supervisor for approval if:
    (1) The CVA changes;
    (2) The CVA's or assigned personnel's qualifications change; or

[[Page 395]]

    (3) The level of work to be performed changes.
    (b) If only part of a verification plan is affected by one of the 
changes described in paragraph (a) of this section, you can resubmit 
only the affected part. You do not have to resubmit the summary of 
technical details unless you make changes in the technical details.



Sec. 250.914  How do I nominate a CVA?

    (a) As part of your design verification, fabrication verification, 
or installation verification plan, you must nominate a CVA for the 
Regional Supervisor's approval. You must specify whether the nomination 
is for the design, fabrication, or installation phase of verification, 
or for any combination of these phases.
    (b) For each CVA, you must submit a list of documents to be 
forwarded to the CVA, and a qualification statement that includes the 
following:
    (1) Previous experience in third-party verification or experience in 
the design, fabrication, installation, or major modification of offshore 
oil and gas platforms. This should include fixed platforms, floating 
platforms, manmade islands, other similar marine structures, and related 
systems and equipment;
    (2) Technical capabilities of the individual or the primary staff 
for the specific project;
    (3) Size and type of organization or corporation;
    (4) In-house availability of, or access to, appropriate technology. 
This should include computer programs, hardware, and testing materials 
and equipment;
    (5) Ability to perform the CVA functions for the specific project 
considering current commitments;
    (6) Previous experience with MMS requirements and procedures;
    (7) The level of work to be performed by the CVA.



Sec. 250.915  What are the CVA's primary responsibilities?

    (a) The CVA must conduct specified reviews according to Sec. Sec. 
250.916, 250.917, and 250.918 of this subpart.
    (b) Individuals or organizations acting as CVAs must not function in 
any capacity that would create a conflict of interest, or the appearance 
of a conflict of interest.
    (c) The CVA must consider the applicable provisions of the documents 
listed in Sec. 250.901(a); the alternative codes, rules, and standards 
approved under 250.901(b); and the requirements of this subpart.
    (d) The CVA is the primary contact with the Regional Supervisor and 
is directly responsible for providing immediate reports of all incidents 
that affect the design, fabrication and installation of the platform.



Sec. 250.916  What are the CVA's primary duties during the design phase?

    (a) The CVA must use good engineering judgement and practices in 
conducting an independent assessment of the design of the platform, 
major modification, or repair. The CVA must ensure that the platform, 
major modification, or repair is designed to withstand the environmental 
and functional load conditions appropriate for the intended service life 
at the proposed location.
    (b) Primary duties of the CVA during the design phase include the 
following:

------------------------------------------------------------------------
       Type of facility . . .                 The CVA must . . .
------------------------------------------------------------------------
(1) For fixed platforms and non-     Conduct an independent assessment
 ship-shaped floating facilities.     of all proposed:
                                     (i) Planning criteria;
                                     (ii) Operational requirements;
                                     (iii) Environmental loading data;
                                     (iv) Load determinations;
                                     (v) Stress analyses;
                                     (vi) Material designations;
                                     (vii) Soil and foundation
                                      conditions;
                                     (viii) Safety factors; and
                                     (ix) Other pertinent parameters of
                                      the proposed design.
(2)For all floating facilities.....  Ensure that the requirements of the
                                      U.S. Coast Guard for structural
                                      integrity and stability, e.g.,
                                      verification of center of gravity,
                                      etc., have been met. The CVA must
                                      also consider:

[[Page 396]]

 
                                     (i) Drilling, production, and
                                      pipeline risers, and riser
                                      tensioning systems;
                                     (ii) Turrets and turret-and-hull
                                      interfaces;
                                     (iii) Foundations, foundation
                                      pilings and templates, and
                                      anchoring systems; and
                                     (iv) Mooring or tethering systems.
------------------------------------------------------------------------

    (c) The CVA must submit interim reports to the Regional Supervisor 
and to you, as appropriate. The CVA, upon completion of the design 
verification, must prepare a final report and submit one copy to the 
Regional Supervisor. The CVA must submit the final report within 90 days 
of the receipt of the design data, or within 90 days from the date the 
approval to act as a CVA was issued, whichever is later. The CVA must 
submit the final report to the Regional Supervisor before fabrication 
begins, and must include:
    (1) A summary of the material reviewed and the CVA's findings;
    (2) The CVA's recommendation that the Regional Supervisor either 
accept, request modifications, or reject the proposed design;
    (3) The particulars of how, by whom, and when the independent review 
was conducted; and
    (4) Any additional comments the CVA may deem necessary.



Sec. 250.917  What are the CVA's primary duties during the fabrication phase?

    (a) The CVA must use good engineering judgement and practices in 
conducting an independent assessment of the fabrication activities. The 
CVA must monitor the fabrication of the platform or major modification 
to ensure that it has been built according to the approved design and 
the fabrication plan. If the CVA finds that fabrication procedures are 
changed or design specifications are modified, the CVA must inform you. 
If you accept the modifications, then the CVA must so inform the 
Regional Supervisor.
    (b) Primary duties of the CVA during the fabrication phase include 
the following:

------------------------------------------------------------------------
       Type of facility . . .                 The CVA must . . .
------------------------------------------------------------------------
(1) For all fixed platforms and non- Make periodic onsite inspections
 ship-shaped floating facilities.     while fabrication is in progress
                                      and must verify the following
                                      fabrication items, as appropriate:
                                     (i) Quality control by lessee and
                                      builder;
                                     (ii) Fabrication site facilities;
                                     (iii) Material quality and
                                      identification methods;
                                     (iv) Fabrication procedures
                                      specified in the approved plan,
                                      and adherence to such procedures;
                                     (v) Welder and welding procedure
                                      qualification and identification;
                                     (vi) Structural tolerences
                                      specified and adherence to those
                                      tolerances;
                                     (vii) The nondestructive
                                      examination requirements, and
                                      evaluation results of the
                                      specified examinations;
                                     (viii) Destructive testing
                                      requirements and results;
                                     (ix) Repair procedures;
                                     (x) Installation of corrosion-
                                      protection systems and splash-zone
                                      protection;
                                     (xi) Erection procedures to ensure
                                      that overstressing of structural
                                      members does not occur;
                                     (xii) Alignment procedures;
                                     (xiii) Dimensional check of the
                                      overall structure, including any
                                      turrets, turret-and-hull
                                      interfaces, any mooring line and
                                      chain and riser tensioning line
                                      segments; and
                                     (xiv) Status of quality-control
                                      records at various stages of
                                      fabrication.
(2) For all floating facilities....  Ensure that the requirements of the
                                      U.S. Coast Guard floating for
                                      structural integrity and
                                      stability, e.g., verification of
                                      center of gravity, etc., have been
                                      met. The CVA must also consider:

[[Page 397]]

 
                                     (i) Drilling, production, and
                                      pipeline risers, and riser
                                      tensioning systems (at least for
                                      the initial fabrication of these
                                      elements);
                                     (ii) Turrets and turret-and-hull
                                      interfaces;
                                     (iii) Foundation pilings and
                                      templates, and anchoring systems;
                                      and
                                     (iv) Mooring or tethering systems.
------------------------------------------------------------------------

    (c) Reports. The CVA must submit interim reports to the Regional 
Supervisor and to you, as appropriate. The CVA must prepare a final 
report covering the adequacy of the entire fabrication phase. The final 
report need not cover aspects of the fabrication already included in 
interim reports. The CVA must submit one copy of the final report to the 
Regional Supervisor within 90 days after completion of the fabrication 
phase but before the beginning of the installation phase. In the final 
report the CVA must:
    (1) Give details of how, by whom, and when the independent 
monitoring activities were conducted;
    (2) Describe the CVA's activities during the verification process;
    (3) Summarize the CVA's findings;
    (4) Confirm or deny compliance with the design specifications and 
the approved fabrication plan;
    (5) Make a recommendation to accept or reject the fabrication; and
    (6) Provide any additional comments that the CVA deems necessary.



Sec. 250.918  What are the CVA's primary duties during the installation 

phase?

    (a) The CVA must use good engineering judgment and practice in 
conducting an independent assessment of the installation activities.
    (b) Primary duties of the CVA during the installation phase include 
the following:

------------------------------------------------------------------------
                                         Operation or equipment to be
         The CVA must . . .                    inspected . . .
------------------------------------------------------------------------
(1) Verify, as appropriate.........  (i) Loadout and initial flotation
                                      operations;
                                     (ii) Towing operations to the
                                      specified location, and review the
                                      towing records;
                                     (iii) Launching and uprighting
                                      operations;
                                     (iv) Submergence operations;
                                     (v) Pile or anchor installations;
                                     (vi) Installation of mooring and
                                      tethering systems;
                                     (vii) Final deck and component
                                      installations; and
                                     (viii) Installation at the approved
                                      location according to the approved
                                      design and the installation plan.
(2) Witness (for a fixed or          (i) The loadout of the jacket,
 floating platform).                  decks, piles, or structures from
                                      each fabrication site;
                                     (ii) The actual installation of the
                                      platform or major modification and
                                      the related installation
                                      activities.
(3) Witness (for a floating          (i) The loadout of the platform;
 platform).
                                     (ii) The installation of drilling,
                                      production, and pipeline risers,
                                      and riser tensioning systems (at
                                      least for the initial installation
                                      of these elements);
                                     (iii) The installation of turrets
                                      and turret-and-hull interfaces;
                                     (iv) The installation of foundation
                                      pilings and templates, and
                                      anchoring systems; and
                                     (v) The installation of the mooring
                                      and tethering systems.
(4) Conduct an onsite survey.......  Survey the platform after
                                      transportation to the approved
                                      location.
(5) Spot-check as necessary to       (i) Equipment;
 determine compliance with the       (ii) Procedures; and
 applicable documents listed in      (iii) Recordkeeping.
 Sec.  250.901(a); the alternative
 codes, rules and standards
 approved under 250.901(b); the
 requirements listed in Sec.
 250.903 and Sec.  250.906 through
 250.908 of this subpart and the
 approved plans.
------------------------------------------------------------------------

    (c) Reports. The CVA must submit interim reports to you and the 
Regional Supervisor, as appropriate. The CVA must prepare a final report 
covering the adequacy of the entire installation phase, and submit one 
copy of the final

[[Page 398]]

report to the Regional Supervisor within 30 days of the installation of 
the platform. In the final report, the CVA must:
    (1) Give details of how, by whom, and when the independent 
monitoring activities were conducted;
    (2) Describe the CVA's activities during the verification process;
    (3) Summarize the CVA's findings;
    (4) Write a confirmation or denial of compliance with the approved 
installation plan;
    (5) Provide a recommendation to accept or reject the installation; 
and
    (6) Provide any additional comments that the CVA deems necessary.

          Inspection, Maintenance, and Assessment of Platforms



Sec. 250.919  What in-service inspection requirements must I meet?

    (a) You must develop a comprehensive annual in-service inspection 
plan covering all of your platforms. As a minimum, your plan must 
address the recommendations of the appropriate documents listed in Sec. 
250.901(a). Your plan must specify the type, extent, and frequency of 
in-place inspections which you will conduct for both the above water and 
the below water structure of all platforms, and pertinent components of 
the mooring systems for floating platforms. The plan must also address 
how you are monitoring the corrosion protection for both the above water 
and below water structure.
    (b) You must submit a report annually on November 1 to the Regional 
Supervisor that must include:
    (1) A list of fixed or floating platforms inspected in the preceding 
12 months;
    (2) The extent and area of inspection;
    (3) The type of inspection employed, (i.e., visual, magnetic 
particle, ultrasonic testing); and
    (4) A summary of the testing results indicating what repairs, if 
any, were needed and the overall structural condition of the fixed or 
floating platform.



Sec. 250.920  What are the MMS requirements for assessment of platforms?

    (a) You must perform a platform assessment when needed, based on the 
platform assessment initiators listed in sections 17.2.1-17.2.5 of API 
RP 2A-WSD, Recommended Practice for Planning, Designing and Constructing 
Fixed Offshore Platforms--Working Stress Design (incorporated by 
reference as specified in 30 CFR 250.198).
    (b) You must initiate mitigation actions for platforms that do not 
pass the assessment process of API RP 2A-WSD.
    (c) You must document all wells, equipment, and pipelines supported 
by the platform if you intend to use the medium or low consequence of 
failure exposure category for your assessment. Exposure categories are 
defined in API RP 2A-WSD Section 1.7.
    (d) MMS may require you to conduct a platform assessment where 
reduced environmental loading criteria are not allowed.
    (e) The use of Section 17, Assessment of Existing Platforms, of API 
RP 2A-WSD, is limited to existing fixed structures that are serving 
their original approved purpose.



Sec. 250.921  How do I analyze my platform for cumulative fatigue?

    (a) If you are required to analyze cumulative fatigue on your 
platform because of the results of an inspection or platform assessment, 
you must ensure that the safety factors for critical elements listed in 
Sec. 250.908 are met or exceeded.
    (b) If the calculated life of a joint or member does not meet the 
criteria of Sec. 250.908, you must either mitigate the load, strengthen 
the joint or member, or develop an increased inspection process.



             Subpart J_Pipelines and Pipeline Rights-of-Way



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 must be accompanied by payment of the service fee 
listed in Sec. 250.125 and submitted to the Regional Supervisor and 
approval obtained before:

[[Page 399]]

    (1) Installation, modification, or abandonment of a lease term 
pipeline;
    (2) Installation or modification of a right-of-way (other than lease 
term) pipeline; or
    (3) Modification or relinquishment of a pipeline right-of way.
    (c)(1) Department of the Interior (DOI) pipelines, as defined in 
Sec. 250.1001, must meet the requirements in Sec. Sec.  250.1000 
through 250.1008.
    (2) A pipeline right-of-way grant holder must identify in writing to 
the Regional Supervisor the operator of any pipeline located on its 
right-of-way, if the operator is different from the right-of-way grant 
holder.
    (3) A producing operator must identify for its own records, on all 
existing pipelines located on its lease or right-of-way, the specific 
points at which operating responsibility transfers to a transporting 
operator.
    (i) Each producing operator must, if practical, durably mark all of 
its above-water transfer points by April 14, 1999 or the date a pipeline 
begins service, whichever is later.
    (ii) If it is not practical to durably mark a transfer point, and 
the transfer point is located above water, then the operator must 
identify the transfer point on a schematic located on the facility.
    (iii) If a transfer point is located below water, then the operator 
must identify the transfer point on a schematic and provide the 
schematic to MMS upon request.
    (iv) If adjoining producing and transporting operators cannot agree 
on a transfer point by April 14, 1999, the MMS Regional Supervisor and 
the Department of Transportation (DOT) Office of Pipeline Safety (OPS) 
Regional Director may jointly determine the transfer point.
    (4) The transfer point serves as a regulatory boundary. An operator 
may write to the MMS Regional Supervisor to request an exception to this 
requirement for an individual facility or area. The Regional Supervisor, 
in consultation with the OPS Regional Director and affected parties, may 
grant the request.
    (5) Pipeline segments designed, constructed, maintained, and 
operated under DOT regulations but transferring to DOI regulation as of 
October 16, 1998, may continue to operate under DOT design and 
construction requirements until significant modifications or repairs are 
made to those segments. After October 16, 1998, MMS operational and 
maintenance requirements will apply to those segments.
    (6) Any producer operating a pipeline that crosses into State waters 
without first connecting to a transporting operator's facility on the 
OCS must comply with this subpart. Compliance must extend from the point 
where hydrocarbons are first produced, through and including the last 
valve and associated safety equipment (e.g., pressure safety sensors) on 
the last production facility on the OCS.
    (7) Any producer operating a pipeline that connects facilities on 
the OCS must comply with this subpart.
    (8) Any operator of a pipeline that has a valve on the OCS 
downstream (landward) of the last production facility may ask in writing 
that the MMS Regional Supervisor recognize that valve as the last point 
MMS will exercise its regulatory authority.
    (9) A pipeline segment is not subject to MMS regulations for design, 
construction, operation, and maintenance if:
    (i) It is downstream (generally shoreward) of the last valve and 
associated safety equipment on the last production facility on the OCS; 
and
    (ii) It is subject to regulation under 49 CFR parts 192 and 195.
    (10) DOT may inspect all upstream safety equipment (including 
valves, over-pressure protection devices, cathodic protection equipment, 
and pigging devices, etc.) that serve to protect the integrity of DOT-
regulated pipeline segments.
    (11) OCS pipeline segments not subject to DOT regulation under 49 
CFR parts 192 and 195 are subject to all MMS regulations.
    (12) A producer may request that its pipeline operate under DOT 
regulations governing pipeline design, construction, operation, and 
maintenance.
    (i) The operator's request must be in the form of a written petition 
to the MMS Regional Supervisor that states the justification for the 
pipeline to operate under DOT regulation.

[[Page 400]]

    (ii) The Regional Supervisor will decide, on a case-by-case basis, 
whether to grant the operator's request. In considering each petition, 
the Regional Supervisor will consult with the Office of Pipeline Safety 
(OPS) Regional Director.
    (13) A transporter who operates a pipeline regulated by DOT may 
request to operate under MMS regulations governing pipeline operation 
and maintenance. Any subsequent repairs or modifications will also be 
subject to MMS regulations governing design and construction.
    (i) The operator's request must be in the form of a written petition 
to the OPS Regional Director and the MMS Regional Supervisor.
    (ii) The MMS Regional Supervisor and the OPS Regional Director will 
decide how to act on this petition.
    (d) A pipeline which qualifies as a right-of-way pipeline (see 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-way holder has failed to comply with a provision of 
the Act or any other applicable law, a provision of these or other 
applicable regulations, or a condition of a permit or right-of-way 
grant.
    (3) The Secretary of the Interior (Secretary) may cancel a pipeline 
permit or right-of-way grant in accordance with 43 U.S.C. 1334(a)(2). A 
right-of-way grant may be forfeited in accordance with 43 U.S.C. 
1334(e).

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998; 63 FR 34597, June 25, 1998; 63 FR 43880, Aug. 17, 
1998; 65 FR 46095, July 27, 2000; 71 FR 40912, July 19, 2006]



Sec. 250.1001  Definitions.

    Terms used in this subpart shall have the meanings given below:
    DOI pipelines include:
    (1) Producer-operated pipelines extending upstream (generally 
seaward) from each point on the OCS at which operating responsibility 
transfers from a producing operator to a transporting operator;
    (2) Producer-operated pipelines extending upstream (generally 
seaward) of the last valve (including associated safety equipment) on 
the last production facility on the OCS that do not connect to a 
transporter-operated pipeline on the OCS before crossing into State 
waters;
    (3) Producer-operated pipelines connecting production facilities on 
the OCS;
    (4) Transporter-operated pipelines that DOI and DOT have agreed are 
to be regulated as DOI pipelines; and
    (5) All OCS pipelines not subject to regulation under 49 CFR parts 
192 and 195.
    DOT pipelines include:
    (1) Transporter-operated pipelines currently operated under DOT 
requirements governing design, construction, maintenance, and operation;
    (2) Producer-operated pipelines that DOI and DOT have agreed are to 
be regulated under DOT requirements governing design, construction, 
maintenance, and operation; and
    (3) Producer-operated pipelines downstream (generally shoreward) of 
the last valve (including associated safety equipment) on the last 
production facility on the OCS that do not connect to a transporter-
operated pipeline on the OCS before crossing into State waters and that 
are regulated under 49 CFR parts 192 and 195.
    Lease term pipelines are those pipelines owned and operated by a 
lessee or operator and are wholly contained within the boundaries of a 
single lease, unitized leases, or contiguous (not cornering) leases of 
that lessee or operator.
    Out-of-service pipelines are those pipelines that have not been used 
to transport oil, natural gas, sulfur, or produced water for more than 
30 consecutive days.

[[Page 401]]

    Pipelines are the piping, risers, and appurtenances installed for 
the purpose of transporting oil, gas, sulphur, and produced water. 
(Piping confined to a production platform or structure is covered in 
Subpart H, Production Safety Systems, and is excluded from this 
subpart.)
    Production facilities means OCS facilities that receive hydrocarbon 
production either directly from wells or from other facilities that 
produce hydrocarbons from wells. They may include processing equipment 
for treating the production or separating it into its various liquid and 
gaseous components before transporting it to shore.
    Right-of-way pipelines are those pipelines which--
    (1) Are contained within the boundaries of a single lease or group 
of unitized leases but are not owned and operated by the lessee or 
operator of that lease or unit,
    (2) Are contained within the boundaries of contiguous (not 
cornering) leases which do not have a common lessee or operator,
    (3) Are contained within the boundaries of contiguous (not 
cornering) leases which have a common lessee or operator but are not 
owned and operated by that common lessee or operator, or
    (4) Cross any portion of an unleased block(s).

[53 FR 10690, Apr. 1, 1998. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 63 FR 43881, Aug. 17, 1998; 65 FR 46096, July 27, 2000; 67 
FR 35405, May 17, 2002; 72 FR 25201, May 4, 2007]



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 (incorporated by reference as specified in 30 CFR 
250.198) where--

P=Internal design pressure in pounds per square inch (psi).
S=Specified minimum yield strength, in psi, stipulated in the 
          specification under which the pipe was purchased from the 
          manufacturer or determined in accordance with section 
          811.253(h) of ANSI B31.8.
D=Nominal outside diameter of pipe, in inches.
t=Nominal wall thickness, in inches.
F=Construction design factor of 0.72 for the submerged component and 
0.60 for the riser component.
E=Longitudinal joint factor obtained from Table 841.1B of ANSI B31.8. 
(See also section 811.253(d)).
T=Temperature derating factor obtained from Table 841.1C of ANSI B31.8.

    (b)(1) Pipeline valves shall meet the minimum design requirements of 
American Petroleum Institute (API) Spec 6A, API Spec 6D, or the 
equivalent. A valve may not be used under operating conditions that 
exceed the applicable pressure-temperature ratings contained in those 
standards.
    (2) Pipeline flanges and flange accessories shall meet the minimum 
design requirements of ANSI B16.5, API Spec 6A, or the equivalent 
(incorporated by reference as specified in 30 CFR 250.198). Each flange 
assembly must be able to withstand the maximum pressure at which the 
pipeline is to be operated and to maintain its physical and chemical 
properties at any temperature to which it is anticipated that it might 
be subjected in service.
    (3) Pipeline fittings shall have pressure-temperature ratings based 
on stresses for pipe of the same or equivalent material. The actual 
bursting strength of the fitting shall at least be equal to the computed 
bursting strength of the pipe.
    (4) If you are installing pipelines constructed of unbonded flexible 
pipe, you must design them according to the standards and procedures of 
API Spec 17J, incorporated by reference as specified in 30 CFR 250.198.
    (5) You must design pipeline risers for tension leg platforms and 
other floating platforms according to the design standards of API RP 
2RD, Design of Risers for Floating Production Systems (FPSs) and Tension 
Leg Platforms (TLPs), incorporated by reference as specified in 30 CFR 
250.198.
    (c) The maximum allowable operating pressure (MAOP) shall not exceed 
the least of the following:
    (1) Internal design pressure of the pipeline, valves, flanges, and 
fittings;

[[Page 402]]

    (2) Eighty percent of the hydrostatic pressure test (HPT) pressure 
of the pipeline; or
    (3) If applicable, the MAOP of the receiving pipeline when the 
proposed pipeline and the receiving pipeline are connected at a subsea 
tie-in.
    (d) If the maximum source pressure (MSP) exceeds the pipeline's 
MAOP, you must install and maintain redundant safety devices meeting the 
requirements of section A9 of API RP 14C (incorporated by reference as 
specified in Sec. 250.198). Pressure safety valves (PSV) may be used 
only after a determination by the Regional Supervisor that the pressure 
will be relieved in a safe and pollution-free manner. The setting level 
at which the primary and redundant safety equipment actuates shall not 
exceed the pipeline's MAOP.
    (e) Pipelines shall be provided with an external protective coating 
capable of minimizing underfilm corrosion and a cathodic protection 
system designed to mitigate corrosion for at least 20 years.
    (f) Pipelines shall be designed and maintained to mitigate any 
reasonably anticipated detrimental effects of water currents, storm or 
ice scouring, soft bottoms, mud slides, earthquakes, subfreezing 
temperatures, and other environmental factors.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 67 FR 51760, Aug. 9, 2002; 70 FR 41583, July 19, 2005; 72 
FR 12096, Mar. 15, 2007; 72 FR 25201, May 4, 2007]



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 pressure tested with water at a stabilized 
pressure of at least 1.25 times the MAOP for at least 8 hours when 
installed, relocated, uprated, or reactivated after being out-of-service 
for more than 1 year.
    (2) Prior to returning a pipeline to service after a repair, the 
pipeline shall be pressure tested with water or processed natural gas at 
a minimum stabilized pressure of at least 1.25 times the MAOP for at 
least 2 hours.
    (3) Pipelines shall not be pressure tested at a pressure which 
produces a stress in the pipeline in excess of 95 percent of the 
specified minimum-yield strength of the pipeline. A temperature recorder 
measuring test fluid temperature synchronized with a pressure recorder 
along with deadweight test readings shall be employed for all pressure 
testing. When a pipeline is pressure tested, no observable leakage shall 
be allowed. Pressure gauges and recorders shall be of sufficient 
accuracy to verify that leakage is not occurring.
    (4) The Regional Supervisor may require pressure testing of 
pipelines to verify the integrity of the system when the Regional 
Supervisor determines that there is a reasonable likelihood that the 
line has been damaged or

[[Page 403]]

weakened by external or internal conditions.
    (c) When a pipeline is repaired utilizing a clamp, the clamp shall 
be a full encirclement clamp able to withstand the anticipated pipeline 
pressure.

[53 FR 10690, Apr. 1, 1988; 53 FR 12227, Apr. 13, 1988; 57 FR 26997, 
June 17, 1992. Redesignated at 63 FR 29479, May 29, 1998, as amended at 
72 FR 25201, May 4, 2007]



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 a production platform shall be 
equipped with an automatic shutdown valve (SDV) immediately upon 
boarding the platform. The SDV shall be connected to the automatic- and 
remote-emergency shut-in systems.
    (3) Departing pipelines receiving production from production 
facilities shall be protected by high- and low-pressure sensors (PSHL) 
to directly or indirectly shut in all production facilities. The PSHL 
shall be set not to exceed 15 percent above and below the normal 
operating pressure range. However, high pilots shall not be set above 
the pipeline's MAOP.
    (4) Crossing pipelines on production or manned nonproduction 
platforms which do not receive production from the platform shall be 
equipped with an SDV immediately upon boarding the platform. The SDV 
shall be operated by a PSHL on the departing pipelines and connected to 
the platform automatic- and remote-emergency shut-in systems.
    (5) The Regional Supervisor may require that oil pipelines be 
equipped with a metering system to provide a continuous volumetric 
comparison between the input to the line at the structure(s) and the 
deliveries onshore. The system shall include an alarm system and shall 
be of adequate sensitivity to detect variations between input and 
discharge volumes. In lieu of the foregoing, a system capable of 
detecting leaks in the pipeline may be substituted with the approval of 
the Regional Supervisor.
    (6) Pipelines incoming to a subsea tie-in shall be equipped with a 
block valve and an FSV. Bidirectional pipelines connected to a subsea 
tie-in shall be equipped with only a block valve.
    (7) Gas-lift or water-injection pipelines on unmanned platforms need 
only be equipped with an FSV installed immediately upstream of each 
casing annulus or the first inlet valve on the christmas tree.
    (8) Bidirectional pipelines shall be equipped with a PSHL and an SDV 
immediately upon boarding each platform.
    (9) Pipeline pumps must comply with section A7 of API RP 14C 
(incorporated by reference as specified in Sec. 250.198). The setting 
levels for the PSHL devices are specified in paragraph (b)(3) of this 
section.
    (c) If the required safety equipment is rendered ineffective or 
removed from service on pipelines which are continued in operation, an 
equivalent degree of safety shall be provided. The safety equipment 
shall be identified by the placement of a sign on the equipment stating 
that the equipment is rendered ineffective or removed from service.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 56 
FR 32100, July 15, 1991. Redesignated at 63 FR 29479, May 29, 1998; 67 
FR 51760, Aug. 9, 2002; 72 FR 25201, May 4, 2007]



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

[[Page 404]]

available to the Regional Supervisor upon request.
    (b) When pipelines are protected by rectifiers or anodes for which 
the initial life expectancy of the cathodic protection system either 
cannot be calculated or calculations indicate a life expectancy of less 
than 20 years, such pipelines shall be inspected annually by taking 
measurements of pipe-to-electrolyte potential.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 72 FR 25201, May 4, 2007]



Sec. 250.1006  How must I decommission and take out of service a DOI 

pipeline?

    (a) The requirements for decommissioning pipelines are listed in 
Sec. 250.1750 through Sec.  250.1754.
    (b) The table in this section lists the requirements if you take a 
DOI pipeline out of service:

------------------------------------------------------------------------
  If you have the pipeline out of service
                   for:                            Then you must:
------------------------------------------------------------------------
(1) 1 year or less........................  Isolate the pipeline with a
                                             blind flange or a closed
                                             block valve at each end of
                                             the pipeline.
(2) More than 1 year but less than 5 years  Flush and fill the pipeline
                                             with inhibited seawater.
(3) 5 or more years.......................  Decommission the pipeline
                                             according to Sec. Sec.
                                             250.1750-250.1754.
------------------------------------------------------------------------


[67 FR 35405, May 17, 2002]



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,
    (ix) Proposed date for commencing installation and estimated time 
for construction; and

[[Page 405]]

    (x) Type of protection to be afforded crossing pipelines, subsea 
valves, taps, and manifold assemblies, if applicable.
    (4) The application must include a description of any additional 
design precautions which will be taken to enable the pipeline to 
withstand the effects of water currents, storm or ice scouring, soft 
bottoms, mudslides, earthquakes, permafrost, and other environmental 
factors. If your application involves using unbonded flexible pipe, you 
must:
    (i) Review the manufacturer's Design Methodology Verification 
Report, and the independent verification agent's (IVA's) certificate for 
the design methodology contained in that report, to ensure that the 
manufacturer has complied with the requirements of API Spec 17J 
incorporated by reference as specified in 30 CFR 250.198;
    (ii) Determine that the unbonded flexible pipe is suitable for its 
intended purpose on the lease or pipeline right-of-way;
    (iii) Submit to the MMS Regional Supervisor the manufacturer's 
design specifications for the unbonded flexible pipe; and
    (iv) Submit to the MMS Regional Supervisor a statement certifying 
that the pipe is suitable for its intended use, and that the 
manufacturer has complied with the IVA requirements of API Spec 17J 
incorporated by reference as specified in 30 CFR 250.198.
    (5) The application shall include a shallow hazards survey report 
and, if required by the Regional Director, an archaeological resource 
report that covers the entire length of the pipeline. A shallow hazards 
analysis may be included in a lease term pipeline application in lieu of 
the shallow hazards survey report with the approval of the Regional 
Director. The Regional Director may require the submission of the data 
upon which the report or analysis is based.
    (b) Applications to modify an approved lease term pipeline or right-
of-way grant shall be submitted in quadruplicate to the Regional 
Supervisor. These applications need only address those items in the 
original application affected by the proposed modification.

[53 FR 10690, Apr. 1, 1988, as amended at 59 FR 53094, Oct. 21, 1994. 
Redesignated at 63 FR 29479, May 29, 1998, as amended at 63 FR 43881, 
Aug. 17, 1998; 67 FR 35406, May 17, 2002; 70 FR 41583, July 19, 2005; 72 
FR 25201, May 4, 2007]



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 must notify the Regional 
Supervisor before the repair of any pipeline or as soon as practicable. 
Your notification must be accompanied by payment of the service fee 
listed in Sec. 250.125. You must submit a detailed report of the repair 
of a pipeline or pipeline component to the Regional Supervisor within

[[Page 406]]

30 days after the completion of the repairs. In the report you must 
include the following:
    (1) Description of repairs;
    (2) Results of pressure test; and
    (3) Date returned to service.
    (f) The Regional Supervisor may require that DOI pipeline failures 
be analyzed and that samples of a failed section be examined in a 
laboratory to assist in determining the cause of the failure. A 
comprehensive written report of the information obtained shall be 
submitted by the lessee to the Regional Supervisor as soon as available.
    (g) If the effects of scouring, soft bottoms, or other environmental 
factors are observed to be detrimentally affecting a pipeline, a plan of 
corrective action shall be submitted to the Regional Supervisor for 
approval within 30 days of the observation. A report of the remedial 
action taken shall be submitted to the Regional Supervisor by the lessee 
or right-of-way holder within 30 days after completion.
    (h) The results and conclusions of measurements of pipe-to-
electrolyte potential measurements taken annually on DOI pipelines in 
accordance with 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; 71 FR 40912, July 19, 2006]



Sec. 250.1009  Requirements to obtain pipeline right-of-way grants.

    (a) In addition to applicable requirements of Sec. Sec. 250.1000 
through 250.1008 and other regulations of this part, regulations of the 
Department of Transportation, Department of the Army, and the Federal 
Energy Regulatory Commission (FERC), when a pipeline qualifies as a 
right-of-way pipeline, the pipeline shall not be installed until a 
right-of-way has been requested and granted in accordance with this 
subpart. The right-of-way grant is issued pursuant to 43 U.S.C. 1334(e) 
and may be acquired and held only by citizens and nationals of the 
United States; aliens lawfully admitted for permanent residence in the 
United States as defined in 8 U.S.C. 1101(a)(20); private, public, or 
municipal corporations organized under the laws of the United States or 
territory thereof, the District of Columbia, or of any State; or 
associations of such citizens, nationals, resident aliens, or private, 
public, or municipal corporations, States, or political subdivisions of 
States.
    (b) A right-of-way shall include the site on which the pipeline and 
associated structures are to be situated, shall not exceed 200 feet in 
width unless safety and environmental factors during construction and 
operation of the associated right-of-way pipeline require a greater 
width, and shall be limited to the area reasonably necessary for pumping 
stations or other accessory structures.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 
FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 
22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 
63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]



Sec. 250.1010  General requirements for pipeline right-of-way holders.

    An applicant, by accepting a right-of-way grant, agrees to comply 
with the following requirements:
    (a) The right-of-way holder shall comply with applicable laws and 
regulations and the terms of the grant.
    (b) The granting of the right-of-way shall be subject to the express 
condition that the rights granted shall not prevent or interfere in any 
way with the management, administration, or the granting of other rights 
by the United States, either prior or subsequent to the granting of the 
right-of-way. Moreover, the holder agrees to allow the occupancy and use 
by the United States, its lessees, or other right-of-way holders, of any 
part of the right-of-way grant not actually occupied or necessarily 
incident to its use for any necessary operations involved in the 
management, administration, or the enjoyment of such other granted 
rights.
    (c) If the right-of-way holder discovers any archaeological resource 
while conducting operations within the right-of-way, the right-of-way 
holder shall immediately halt operations

[[Page 407]]

within the area of the discovery and report the discovery to the 
Regional Director. If investigations determine that the resource is 
significant, the Regional Director will inform the right-of-way holder 
how to protect it.
    (d) The Regional Supervisor shall be kept informed at all times of 
the right-of-way holder's address and, if a corporation, the address of 
its principal place of business and the name and address of the officer 
or agent authorized to be served with process.
    (e) The right-of-way holder shall pay the United States or its 
lessees or right-of-way holders, as the case may be, the full value of 
all damages to the property of the United States or its said lessees or 
right-of-way holders and shall indemnify the United States against any 
and all liability for damages to life, person, or property arising from 
the occupation and use of the area covered by the right-of-way grant.
    (f)(1) The holder of a right-of-way oil or gas pipeline shall 
transport or purchase oil or natural gas produced from submerged lands 
in the vicinity of the pipeline without discrimination and in such 
proportionate amounts as the FERC may, after a full hearing with due 
notice thereof to the interested parties, determine to be reasonable, 
taking into account, among other things, conservation and the prevention 
of waste.
    (2) Unless otherwise exempted by FERC pursuant to 43 U.S.C. 
1334(f)(2), the holder shall--
    (i) Provide open and nondiscriminatory access to a right-of-way 
pipeline to both owner and nonowner shippers, and
    (ii) Comply with the provisions of 43 U.S.C. 1334(f)(1)(B) under 
which FERC may order an expansion of the throughput capacity of a right-
of-way pipeline which is approved after September 18, 1978, and which is 
not located in the Gulf of Mexico or the Santa Barbara Channel.
    (g) The area covered by a right-of-way and all improvements thereon 
shall be kept open at all reasonable times for inspection by the 
Minerals Management Service (MMS). The right-of-way holder shall make 
available all records relative to the design, construction, operation, 
maintenance and repair, and investigations on or with regard to such 
area.
    (h) Upon relinquishment, forfeiture, or cancellation of a right-of-
way grant, the right-of-way holder shall remove all platforms, 
structures, domes over valves, pipes, taps, and valves along the right-
of-way. All of these improvements shall be removed by the holder within 
1 year of the effective date of the relinquishment, forfeiture, or 
cancellation unless this requirement is waived in writing by the 
Regional Supervisor. All such improvements not removed within the time 
provided herein shall become the property of the United States but that 
shall not relieve the holder of liability for the cost of their removal 
or for restoration of the site. Furthermore, the holder is responsible 
for accidents or damages which might occur as a result of failure to 
timely remove improvements and equipment and restore a site. An 
application for relinquishment of a right-of-way grant shall be filed in 
accordance with Sec. 250.1019 of this part.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 
FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 
22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 
63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 72 FR 
25201, May 4, 2007]



Sec. 250.1011  Bond requirements for pipeline right-of-way holders.

    (a) When you apply for, or are the holder of, a right-of-way, you 
must:
    (1) Provide and maintain a $300,000 bond (in addition to the bond 
coverage required in part 256) that guarantees compliance with all the 
terms and conditions of the rights-of-way you hold in an OCS area; and
    (2) Provide additional security if the Regional Director determines 
that a bond in excess of $300,000 is needed.
    (b) For the purpose of this paragraph, there are three areas:
    (1) The Gulf of Mexico and the area offshore the Atlantic Coast;
    (2) The areas offshore the Pacific Coast States of California, 
Oregon, Washington, and Hawaii; and
    (3) The area offshore the Coast of Alaska.

[[Page 408]]

    (c) If, as the result of a default, the surety on a right-of-way 
grant bond makes payment to the Government of any indebtedness under a 
grant secured by the bond, the face amount of such bond and the surety's 
liability shall be reduced by the amount of such payment.
    (d) After a default, a new bond in the amount of $300,000 shall be 
posted within 6 months or such shorter period as the Regional Supervisor 
may direct. Failure to post a new bond shall be grounds for forfeiture 
of all grants covered by the defaulted bond.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 
FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 
22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 
63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 72 FR 
25201, May 4, 2007]



Sec. 250.1012  Required payments for pipeline right-of-way holders.

    (a) You must pay MMS an annual rental of $15 for each statute mile, 
or part of a statute mile, of the OCS that your pipeline right-of-way 
crosses.
    (b) This paragraph applies to you if you obtain a pipeline right-of-
way that includes a site for an accessory to the pipeline, including but 
not limited to a platform. This paragraph also applies if you apply to 
modify a right-of-way to change the site footprint. In either case, you 
must pay the amounts shown in the following table.

------------------------------------------------------------------------
               If...                               Then...
------------------------------------------------------------------------
(1) Your accessory site is located   You must pay a rental of $5 per
 in water depths of less than 200     acre per year with a minimum of
 meters;                              $450 per year. The area subject to
                                      annual rental includes the areal
                                      extent of anchor chains, pipeline
                                      risers, and other facilities and
                                      devices associated with the
                                      accessory.
(2) Your accessory site is located   You must pay a rental of $7.50 per
 in water depths of 200 meters or     acre per year with a minimum of
 greater;                             $675 per year. The area subject to
                                      annual rental includes the areal
                                      extent of anchor chains, pipeline
                                      risers, and other facilities and
                                      devices associated with the
                                      accessory.
------------------------------------------------------------------------

    (c) If you hold a pipeline right-of-way that includes a site for an 
accessory to your pipeline and you are not covered by paragraph (b) of 
this section, then you must pay MMS an annual rental of $75 for use of 
the affected area.
    (d) You may make the rental payments required by paragraphs (a), 
(b)(1), (b)(2), and (c) of this section on an annual basis, for a 5-year 
period, or for multiples of 5 years. You must make the first payment at 
the time you submit the pipeline right-of-way application. You must make 
all subsequent payments before the respective time periods begin.
    (e) Late payments. An interest charge will be assessed on unpaid and 
underpaid amounts from the date the amounts are due, in accordance with 
the provisions found in 30 CFR 218.54. If you fail to make a payment 
that is late after written notice from MMS, MMS may initiate 
cancellation of the right-of-use grant and easement under 30 CFR 
250.1013.

[68 FR 69312, Dec. 12, 2003, as amended at 69 FR 29433, May 24, 2004]



Sec. 250.1013  Grounds for forfeiture of pipeline right-of-way grants.

    Failure to comply with the Act, regulations, or any conditions of 
the right-of-way grant prescribed by the Regional Supervisor shall be 
grounds for forfeiture of the grant in an appropriate judicial 
proceeding instituted by the United States in any U.S. District

[[Page 409]]

Court having jurisdiction in accordance with the provisions of 43 U.S.C. 
1349.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 
FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 
22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 
63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]



Sec. 250.1014  When pipeline right-of-way grants expire.

    Any right-of-way granted under the provisions of this subpart 
remains in effect as long as the associated pipeline is properly 
maintained and used for the purpose for which the grant was made, unless 
otherwise expressly stated in the grant. Temporary cessation or 
suspension of pipeline operations shall not cause the grant to expire. 
However, if the purpose of the grant ceases to exist or use of the 
associated pipeline is permanently discontinued for any reason, the 
grant shall be deemed to have expired.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 
FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 
22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 
63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]



Sec. 250.1015  Applications for pipeline right-of-way grants.

    (a) You must submit an original and three copies of an application 
for a new or modified pipeline ROW grant to the Regional Supervisor. The 
application must address those items required by Sec. 250.1007(a) or 
(b) of this subpart, as applicable. It must also state the primary 
purpose for which you will use the ROW grant. If the ROW has been used 
before the application is made, the application must state the date such 
use began, by whom, and the date the applicant obtained control of the 
improvement. When you file your application, you must pay the rental 
required under Sec. 250.1012 of this subpart, as well as the service 
fees listed in Sec. 250.125 of this part for a pipeline ROW grant to 
install a new pipeline, or to convert an existing lease term pipeline 
into a ROW pipeline. An application to modify an approved ROW grant must 
be accompanied by the additional rental required under Sec. 250.1012 if 
applicable. You must file a separate application for each ROW.
    (b)(1) An individual applicant shall submit a statement of 
citizenship or nationality with the application. An applicant who is an 
alien lawfully admitted for permanent residence in the United States 
shall also submit evidence of such status with the application.
    (2) If the applicant is an association (including a partnership), 
the application shall also be accompanied by a certified copy of the 
articles of association or appropriate reference to a copy of such 
articles already filed with MMS and a statement as to any subsequent 
amendments.
    (3) If the applicant is a corporation, the application shall also 
include the following:
    (i) A statement certified by the Secretary or Assistant Secretary of 
the corporation with the corporate seal showing the State in which it is 
incorporated and the name of the person(s) authorized to act on behalf 
of the corporation, or
    (ii) In lieu of such a statement, an appropriate reference to 
statements or records previously submitted to MMS (including material 
submitted in compliance with prior regulations).
    (c) The application shall include a list of every lessee and right-
of-way holder whose lease or right-of-way is intersected by the proposed 
right-of-way. The application shall also include a statement that a copy 
of the application has been sent by registered or certified mail to each 
such lessee or right-of-way holder.
    (d) The applicant shall include in the application an original and 
three copies of a completed Nondiscrimination in Employment form (YN 
3341-1 dated July 1982). These forms are available at each MMS regional 
office.
    (e) Notwithstanding the provisions of paragraph (a) of this section, 
the requirements to pay filing fees under

[[Page 410]]

that paragraph are suspended until January 3, 2006.

[53 FR 10690, Apr. 1, 1988, as amended at 62 FR 39775, July 24, 1997. 
Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 64 FR 
42598, Aug. 5, 1999. Further redesignated and amended at 68 FR 69311, 
69312, Dec. 12, 2003; 70 FR 49876, Aug. 25, 2005; 70 FR 61893, Oct. 27, 
2005]



Sec. 250.1016  Granting pipeline rights-of-way.

    (a) In considering an application for a right-of-way, the Regional 
Supervisor shall consider the potential effect of the associated 
pipeline on the human, marine, and coastal environments, life (including 
aquatic life), property, and mineral resources in the entire area during 
construction and operational phases. The Regional Supervisor shall 
prepare an environmental analysis in accordance with applicable policies 
and guidelines. To aid in the evaluation and determinations, the 
Regional Supervisor may request and consider views and recommendations 
of appropriate Federal Agencies, hold public meetings after appropriate 
notice, and consult, as appropriate, with State agencies, organizations, 
industries, and individuals. Before granting a pipeline right-of-way, 
the Regional Supervisor shall give consideration to any recommendation 
by the intergovernmental planning program, or similar process, for the 
assessment and management of OCS oil and gas transportation.
    (b) Should the proposed route of a right-of-way adjoin and 
subsequently cross any State submerged lands, the applicant shall submit 
evidence to the Regional Supervisor that the State(s) so affected has 
reviewed the application. The applicant shall also submit any comment 
received as a result of that review. In the event of a State 
recommendation to relocate the proposed route, the Regional Supervisor 
may consult with the appropriate State officials.
    (c)(1) The applicant shall submit photocopies of return receipts to 
the Regional Supervisor that indicate the date that each lessee or 
right-of-way holder referenced in Sec. 250.1015(c) of this part has 
received a copy of the application. Letters of no objection may be 
submitted in lieu of the return receipts.
    (2) The Regional Supervisor shall not take final action on a right-
of-way application until the Regional Supervisor is satisfied that each 
such lessee or right-of-way holder has been afforded at least 30 days 
from the date determined in paragraph (c)(1) of this section in which to 
submit comments.
    (d) If a proposed right-of-way crosses any lands not subject to 
disposition by mineral leasing or restricted from oil and gas 
activities, it shall be rejected by the Regional Supervisor unless the 
Federal Agency with jurisdiction over such excluded or restricted area 
gives its consent to the granting of the right-of-way. In such case, the 
applicant, upon a request filed within 30 days after receipt of the 
notification of such rejection, shall be allowed an opportunity to 
eliminate the conflict.
    (e)(1) If the application and other required information are found 
to be in compliance with applicable laws and regulations, the right-of-
way may be granted. The Regional Supervisor may prescribe, as conditions 
to the right-of-way grant, stipulations necessary to protect human, 
marine, and coastal environments, life (including aquatic life), 
property, and mineral resources located on or adjacent to the right-of-
way.
    (2) If the Regional Supervisor determines that a change in the 
application should be made, the Regional Supervisor shall notify the 
applicant that an amended application shall be filed subject to 
stipulated changes. The Regional Supervisor shall determine whether the 
applicant shall deliver copies of the amended application to other 
parties for comment.
    (3) A decision to reject an application shall be in writing and 
shall state the reasons for the rejection.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1988. 
Redesignated and amended at 63 FR 29479, 29486, May 29, 1998. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 72 FR 
25201, May 4, 2007]

[[Page 411]]



Sec. 250.1017  Requirements for construction under pipeline right-of-way 

grants.

    (a) Failure to construct the associated right-of-way pipeline within 
5 years of the date of the granting of a right-of-way shall cause the 
grant to expire.
    (b)(1) A right-of-way holder shall ensure that the right-of-way 
pipeline is constructed in a manner that minimizes deviations from the 
right-of-way as granted.
    (2) If, after constructing the right-of-way pipeline, it is 
determined that a deviation from the proposed right-of-way as granted 
has occurred, the right-of-way holder shall--
    (i) Notify the operators of all leases and holders of all right-of-
way grants in which a deviation has occurred, and within 60 days of the 
date of the acceptance by the Regional Supervisor of the completion of 
pipeline construction report, provide the Regional Supervisor with 
evidence of such notification; and
    (ii) Relinquish any unused portion of the right-of-way.
    (3) Substantial deviation of a right-of-way pipeline as constructed 
from the proposed right-of-way as granted may be grounds for forfeiture 
of the right-of-way.
    (c) If the Regional Supervisor determines that a significant change 
in conditions has occurred subsequent to the granting of a right-of-way 
but prior to the commencement of construction of the associated 
pipeline, the Regional Supervisor may suspend or temporarily prohibit 
the commencement of construction until the right-of-way grant is 
modified to the extent necessary to address the changed conditions.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998. 
Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]



Sec. 250.1018  Assignment of pipeline right-of-way grants.

    (a) Assignment may be made of a right-of-way grant, in whole or of 
any lineal segment thereof, subject to the approval of the Regional 
Supervisor. An application for approval of an assignment of a right-of-
way or of a lineal segment thereof, shall be filed in triplicate with 
the Regional Supervisor.
    (b) Any application for approval for an assignment, in whole or in 
part, of any right, title, or interest in a right-of-way grant must be 
accompanied by the same showing of qualifications of the assignees as is 
required of an applicant for a ROW in Sec. 250.1015 of this subpart and 
must be supported by a statement that the assignee agrees to comply with 
and to be bound by the terms and conditions of the ROW grant. The 
assignee must satisfy the bonding requirements in Sec. 250.1011 of this 
subpart. No transfer will be recognized unless and until it is first 
approved, in writing, by the Regional Supervisor. The assignee must pay 
the service fee listed in Sec. 250.125 of this part for a pipeline ROW 
assignment request.
    (c) Notwithstanding the provisions of paragraph (b) of this section, 
the requirement to pay a filing fee under that paragraph is suspended 
until January 3, 2006.

[53 FR 10690, Apr. 1, 1988, as amended at 62 FR 39775, July 24, 1997. 
Redesignated and amended at 63 FR 29479, 29486, May 29, 1998. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 70 FR 
49876, Aug. 25, 2005; 70 FR 61893, Oct. 27, 2005]



Sec. 250.1019  Relinquishment of pipeline right-of-way grants.

    A right-of-way grant or a portion thereof may be surrendered by the 
holder by filing a written relinquishment in triplicate with the 
Regional Supervisor. It must contain those items addressed in Sec. Sec. 
250.1751 and 250.1752 of this part. A relinquishment shall take effect 
on the date it is filed subject to the satisfaction of all outstanding 
debts, fees, or fines and the requirements in Sec. 250.1010(h) of this 
part.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998; 67 FR 35406, May 17, 2002. Further redesignated and 
amended at 68 FR 69311, 69312, Dec. 12, 2003; 72 FR 25201, May 4, 2007]

[[Page 412]]



                 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 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.
    (f) The lessee must pay the service fee listed in Sec. 250.125 of 
this part with its request for either a 500 feet from lease/unit line 
production interval or

[[Page 413]]

to produce from a completion in an associated gas cap of a sensitive 
reservoir under this section.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998; 70 FR 49876, Aug. 25, 2005]



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, Sensitive Reservoir 
Information Report (SRI), along with appropriate supporting information 
to the Regional Supervisor within 45 days after discovering that a 
reservoir is sensitive.
    (2) The lessee may propose to revise an MER by submitting Form MMS-
127 with appropriate supporting information.
    (3) The effective date of an MER for a reservoir or revision thereof 
shall be the first day of the month in which Form MMS-127 is submitted.
    (4) When approved, the MER shall not be exceeded, except as provided 
in paragraph (a)(5) of this section.
    (5) If a reservoir is produced at a rate in excess of the MER for 
any month, the lessee should initiate measures necessary to balance 
production (offset overproduction by underproduction) during the next 
succeeding month. All overproduction shall be balanced by the end of the 
next succeeding calendar quarter following the quarter in which the 
overproduction occurred. Any operation in an overproduction status in 
any reservoir for two successive calendar quarters shall be shut in from 
that reservoir until the actual production is equal to that which would 
have occurred under the approved MER, unless an alternative plan is 
approved by the Regional Supervisor.
    (6) The lessee shall review the MER for each producing sensitive 
reservoir at least once a year and submit Form MMS-127 with appropriate 
supporting information.
    (7) The lessee may request the reclassification of a reservoir from 
sensitive to nonsensitive and request approval for termination of an MER 
by submitting Form MMS-127 with information supporting the 
reclassification and termination.
    (8) At the request of the Regional Supervisor, the lessee shall 
furnish the information specified on Form MMS-127 for any producing 
nonsensitive reservoir.
    (9) Public information copies of Form MMS-127 shall be submitted in 
accordance with Sec. 250.186.
    (b) MPR. (1) The lessee shall propose an MPR for each producing well 
completion together with full information on the method used in its 
determination. The MPR shall be based on well tests and any limitations 
imposed by well and surface equipment, sand production, gas-oil and 
water-oil ratios, location of perforated intervals, and prudent 
operating practices. The sum of the MPR's of wells completed in a 
sensitive reservoir shall not exceed the approved MER.
    (2) The lessee shall conduct a well-flow potential test within 30 
days of the date of first continuous production on all new, recompleted, 
and reworked well completions. Within 15 days after the end of the test 
period, the lessee must submit a proposed MPR with well potential test 
for the individual well completion on Form MMS-126, Well Potential Test 
Report. The initial MPR shall not exceed 110 percent of the test rate 
submitted and shall be effective on the first day of the month following 
the end of the test period if approved by the Regional Supervisor. 
During the 30-day period allowed for testing, the lessee may produce a 
new, recompleted, or reworked completion at rates necessary to establish 
the MPR. After the 30-day period and prior to approval of the initial 
MPR, a well completion may be produced at a rate not to exceed the 
proposed rate. The lessee shall report the total production obtained 
during the test period and shall identify all other wells completed in 
the reservoir on Form MMS-126.
    (3) At least one well test shall be conducted during a calendar half 
for producing oil-well and gas-well completions and results submitted on 
Form MMS-128, Semiannual Well Test Report. Well tests shall be submitted 
within 45 days of the day the test was conducted.
    (4) Unless otherwise ordered by the Regional Supervisor, a revised 
MPR shall automatically be approved for

[[Page 414]]

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. 250.186.
    (9) Public information copies of Form MMS-128 shall be submitted in 
accordance with Sec. 250.186.
    (c) Temporary rates. Temporary production rates resulting from 
normal variations and fluctuations exceeding a well MPR or reservoir MER 
shall not be considered a violation, provided that such production in 
excess of an approved MER is balanced by production in accordance with 
the provisions of paragraph (a)(5) of this section.

[53 FR 10690, Apr. 1, 1988, as amended at 58 FR 49928, Sept. 24, 1993. 
Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 64 FR 
72794, Dec. 28, 1999; 65 FR 2875, Jan. 19, 2000; 71 FR 19646, Apr. 17, 
2006; 72 FR 25201, May 4, 2007]



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) 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.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 72 FR 25201, May 4, 2007]



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

[[Page 415]]

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 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. 250.490(f)), Exploration Plan or 
Development and Production Plan, and associated documents in determining 
the need for such restrictions.
    (ii) If the Regional Supervisor determines that flaring at a 
facility or group of facilities may significantly affect the air quality 
of an onshore area, the Regional Supervisor may require

[[Page 416]]

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 
Sec. Sec. 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; 68 FR 
8435, Feb. 20, 2003]



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. The application shall provide the estimated 
recoverable reserves as well as any available alternate drainage points 
which might be used to produce the reservoirs separately.
    (b) For a competitive reservoir, notice of intent to submit the 
application shall be sent by the applicant to all other lessees having 
an interest in the reservoir prior to submitting the application to the 
Regional Supervisor.
    (c) The application shall specify the well-completion number to be 
used for subsequent reporting purposes.
    (d) The applicant must pay the service fee listed in Sec. 250.125 
of this part with its request for downhole commingling.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 70 FR 49876, Aug. 25, 2005]



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?.

[[Page 417]]

 
 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 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.

[[Page 418]]

    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.
    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 any changes to the previously-approved measurement and/or 
allocation procedures. Your application (which may also include any 
relevant gas measurement and surface commingling requests) must be 
accompanied by payment of the service fee listed in Sec. 250.125. The 
service fees are divided into two levels based on complexity as shown in 
the following table.

------------------------------------------------------------------------
             Application type                          Actions
------------------------------------------------------------------------
(i) Simple applications...................  Applications to temporarily
                                             reroute production (for a
                                             duration not to exceed six
                                             months); Production tests
                                             prior to pipeline
                                             construction; Departures
                                             related to meter proving,
                                             well testing, or sampling
                                             frequency.
(ii) Complex applications.................  Creation of new facility
                                             measurement points (FMPs);
                                             Association of leases or
                                             units with existing FMPs;
                                             Inclusion of production
                                             from additional structures;
                                             Meter updates which add buy-
                                             back gas meters or pigging
                                             meters; Other applications
                                             which request deviations
                                             from the approved
                                             allocation procedures.
------------------------------------------------------------------------

    (2) Use measurement equipment that will accurately measure the 
liquid hydrocarbons produced from a lease or unit;
    (3) Use procedures and correction factors according to the 
applicable chapters of the API MPMS as incorporated by reference in 30 
CFR 250.198, when obtaining net standard volume and associated 
measurement parameters; and

[[Page 419]]

    (4) When requested by the Regional Supervisor, provide the pipeline 
(retrograde) condensate volumes as allocated to the individual leases or 
units.
    (b) What are the requirements for liquid hydrocarbon royalty meters? 
You must:
    (1) Ensure that the royalty meter facilities include the following 
approved components (or other MMS-approved components) which must be 
compatible with their connected systems:
    (i) A meter equipped with a nonreset totalizer;
    (ii) A calibrated mechanical displacement (pipe) prover, master 
meter, or tank prover;
    (iii) A proportional-to-flow sampling device pulsed by the meter 
output;
    (iv) A temperature measurement or temperature compensation device; 
and
    (v) A sediment and water monitor with a probe located upstream of 
the divert valve.
    (2) Ensure that the royalty meter facilities accomplish the 
following:
    (i) Prevent flow reversal through the meter;
    (ii) Protect meters subjected to pressure pulsations or surges;
    (iii) Prevent the meter from being subjected to shock pressures 
greater than the maximum working pressure; and
    (iv) Prevent meter bypassing.
    (3) Maintain royalty meter facilities to ensure the following:
    (i) Meters operate within the gravity range specified by the 
manufacturer;
    (ii) Meters operate within the manufacturer's specifications for 
maximum and minimum flow rate for linear accuracy; and
    (iii) Meters are reproven when changes in metering conditions affect 
the meters' performance such as changes in pressure, temperature, 
density (water content), viscosity, pressure, and flow rate.
    (4) Ensure that sampling devices conform to the following:
    (i) The sampling point is in the flowstream immediately upstream or 
downstream of the meter or divert valve (in accordance with the API MPMS 
as incorporated by reference in 30 CFR 250.198);
    (ii) The sample container is vapor-tight and includes a power mixing 
device to allow complete mixing of the sample before removal from the 
container; and
    (iii) The sample probe is in the center half of the pipe diameter in 
a vertical run and is located at least three pipe diameters downstream 
of any pipe fitting within a region of turbulent flow. The sample probe 
can be located in a horizontal pipe if adequate stream conditioning such 
as power mixers or static mixers are installed upstream of the probe 
according to the manufacturer's instructions.
    (c) What are the requirements for run tickets? You must:
    (1) For royalty meters, ensure that the run tickets clearly identify 
all observed data, all correction factors not included in the meter 
factor, and the net standard volume.
    (2) For royalty tanks, ensure that the run tickets clearly identify 
all observed data, all applicable correction factors, on/off seal 
numbers, and the net standard volume.
    (3) Pull a run ticket at the beginning of the month and immediately 
after establishing the monthly meter factor or a malfunction meter 
factor.
    (4) Send all run tickets for royalty meters and tanks to the 
Regional Supervisor within 15 days after the end of the month;
    (d) What are the requirements for liquid hydrocarbon royalty meter 
provings? You must:
    (1) Permit MMS representatives to witness provings;
    (2) Ensure that the integrity of the prover calibration is traceable 
to test measures certified by the National Institute of Standards and 
Technology;
    (3) Prove each operating royalty meter to determine the meter factor 
monthly, but the time between meter factor determinations must not 
exceed 42 days;
    (4) Obtain approval from the Regional Supervisor before proving on a 
schedule other than monthly; and
    (5) Submit copies of all meter proving reports for royalty meters to 
the Regional Supervisor monthly within 15 days after the end of the 
month.
    (e) What are the requirements for calibrating a master meter used in 
royalty meter provings? You must:
    (1) Calibrate the master meter to obtain a master meter factor 
before using

[[Page 420]]

it to determine operating meter factors;
    (2) Use a fluid of similar gravity, viscosity, temperature, and flow 
rate as the liquid hydrocarbons that flow through the operating meter to 
calibrate the master meter;
    (3) Calibrate the master meter monthly, but the time between 
calibrations must not exceed 42 days;
    (4) Calibrate the master meter by recording runs until the results 
of two consecutive runs (if a tank prover is used) or five out of six 
consecutive runs (if a mechanical-displacement prover is used) produce 
meter factor differences of no greater than 0.0002. Lessees must use the 
average of the two (or the five) runs that produced acceptable results 
to compute the master meter factor;
    (5) Install the master meter upstream of any back-pressure or 
reverse flow check valves associated with the operating meter. However, 
the master meter may be installed either upstream or downstream of the 
operating meter; and
    (6) Keep a copy of the master meter calibration report at your field 
location for 2 years.
    (f) What are the requirements for calibrating mechanical-
displacement provers and tank provers? You must:
    (1) Calibrate mechanical-displacement provers and tank provers at 
least once every 5 years according to the API MPMS as incorporated by 
reference in 30 CFR 250.198; and
    (2) Submit a copy of each calibration report to the Regional 
Supervisor within 15 days after the calibration.
    (g) What correction factors must I use when proving meters with a 
mechanical-displacement prover, tank prover, or master meter? Calculate 
the following correction factors using the API MPMS as referenced in 30 
CFR 250.198:
    (1) The change in prover volume due to the effect of temperature on 
steel (Cts);
    (2) The change in prover volume due to the effect of pressure on 
steel (Cps);
    (3) The change in liquid volume due to the effect of temperature on 
a liquid (Ctl); and
    (4) The change in liquid volume due to the effect of pressure on a 
liquid (Cpl).
    (h) What are the requirements for establishing and applying 
operating meter factors for liquid hydrocarbons? (1) If you use a 
mechanical-displacement prover, you must record proof runs until five 
out of six consecutive runs produce a difference between individual runs 
of no greater than .05 percent. You must use the average of the five 
accepted runs to compute the meter factor.
    (2) If you use a master meter, you must record proof runs until 
three consecutive runs produce a total meter factor difference of no 
greater than 0.0005. The flow rate through the meters during the proving 
must be within 10 percent of the rate at which the line meter will 
operate. The final meter factor is determined by averaging the meter 
factors of the three runs;
    (3) If you use a tank prover, you must record proof runs until two 
consecutive runs produce a meter factor difference of no greater than 
.0005. The final meter factor is determined by averaging the meter 
factors of the two runs; and
    (4) You must apply operating meter factors forward starting with the 
date of the proving.
    (i) Under what circumstances does a liquid hydrocarbon royalty meter 
need to be taken out of service, and what must I do? (1) If the 
difference between the meter factor and the previous factor exceeds 
0.0025 it is a malfunction factor, and you must:
    (i) Remove the meter from service and inspect it for damage or wear;
    (ii) Adjust or repair the meter, and reprove it;
    (iii) Apply the average of the malfunction factor and the previous 
factor to the production measured through the meter between the date of 
the previous factor and the date of the malfunction factor; and
    (iv) Indicate that a meter malfunction occurred and show all 
appropriate remarks regarding subsequent repairs or adjustments on the 
proving report.
    (2) If a meter fails to register production, you must:
    (i) Remove the meter from service, repair and reprove it;
    (ii) Apply the previous meter factor to the production run between 
the date of that factor and the date of the failure; and

[[Page 421]]

    (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 API MPMS as incorporated by 
reference in 30 CFR 250.198.

[63 FR 26370, May 12, 1998. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998; 63 FR 33853, June 22, 1998; 64 FR 72794, Dec. 28 
1999; 71 FR 40912, July 19, 2006; 72 FR 25201, May 4, 2007]



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 any 
changes to the previously-approved measurement and/or allocation 
procedures. Your application (which may also include any relevant liquid 
hydrocarbon measurement and surface commingling requests) must be 
accompanied by payment of the service fee listed in Sec. 250.125. The 
service fees are divided into two levels based on complexity, see table 
in Sec. 250.1202(a)(1).
    (2) Design, install, use, maintain, and test measurement equipment 
to ensure accurate and verifiable measurement. You must follow the 
recommendations in API MPMS as incorporated by reference in 30 CFR 
250.198.
    (3) Ensure that the measurement components demonstrate consistent

[[Page 422]]

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.
    (3) If you estimate the volume, document the estimating method, the 
data used, and the volumes estimated.
    (4) You must keep the documentation, including the volume data, 
easily obtainable for inspection at the field location for at least 2 
years, and must retain the documentation at a location of your choosing 
for at least 7 years after the documentation is generated, subject to 
all other document retention and production requirements in 30 U.S.C. 
1713 and 30 CFR part 212.
    (5) Upon the request of the Regional Supervisor, you must provide 
copies of the records.

[63 FR 26370, May 12, 1998. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998; 63 FR 33853, June 22, 1998; 64 FR 72794, Dec. 28, 
1999; 71 FR 40912, July 19, 2006]



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

[[Page 423]]

any changes to the previously approved commingling procedures. Your 
application (which may also include any relevant liquid hydrocarbon and 
gas measurement requests) must be accompanied by payment of the service 
fee listed in Sec. 250.125. The service fees are divided into two 
levels based on complexity, see table in Sec. 250.1202(a)(1).
    (2) Upon the request of the Regional Supervisor, lessees who deliver 
State lease production into a Federal commingling system must provide 
volumetric or fractional analysis data on the State lease production 
through the designated system operator.
    (b) What are the requirements for a periodic well test used for 
allocation? You must:
    (1) Conduct a well test at least once every 2 months unless the 
Regional Supervisor approves a different frequency;
    (2) Follow the well test procedures in 30 CFR part 250, Subpart K; 
and
    (3) Retain the well test data at the field location for 2 years.

[63 FR 26370, May 12, 1998. Redesignated at 63 FR 29479, May 29, 1998; 
63 FR 33853, June 22, 1998; 71 FR 40913, July 19, 2006]



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.



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:

[[Page 424]]

    (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 
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]

[[Page 425]]



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 with the Regional Supervisor for approval.
    (d) You must pay the service fee listed in Sec. 250.125 of this 
part with your request for a voluntary unitization proposal or the 
expansion of a previously approved voluntary unit to include additional 
acreage. Additionally, you must pay the service fee listed in Sec. 
250.125 with your request for unitization revision.

[62 FR 5331, Feb. 5, 1997. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998; 70 FR 49876, Aug. 25, 2005]



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

[[Page 426]]

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 Sec. Sec. 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.



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

[[Page 427]]

 
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.
    Reviewing Officer means an MMS employee assigned to review case 
files and assess civil penalties.
    Violation means failure to comply with the Outer Continental Shelf 
Lands Act (OCSLA) or any other applicable laws, with any regulations 
issued under the OCSLA, or with the terms or provisions of leases, 
licenses, permits, rights-of-way, or other approvals issued under the 
OCSLA.
    Violator means a person responsible for a violation.

[62 FR 42668, Aug. 8, 1997. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 71 FR 23864, Apr. 25, 2006]



Sec. 250.1403  What is the maximum civil penalty?

    The maximum civil penalty is $35,000 per day per violation.

[72 FR 8899, Feb. 28, 2007]



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 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

[[Page 428]]

    (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 Sec. Sec. 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]



          Subpart O_Well Control and Production Safety Training

    Source: 65 FR 49490, Aug. 14, 2000, unless otherwise noted.



Sec. 250.1500  Definitions.

    Terms used in this subpart have the following meaning:
    Employee means direct employees of the lessees who are assigned well 
control or production safety duties.
    I or you means the lessee engaged in oil, gas, or sulphur operations 
in the Outer Continental Shelf (OCS).
    Lessee means a person who has entered into a lease with the United 
States to explore for, develop, and produce the leased minerals. The 
term lessee also includes an owner of operating rights for that lease 
and the MMS-approved assignee of that lease.

[[Page 429]]

    Production safety means production operations as well as the 
installation, repair, testing, maintenance, or operation of surface or 
subsurface safety devices.
    Well control means drilling, well completion, well workover, and 
well servicing operations. For purposes of this subpart, well 
completion/well workover means those operations following the drilling 
of a well that are intended to establish or restore production to a 
well. It includes small tubing operations but does not include well 
servicing. Well servicing means snubbing, coil tubing, and wireline 
operations.



Sec. 250.1501  What is the goal of my training program?

    The goal of your training program must be safe and clean OCS 
operations. To accomplish this, you must ensure that your employees and 
contract personnel engaged in well control or production safety 
operations understand and can properly perform their duties.



Sec. 250.1502  Is there a transition period for complying with the regulations in this subpart?

    (a) During the period October 13, 2000 until October 15, 2002 you 
may either:
    (1) Comply with the provisions of this subpart. If you elect to do 
so, you must notify the Regional Supervisor; or
    (2) Comply with the training regulations in 30 CFR 250.1501 through 
250.1524 that were in effect on June 1, 2000 and are contained in the 30 
CFR, parts 200 to 699, edition revised as of July 1, 1999, as amended on 
December 28, 1999 (64 FR 72794).
    (b) After October 15, 2002, you must comply with the provisions of 
this subpart.



Sec. 250.1503  What are my general responsibilities for training?

    (a) You must establish and implement a training program so that all 
of your employees are trained to competently perform their assigned well 
control and production safety duties. You must verify that your 
employees understand and can perform the assigned well control or 
production safety duties.
    (b) You must have a training plan that specifies the type, 
method(s), length, frequency, and content of the training for your 
employees. Your training plan must specify the method(s) of verifying 
employee understanding and performance. This plan must include at least 
the following information:
    (1) Procedures for training employees in well control or production 
safety practices;
    (2) Procedures for evaluating the training programs of your 
contractors;
    (3) Procedures for verifying that all employees and contractor 
personnel engaged in well control or production safety operations can 
perform their assigned duties;
    (4) Procedures for assessing the training needs of your employees on 
a periodic basis;
    (5) Recordkeeping and documentation procedures; and
    (6) Internal audit procedures.
    (c) Upon request of the District Manager or Regional Supervisor, you 
must provide:
    (1) Copies of training documentation for personnel involved in well 
control or production safety operations during the past 5 years; and
    (2) A copy of your training plan.



Sec. 250.1504  May I use alternative training methods?

    You may use alternative training methods. These methods may include 
computer-based learning, films, or their equivalents. This training 
should be reinforced by appropriate demonstrations and ``hands-on'' 
training. Alternative training methods must be conducted according to, 
and meet the objectives of, your training plan.



Sec. 250.1505  Where may I get training for my employees?

    You may get training from any source that meets the requirements of 
your training plan.



Sec. 250.1506  How often must I train my employees?

    You determine the frequency of the training you provide your 
employees. You must do all of the following:
    (a) Provide periodic training to ensure that employees maintain 
understanding of, and competency in, well control or production safety 
practices;

[[Page 430]]

    (b) Establish procedures to verify adequate retention of the 
knowledge and skills that employees need to perform their assigned well 
control or production safety duties; and
    (c) Ensure that your contractors' training programs provide for 
periodic training and verification of well control or production safety 
knowledge and skills.



Sec. 250.1507  How will MMS measure training results?

    MMS may periodically assess your training program, using one or more 
of the methods in this section.
    (a) Training system audit. MMS or its authorized representative may 
conduct a training system audit at your office. The training system 
audit will compare your training program against this subpart. You must 
be prepared to explain your overall training program and produce 
evidence to support your explanation.
    (b) Employee or contract personnel interviews. MMS or its authorized 
representative may conduct interviews at either onshore or offshore 
locations to inquire about the types of training that were provided, 
when and where this training was conducted, and how effective the 
training was.
    (c) Employee or contract personnel testing. MMS or its authorized 
representative may conduct testing at either onshore or offshore 
locations for the purpose of evaluating an individual's knowledge and 
skills in perfecting well control and production safety duties.
    (d) Hands-on production safety, simulator, or live well testing. MMS 
or its authorized representative may conduct tests at either onshore or 
offshore locations. Tests will be designed to evaluate the competency of 
your employees or contract personnel in performing their assigned well 
control and production safety duties. You are responsible for the costs 
associated with this testing, excluding salary and travel costs for MMS 
personnel.



Sec. 250.1508  What must I do when MMS administers written or oral tests?

    MMS or its authorized representative may test your employees or 
contract personnel at your worksite or at an onshore location. You and 
your contractors must:
    (a) Allow MMS or its authorized representative to administer written 
or oral tests; and
    (b) Identify personnel by current position, years of experience in 
present position, years of total oil field experience, and employer's 
name (e.g., operator, contractor, or sub-contractor company name).



Sec. 250.1509  What must I do when MMS administers or requires hands-on, 

simulator, or other types of testing?

    If MMS or its authorized representative conducts, or requires you or 
your contractor to conduct hands-on, simulator, or other types of 
testing, you must:
    (a) Allow MMS or its authorized representative to administer or 
witness the testing;
    (b) Identify personnel by current position, years of experience in 
present position, years of total oil field experience, and employer's 
name (e.g., operator, contractor, or sub-contractor company name); and
    (c) Pay for all costs associated with the testing, excluding salary 
and travel costs for MMS personnel.



Sec. 250.1510  What will MMS do if my training program does not comply with 

this subpart?

    If MMS determines that your training program is not in compliance, 
we may initiate one or more of the following enforcement actions:
    (a) Issue an Incident of Noncompliance (INC);
    (b) Require you to revise and submit to MMS your training plan to 
address identified deficiencies;
    (c) Assess civil/criminal penalties; or
    (d) Initiate disqualification procedures.



                      Subpart P_Sulphur Operations

    Source: 56 FR 32100, July 15, 1991, unless otherwise noted. 
Redesignated at 63 FR 29479, May 29, 1998.



Sec. 250.1600  Performance standard.

    Operations to discover, develop, and produce sulphur in the OCS 
shall be in

[[Page 431]]

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 conducted for related purposes. Activities 
conducted for related purposes include, but are not limited to, 
production of other minerals, such as salt, for use in the exploration 
for or the development and production of sulphur. The lessee must have 
obtained the right to produce and/or use these other minerals.
    (b) Lessees conducting sulphur operations in the OCS shall comply 
with the requirements of the applicable provisions of subparts A, B, C, 
I, J, M, N, O, and Q of this part.
    (c) Lessees conducting sulphur operations in the OCS are also 
required to comply with the requirements in the applicable provisions of 
subparts D, E, F, H, K, and L of this part where such provisions 
specifically are referenced in this subpart.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 72 FR 25201, May 4, 2007]



Sec. 250.1603  Determination of sulphur deposit.

    (a) Upon receipt of a written request from the lessee, the District 
Manager will determine whether a sulphur deposit has been defined that 
contains sulphur in paying quantities (i.e., sulphur in quantities 
sufficient to yield a return in excess of the costs, after completion of 
the wells, of producing minerals at the wellheads).
    (b) A determination under paragraph (a) of this section shall be 
based upon the following:
    (1) Core analyses that indicate the presence of a producible sulphur 
deposit (including an assay of elemental sulphur);
    (2) An estimate of the amount of recoverable sulphur in long tons 
over a specified period of time; and
    (3) Contour map of the cap rock together with isopach map showing 
the extent and estimated thickness of the sulphur deposit.



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

[[Page 432]]

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 250.490 of this part), 
the lessee shall take appropriate precautions to protect life and 
property, especially during operations such as dismantling wellhead 
equipment and flow lines and circulating the well. The lessee shall also 
take appropriate precautions when H2S is generated as a 
result of sulphur production operations. The lessee shall comply with 
the requirements in Sec. 250.490 of this part as well as the 
requirements of this subpart.
    (c) Welding and burning practices and procedures. All welding, 
burning, and hot-tapping activities involved in drilling, well-
completion, well-workover or production operations shall be conducted 
with properly maintained equipment, trained personnel, and appropriate 
procedures in order to minimize the danger to life and property 
according to the specific requirements in Sec. 250.109 through Sec.  
250.113 of this part.
    (d) Electrical requirements. All electrical equipment and systems 
involved in drilling, well-completion, well-workover, and production 
operations shall be designed, installed, equipped, protected, operated, 
and maintained so as to minimize the danger to life and property in 
accordance with the requirements of Sec. 250.114 of this part.
    (e) Structures on fixed OCS platforms. Derricks, cranes, masts, 
substructures, and related equipment shall be selected, designed, 
installed, used, and maintained so as to be adequate for the potential 
loads and conditions of loading that may be encountered during the 
operations. Prior to moving equipment such as a well-drilling, well-
completion, or well-workover rig or associated equipment or production 
equipment onto a platform, the lessee shall determine the structural 
capability of the platform to safely support the equipment and 
operations, taking into consideration corrosion protection, platform 
age, and previous stresses.
    (f) Traveling-block safety device. After August 14, 1992, all 
drilling units being used for drilling, well-completion, or well-
workover operations that have both a traveling block and a crown block 
shall be equipped with a safety device that is designed to prevent the 
traveling block from striking the crown block. The device shall be 
checked for proper operation weekly and after each drill-line slipping 
operation. The results of the operational check shall be entered in the 
operations log.

[56 FR 32100, July 15, 1991. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998; 67 FR 51760, Aug. 9, 2002; 68 FR 8435, Feb. 20, 
2003]



Sec. 250.1605  Drilling requirements.

    (a) Lessees of OCS sulphur leases shall conduct drilling operations 
in accordance with Sec. Sec. 250.1605 through 250.1619 of this subpart 
and with other requirements of this part, as appropriate.
    (b) Fitness of drilling unit. (1) Drilling units shall be capable of 
withstanding the oceanographic and meteorological conditions for the 
proposed season and location of operations.
    (2) Prior to commencing operation, drilling units shall be made 
available for a complete inspection by the District Manager.
    (3) The lessee shall provide information and data on the fitness of 
the drilling unit to perform the proposed drilling operation. The 
information shall be submitted with, or prior to, the submission of Form 
MMS-123, Application for Permit to Drill (APD), in accordance with 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 Manager or there are 
changes in the equipment that affect the rated capacity of the unit.
    (c) Oceanographic, meteorological, and drilling unit performance 
data. Where oceanographic, meteorological, and drilling unit performance 
data are not otherwise readily available, lessees shall collect and 
report such data upon request to the District Manager. The type of 
information to be collected and

[[Page 433]]

reported will be determined by the District Manager in the interests of 
safety in the conduct of operations and the structural integrity of the 
drilling unit.
    (d) Foundation requirements. When the lessee fails to provide 
sufficient information pursuant to Sec. Sec. 250.211 through 250.228 
and 250.241 through 250.262 of this part to support a determination that 
the seafloor is capable of supporting a specific bottom-founded drilling 
unit under the site-specific soil and oceanographic conditions, the 
District Manager may require that additional surveys and soil borings be 
performed and the results submitted for review and evaluation by the 
District Manager before approval is granted for commencing drilling 
operations.
    (e) Tests, surveys, and samples. (1) Lessees shall drill and take 
cores and/or run well and mud logs through the objective interval to 
determine the presence, quality, and quantity of sulphur and other 
minerals (e.g., oil and gas) in the cap rock and the outline of the 
commercial sulphur deposit.
    (2) Inclinational surveys shall be obtained on all vertical wells at 
intervals not exceeding 1,000 feet during the normal course of drilling. 
Directional surveys giving both inclination and azimuth shall be 
obtained on all directionally drilled wells at intervals not exceeding 
500 feet during the normal course of drilling and at intervals not 
exceeding 200 feet in all planned angle-change portions of the borehole.
    (3) Directional surveys giving both inclination and azimuth shall be 
obtained on both vertically and directionally drilled wells at intervals 
not exceeding 500 feet prior to or upon setting a string of casing, or 
production liner, and at total depth. Composite directional surveys 
shall be prepared with the interval shown from the bottom of the 
conductor casing. In calculating all surveys, a correction from the true 
north to Universal-Transverse-Mercator-Grid-north or Lambert-Grid-north 
shall be made after making the magnetic-to-true-north correction. A 
composite dipmeter directional survey or a composite measurement while-
drilling directional survey will be acceptable as fulfilling the 
applicable requirements of this paragraph.
    (4) Wells are classified as vertical if the calculated average of 
inclination readings weighted by the respective interval lengths between 
readings from surface to drilled depth does not exceed 3 degrees from 
the vertical. When the calculated average inclination readings weighted 
by the length of the respective interval between readings from the 
surface to drilled depth exceeds 3 degrees, the well is classified as 
directional.
    (5) At the request of a holder of an adjoining lease, the Regional 
Supervisor may, for the protection of correlative rights, furnish a copy 
of the directional survey to that leaseholder.
    (f) Fixed drilling platforms. Applications for installation of fixed 
drilling platforms or structures including artificial islands shall be 
submitted in accordance with the provisions of subpart I, Platforms and 
Structures, of this part. Mobile drilling units that have their jacking 
equipment removed or have been otherwise immobilized are classified as 
fixed bottom founded drilling platforms.
    (g) Crane operations. You must operate a crane installed on fixed 
platforms according to 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; 70 FR 51519, Aug. 30, 
2005]



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

[[Page 434]]

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 Manager to determine specific operating requirements, field 
rules may be established for drilling, well completion, or well workover 
on the District Manager's initiative or in response to a request from a 
lessee; such rules may modify the specific requirements of this subpart. 
After field rules have been established, operations in the field shall 
be conducted in accordance with such rules and other requirements of 
this subpart. Field rules may be amended or canceled for cause at any 
time upon the initiative of the District Manager or upon the request of 
a lessee.



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 stresses imposed by tensile, compressive, and buckling 
loads; burst and collapse pressures; thermal effects; and combinations 
thereof. Safety factors in the drilling and casing program designs shall 
be of sufficient magnitude to provide well control during drilling and 
to assure safe operations for the life of the well.
    (4) In cases where cement has filled the annular space back to the 
mud line, the cement may be washed out or displaced to a depth not 
exceeding the depth of the structural casing shoe to facilitate casing 
removal upon well abandonment if the District Manager determines that 
subsurface protection against damage to freshwater aquifers and against 
damage caused by adverse loads, pressures, and fluid flows is not 
jeopardized.
    (5) If there are indications of inadequate cementing (such as lost 
returns, cement channeling, or mechanical failure of equipment), the 
lessee shall evaluate the adequacy of the cementing operations by 
pressure testing the casing shoe. If the test indicates inadequate 
cementing, the lessee shall initiate remedial action as approved by the 
District Manager. For cap rock casing, the test for adequacy of 
cementing shall be the pressure testing of the annulus between the cap 
rock and the conductor casings. The pressure shall not exceed 70 percent 
of the burst pressure of the conductor casing or 70 percent of the 
collapse pressure of the cap rock casing.
    (b) Drive or structural casing. This casing shall be set by driving, 
jetting, or drilling to a minimum depth of 100 feet below the mud line 
or such other depth, as may be required or approved by the District 
Manager, in order to support unconsolidated deposits and to provide hole 
stability for initial drilling operations. If this portion of the hole 
is drilled, a quantity of cement sufficient to fill the annular space 
back to the mud line shall be used.
    (c) Conductor and cap rock casing setting and cementing 
requirements. (1) Conductor and cap rock casing design and setting 
depths shall be based upon relevant engineering and geologic factors 
including the presence or absence of

[[Page 435]]

hydrocarbons, potential hazards, and water depths. The proposed casing 
setting depths may be varied, subject to District Manager approval, to 
permit the casing to be set in a competent formation or through 
formations determined desirable to be isolated from the wellbore by 
casing for safer drilling operations. However, the conductor casing 
shall be set immediately prior to drilling into formations known to 
contain oil or gas or, if unknown, upon encountering such formations. 
Cap rock casing shall be set and cemented through formations known to 
contain oil or gas or, if unknown, upon encountering such formations. 
Upon encountering unexpected formation pressures, the lessee shall 
submit a revised casing program to the District Manager for approval.
    (2) Conductor casing shall be cemented with a quantity of cement 
that fills the calculated annular space back to the mud line. Cement 
fill shall be verified by the observation of cement returns. In the 
event that observation of cement returns is not feasible, additional 
quantities of cement shall be used to assure fill to the mud line.
    (3) Cap rock casing shall be cemented with a quantity of cement that 
fills the calculated annular space to at least 200 feet inside the 
conductor casing. When geologic conditions such as near surface 
fractures and faulting exist, cap rock casing shall be cemented with a 
quantity of cement that fills the calculated annular space to the mud 
line, unless otherwise approved by the District Manager. In brine wells, 
the second cap rock casing shall be cemented with a quantity of cement 
that fills the calculated annular space to at least 200 feet above the 
setting depth of the first cap rock casing.
    (d) Bobtail cap rock casing setting and cementing requirements. (1) 
Bobtail cap rock casing shall be set on or just in cap rock and lapped a 
minimum of 100 feet into the previous casing string.
    (2) Sufficient cement shall be used to fill the annular space to the 
top of the bobtail cap rock casing.
    (e) Production liner setting and cementing requirements. (1) 
Production liners for sulphur wells and bleedwells shall be set in cap 
rock at or above the bottom of the open hole (hole that is open in cap 
rock, below the bottom of the cap rock casing) and lapped into the 
previous casing string or to the surface. For brine wells, the liner 
shall be set in salt and lapped into the previous casing string or to 
the surface.
    (2) The production liner is not required to be cemented unless the 
cap rock contains oil or gas. If the cap rock contains oil or gas, 
sufficient cement shall be used to fill the annular space to the top of 
the production liner.



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

[[Page 436]]

this section. The pipe rams shall be of proper size to fit the drill 
pipe in use.
    (c) Working pressure. The working-pressure rating of any BOP shall 
exceed the surface pressure to which it may be anticipated to be 
subjected.
    (d) BOP equipment. All BOP systems shall be equipped and provided 
with the following:
    (1) An accumulator system that provides sufficient capacity to 
supply 1.5 times the volume necessary to close and hold closed all BOP 
equipment units with a minimum pressure of 200 psi above the precharge 
pressure, without assistance from a charging system. After February 14, 
1992, accumulator regulators supplied by rig air, which do not have a 
secondary source of pneumatic supply, shall be equipped with manual 
overrides or other devices alternately provided to ensure capability of 
hydraulic operations if rig air is lost.
    (2) An automatic backup to the accumulator system. The backup system 
shall be supplied by a power source independent from the power source to 
the primary accumulator system. The automatic backup system shall 
possess sufficient capability to close the BOP and hold it closed.
    (3) At least one operable remote BOP control station in addition to 
the one on the drilling floor. This control station shall be in a 
readily accessible location away from the drilling floor.
    (4) A drilling spool with side outlets, if side outlets are not 
provided in the body of the BOP stack, to provide for separate kill and 
choke lines.
    (5) A choke line and a kill line each equipped with two full-opening 
valves. At least one of the valves on the choke line and one valve on 
the kill line shall be remotely controlled, except that a check valve 
may be installed on the kill line in lieu of the remotely controlled 
valve, provided that two readily accessible manual valves are in place 
and the check valve is placed between the manual valve and the pump.
    (6) A fill-up line above the uppermost preventer.
    (7) A choke manifold designed with consideration of anticipated 
pressures to which it may be subjected, method of well control to be 
employed, surrounding environment, and corrosiveness, volume, and 
abrasiveness of fluids. The choke manifold shall also meet the following 
requirements:
    (i) Manifold and choke equipment subject to well and/or pump 
pressure shall have a rated working pressure at least as great as the 
rated working pressure of the ram-type BOP's or as otherwise approved by 
the District Manager;
    (ii) All components of the choke manifold system shall be protected 
from freezing by heating, draining, or filling with proper fluids; and
    (iii) When buffer tanks are installed downstream of the choke 
assemblies for the purpose of manifolding the bleed lines together, 
isolation valves shall be installed on each line.
    (8) Valves, pipes, flexible steel hoses, and other fittings upstream 
of, and including, the choke manifold with a pressure rating at least as 
great as the rated working pressure of the ram-type BOP's unless 
otherwise approved by the District Manager.
    (9) A wellhead assembly with a rated working pressure that exceeds 
the pressure to which it might be subjected.
    (10) The following system components:
    (i) A kelly cock (an essentially full-opening valve) installed below 
the swivel and a similar valve of such design that it can be run through 
the BOP stack installed at the bottom of the kelly. A wrench to fit each 
valve shall be stored in a location readily accessible to the drilling 
crew;
    (ii) An inside BOP and an essentially full-opening, drill-string 
safety valve in the open position on the rig floor at all times while 
drilling operations are being conducted. These valves shall be 
maintained on the rig floor to fit all connections that are in the drill 
string. A wrench to fit the drill-string safety valve shall be stored in 
a location readily accessible to the drilling crew;
    (iii) A safety valve available on the rig floor assembled with the 
proper connection to fit the casing string being run in the hole; and
    (iv) Locking devices installed on the ram-type preventers.
    (e) BOP requirements. Prior to drilling below cap rock casing, a BOP 
system shall be installed consisting of at least three remote-
controlled, hydraulically

[[Page 437]]

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 Manager. Annular type BOP's shall be pressure tested with water 
to 70 percent of rated working pressure or as otherwise approved by the 
District Manager.
    (c) In conjunction with the weekly pressure test of BOP systems 
required in paragraph (d) of this section, the choke manifold valves, 
upper and lower kelly cocks, and drill-string safety valves shall be 
pressure tested to pipe-ram test pressures. Safety valves with proper 
casing connections shall be actuated prior to running casing.
    (d) BOP system shall be pressure tested as follows:
    (1) When installed;
    (2) Before drilling out each string of casing or before continuing 
operations in cases where cement is not drilled out;
    (3) At least once each week, but not exceeding 7 days between 
pressure tests, alternating between control stations. If either control 
system is not functional, further drilling operations shall be suspended 
until that system becomes operable. A period of more than 7 days between 
BOP tests is allowed when there is a stuck drill pipe or there are 
pressure control operations and remedial efforts are being performed, 
provided that the pressure tests are conducted as soon as possible and 
before normal operations resume. The date, time, and reason for 
postponing pressure testing shall be entered into the driller's report. 
Pressure testing shall be performed at intervals to allow each drilling 
crew to operate the equipment. The weekly pressure test is not required 
for blind and blind-shear rams;
    (4) Bind and blind-shear rams shall be actuated at least once every 
7 days. Closing pressure on the blind and blind-shear rams greater than 
necessary to indicate proper operation of the rams is not required;
    (5) Variable bore-pipe rams shall be pressure tested against all 
sizes of pipe in use, excluding drill collars and bottomhole tools; and
    (6) Following the disconnection or repair of any well-pressure 
containment seal in the wellhead/BOP stack assembly. In this situation, 
the pressure tests may be limited to the affected component.
    (e) All BOP systems shall be inspected and maintained to assure that 
the equipment will function properly. The BOP systems shall be visually 
inspected at least once each day. The manufacturer's recommended 
inspection and maintenance procedures are acceptable as guidelines in 
complying with this requirement.
    (f) The lessee shall record pressure conditions during BOP tests on 
pressure charts, unless otherwise approved by the District Manager. The 
test duration for each BOP component tested shall be sufficient to 
demonstrate that the component is effectively holding pressure. The 
charts shall be certified as correct by the operator's representative at 
the facility.
    (g) The time, date, and results of all pressure tests, actuations, 
inspections, and crew drills of the BOP system and system components 
shall be recorded in the driller's report. The BOP tests shall be 
documented in accordance with the following:
    (1) The documentation shall indicate the sequential order of BOP and 
auxiliary equipment testing and the pressure and duration of each test. 
As an

[[Page 438]]

alternate, the documentation in the driller's report may reference a BOP 
test plan that contains the required information and is retained on file 
at the facility.
    (2) The control station used during the test shall be identified in 
the driller's report.
    (3) Any problems or irregularities observed during BOP and auxiliary 
equipment testing and any actions taken to remedy such problems or 
irregularities shall be noted in the driller's report.
    (4) Documentation required to be entered in the driller's report may 
instead be referenced in the driller's report. All records, including 
pressure charts, driller's report, and referenced documents, pertaining 
to BOP tests, actuations, and inspections, shall be available for MMS 
review at the facility for the duration of the drilling activity. 
Following completion of the drilling activity, all drilling records 
shall be retained for a period of 2 years at the facility, at the 
lessee's field office nearest the OCS facility, or at another location 
conveniently available to the District Manager.



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. 250.462 of this part 
or as approved by the District Manager.

[56 FR 32100, July 15, 1991. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998; 68 FR 8435, Feb. 20, 2003]



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 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

[[Page 439]]

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. 
250.455 through Sec. 250.459 of this part, except that the installation 
of an operable degasser in the mud system as required in Sec. 
250.456(g) is not required for sulphur operations.

[56 FR 32100, July 15, 1991. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998; 68 FR 8435, Feb. 20, 2003]



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 Manager 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) Before drilling a well under an approved Exploration Plan, 
Development and Production Plan, or Development Operations Coordination 
Document, you must file Form MMS-123, APD, with the District Manager for 
approval. The submission of your APD must be accompanied by payment of 
the service fee listed in Sec. 250.125. Before starting operations, you 
must receive written approval from the District Manager unless you 
received oral approval under Sec. 250.140.
    (b) An APD shall include rated capacities of the proposed drilling 
unit and of major drilling equipment. After a drilling unit has been 
approved for use in an MMS district, the information need not be 
resubmitted unless required by the District Manager or there are changes 
in the equipment that affect the rated capacity of the unit.
    (c) An APD shall include a fully completed Form MMS-123 and the 
following:
    (1) A plat, drawn to a scale of 2,000 feet to the inch, showing the 
surface and subsurface location of the well to be drilled and of all the 
wells previously drilled in the vicinity from which information is 
available. For development wells on a lease, the wells previously 
drilled in the vicinity need not be shown on the plat. Locations shall 
be indicated in feet from the nearest block line;
    (2) The design criteria considered for the well and for well 
control, including the following:
    (i) Pore pressure;
    (ii) Formation fracture gradients;
    (iii) Potential lost circulation zones;
    (iv) Mud weights;
    (v) Casing setting depths;
    (vi) Anticipated surface pressures (which for purposes of this 
section are defined as the pressure that can reasonably be expected to 
be exerted upon a casing string and its related wellhead equipment). In 
the calculation of anticipated surface pressure, the lessee shall take 
into account the drilling, completion, and producing conditions. The 
lessee shall consider mud densities to be used below various casing 
strings, fracture gradients of the exposed formations, casing setting 
depths, and cementing intervals, total well depth,

[[Page 440]]

formation fluid type, and other pertinent conditions. Considerations for 
calculating anticipated surface pressure may vary for each segment of 
the well. The lessee shall include as a part of the statement of 
anticipated surface pressure the calculations used to determine this 
pressure during the drilling phase and the completion phase, including 
the anticipated surface pressure used for production string design; and
    (vii) If a shallow hazards site survey is conducted, the lessee 
shall submit with or prior to the submittal of the APD, two copies of a 
summary report describing the geological and manmade conditions present. 
The lessee shall also submit two copies of the site maps and data 
records identified in the survey strategy.
    (3) A BOP equipment program including the following:
    (i) The pressure rating of BOP equipment,
    (ii) A schematic drawing of the diverter system to be used (plan and 
elevation views) showing spool outlet internal diameter(s); diverter 
line lengths and diameters, burst strengths, and radius of curvature at 
each turn; valve type, size, working-pressure rating, and location; the 
control instrumentation logic; and the operating procedure to be used by 
personnel, and
    (iii) A schematic drawing of the BOP stack showing the inside 
diameter of the BOP stack and the number of annular, pipe ram, variable-
bore pipe ram, blind ram, and blind-shear ram preventers.
    (4) A casing program including the following:
    (i) Casing size, weight, grade, type of connection and setting 
depth, and
    (ii) Casing design safety factors for tension, collapse, and burst 
with the assumptions made to arrive at these values.
    (5) The drilling prognosis including the following:
    (i) Estimated coring intervals,
    (ii) Estimated depths to the top of significant marker formations, 
and
    (iii) Estimated depths at which encounters with fresh water, 
sulphur, oil, gas, or abnormally pressured water are expected.
    (6) A cementing program including type and amount of cement in cubic 
feet to be used for each casing string;
    (7) A mud program including the minimum quantities of mud and mud 
materials, including weight materials, to be kept at the site;
    (8) A directional survey program for directionally drilled wells;
    (9) An H2S Contingency Plan, if applicable, and if not 
previously submitted; and
    (10) Such other information as may be required by the District 
Manager.
    (d) Public information copies of the APD shall be submitted in 
accordance with Sec. 250.186 of this part.

[56 FR 32100, July 15, 1991, as amended at 58 FR 49928, Sept. 24, 1993. 
Redesignated and amended at 63 FR 29479, 29487, May 29, 1998; 64 FR 
72794, Dec. 28, 1999; 71 FR 19646, Apr. 17, 2006; 71 FR 40913, July 19, 
2006]



Sec. 250.1618  Application for permit to modify.

    (a) You must submit requests for changes in plans, changes in major 
drilling equipment, proposals to deepen, sidetrack, complete, workover, 
or plug back a well, or engage in similar activities to the District 
Manager on Form MMS-124, Application for Permit to Modify (APM). The 
submission of your APM must be accompanied by payment of the service fee 
listed in Sec. 250.125. Before starting operations associated with the 
change, you must receive written approval from the District Manager 
unless you received oral approval under Sec. 250.140.
    (b) The Form MMS-124 submittal shall contain a detailed statement of 
the proposed work that will materially change from the work described in 
the approved APD. Information submitted shall include the present state 
of the well, including the production liner and last string of casing, 
the well depth and production zone, and the well's capability to 
produce. Within 30 days after completion of the work, a subsequent 
detailed report of all the work done and the results obtained shall be 
submitted.

[[Page 441]]

    (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; 71 FR 40913, July 19, 2006]



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 Manager. The records shall 
contain a description of any significant malfunction or problem; all the 
formations penetrated; the content and character of sulphur in each 
formation if cored and analyzed; the kind, weight, size, grade, and 
setting depth of casing; all well logs and surveys run in the wellbore; 
and all other information required by the District Manager in the 
interests of resource evaluation, prevention of waste, conservation of 
natural resources, protection of correlative rights, safety of 
operations, and environmental protection.
    (b) When drilling operations are suspended or temporarily prohibited 
under the provisions of 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 
Manager duplicate copies of the records of all activities related to and 
conducted during the suspension or temporary prohibition on, or attached 
to, Form MMS-125, End of Operations Report, or Form MMS-124, Application 
for Permit to Modify, as appropriate.
    (c) Upon request by the District Manager or Regional Supervisor, the 
lessee shall furnish the following:
    (1) Copies of the records of any of the well operations specified in 
paragraph (a) of this section;
    (2) Copies of the driller's report at a frequency as determined by 
the District Manager. Items to be reported include spud dates, casing 
setting depths, cement quantities, casing characteristics, mud weights, 
lost returns, and any unusual activities; and
    (3) Legible, exact copies of reports on cementing, acidizing, 
analyses of cores, testing, or other similar services.
    (d) As soon as available, the lessee shall transmit copies of logs 
and charts developed by well-logging operations, directional-well 
surveys, and core analyses. Composite logs of multiple runs and 
directional-well surveys shall be transmitted to the District Manager in 
duplicate as soon as available but not later than 30 days after 
completion of such operations for each well.
    (e) If the District Manager determines that circumstances warrant, 
the lessee shall submit any other reports and records of operations in 
the manner and form prescribed by the District Manager.

[56 FR 32100, July 15, 1991, as amended at 58 FR 49928, Sept. 24, 1993. 
Redesignated and amended at 63 FR 29479, 29487, May 29, 1998; 64 FR 
72794, Dec. 28, 1999; 72 FR 25201, May 4, 2007]



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 Sec. Sec. 250.1620 through 250.1626 of this part and other 
provisions of this part as appropriate (see Sec. Sec. 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

[[Page 442]]

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 Manager. Approval 
for such operations shall be requested on Form MMS-124. Approvals by the 
District Manager shall be based upon a determination that the operations 
will be conducted in a manner to protect against harm or damage to life, 
property, natural resources of the OCS, including any mineral deposits, 
the national security or defense, or the marine, coastal, or human 
environment.
    (b) The following information shall be submitted with Form MMS-124 
(or with Form MMS-123):
    (1) A brief description of the well-completion or well-workover 
procedures to be followed;
    (2) When changes in existing subsurface equipment are proposed, a 
schematic drawing showing the well equipment; and
    (3) Where the well is in zones known to contain H2S or 
zones where the presence of H2S is unknown, a description of 
the safety precautions to be implemented.
    (c)(1) Within 30 days after completion, Form MMS-125, including a 
schematic of the tubing and the results of any well tests, shall be 
submitted to the District Manager.
    (2) Within 30 days after completing the well-workover operation, 
except routine operations, Form MMS-124 shall be submitted to the 
District Manager and shall include the results of any well tests and a 
new schematic of the well if any subsurface equipment has been changed.

[56 FR 32100, July 15, 1991, as amended at 58 FR 49928, Sept. 24, 1993. 
Redesignated at 63 FR 29479, May 29, 1998]



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 continuously monitored during 
well-completion and well-workover operations and shall not be left 
unattended at any time unless the well is shut in and secured;
    (b) The following well-control fluid equipment shall be installed, 
maintained, and utilized:
    (1) A fill-up line above the uppermost BOP,
    (2) A well-control fluid-volume measuring device for determining 
fluid volumes when filling the hole on trips, and
    (3) A recording mud-pit-level indicator to determine mud-pit-volume 
gains and losses. This indicator shall include both a visual and an 
audible warning device.
    (c) When coming out of the hole with drill pipe or a workover 
string, the annulus shall be filled with well-control fluid before the 
change in fluid level decreases the hydrostatic pressure 75 psi or every 
five stands of drill pipe or workover string, whichever gives a lower 
decrease in hydrostatic pressure. The number of stands of drill pipe or 
workover string and drill collars that may be pulled prior to filling 
the hole and the equivalent well-control fluid volume shall be 
calculated and posted near the operator's station. A mechanical, 
volumetric, or electronic device for measuring the amount of well-
control fluid required to fill the hole shall be utilized.



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:

[[Page 443]]

    (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.
    (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 Manager. Annular type BOP's shall be pressure tested with water 
to 70 percent of rated working pressure or as otherwise approved by the 
District Manager.
    (c) In conjunction with the weekly pressure test of BOP systems 
required in paragraph (d) of this section, the choke manifold valves, 
upper and lower kelly cocks, and drill-string safety valves shall be 
pressure tested to pipe-ram test pressures. Safety valves with proper 
casing connections shall be actuated prior to running casing.
    (d) BOP system shall be pressure tested as follows:

[[Page 444]]

    (1) When installed;
    (2) Before drilling out each string of casing or before continuing 
operations in cases where cement is not drilled out;
    (3) At least once each week, but not exceeding 7 days between 
pressure tests, alternating between control stations. If either control 
system is not functional, further drilling operations shall be suspended 
until that system becomes operable. A period of more than 7 days between 
BOP tests is allowed when there is a stuck drill pipe or there are 
pressure control operations, and remedial efforts are being performed, 
provided that the pressure tests are conducted as soon as possible and 
before normal operations resume. The time, date, and reason for 
postponing pressure testing shall be entered into the driller's report. 
Pressure testing shall be performed at intervals to allow each drilling 
crew to operate the equipment. The weekly pressure test is not required 
for blind and blind-shear rams;
    (4) Blind and blind-shear rams shall be actuated at least once every 
7 days. Closing pressure on the blind and blind-shear rams greater than 
necessary to indicate proper operation of the rams is not required;
    (5) Variable bore-pipe rams shall be pressure tested against all 
sizes of pipe in use, excluding drill collars and bottomhole tools; and
    (6) Following the disconnection or repair of any well-pressure 
containment seal in the wellhead/BOP stack assembly, the pressure tests 
may be limited to the affected component.
    (e) All personnel engaged in well-completion operations shall 
participate in a weekly BOP drill to familiarize crew members with 
appropriate safety measures.
    (f) The lessee shall record pressure conditions during BOP tests on 
pressure charts, unless otherwise approved by the District Manager. The 
test duration for each BOP component tested shall be sufficient to 
demonstrate that the component is effectively holding pressure. The 
charts shall be certified as correct by the operator's representative at 
the facility.
    (g) The time, date, and results of all pressure tests, actuations, 
inspections, and crew drills of the BOP system and system components 
shall be recorded in the operations log. The BOP tests shall be 
documented in accordance with the following:
    (1) The documentation shall indicate the sequential order of BOP and 
auxiliary equipment testing and the pressure and duration of each test. 
As an alternate, the documentation in the operations log may reference a 
BOP test plan that contains the required information and is retained on 
file at the facility.
    (2) The control station used during the test shall be identified in 
the operations log.
    (3) Any problems or irregularities observed during BOP and auxiliary 
equipment testing and any actions taken to remedy such problems or 
irregularities shall be noted in the operations log.
    (4) Documentation required to be entered in the driller's report may 
instead be referenced in the driller's report. All records, including 
pressure charts, driller's report, and referenced documents, pertaining 
to BOP tests, actuations, and inspections shall be available for MMS 
review at the facility for the duration of the drilling activity. 
Following completion of the drilling activity, all drilling records 
shall be retained for a period of 2 years at the facility, at the 
lessee's field office nearest the OCS facility, or at another location 
conveniently available to the District Manager.



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

[[Page 445]]

Sec. Sec. 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 
Manager for approval. The application shall include information relative 
to the proposed design and installation features. Information concerning 
approved design and installation features shall be maintained by the 
lessee at the lessee's offshore field office nearest the OCS facility or 
at another location conveniently available to the District Manager. All 
approvals are subject to field verification. The application shall 
include the following:
    (1) A schematic flow diagram showing size, capacity, design, working 
pressure of separators, storage tanks, compressor pumps, metering 
devices, and other sulphur-handling vessels;
    (2) A schematic piping diagram showing the size and maximum 
allowable working pressures as determined in accordance with API RP 14E, 
Recommended Practice for Design and Installation of Offshore Production 
Platform Piping Systems;
    (3) Electrical system information including a plan of each platform 
deck, outlining all hazardous areas classified according to API RP 500, 
Recommended Practice for Classification of Locations for Electrical 
Installations at Petroleum Facilities Classified as Class I, Division 1 
and Division 2, or API RP 505, Recommended Practice for Classification 
of Locations for Electrical Installations at Petroleum Facilities 
Classified as Class I, Zone 0, Zone 1, and Zone 2, and outlining areas 
in which potential ignition sources are to be installed;
    (4) Certification that the design for the mechanical and electrical 
systems to be installed were approved by registered professional 
engineers. After these systems are installed, the lessee shall submit a 
statement to the District Manager certifying that the new installations 
conform to the approved designs of this subpart.
    (c) Hydrocarbon handling vessels associated with fuel gas system. 
You must protect hydrocarbon handling vessels associated with the fuel 
gas system with a basic and ancillary surface safety system. This system 
must be designed, analyzed, installed, tested, and maintained in 
operating condition in accordance with API RP 14C, Analysis, Design, 
Installation, and Testing of Basic Surface Safety Systems for Offshore 
Production Platforms (incorporated by reference as specified in Sec. 
250.198). If processing components are to be utilized, other than those 
for which Safety Analysis Checklists are included in API RP 14C, you 
must use the analysis technique and documentation specified therein to 
determine the effect and requirements of these components upon the 
safety system.
    (d) Approval of safety-systems design and installation features for 
fuel gas system. Prior to installation, the lessee shall submit a fuel 
gas safety system application, in duplicate, to the District Manager for 
approval. The application shall include information relative to the 
proposed design and installation features. Information concerning 
approved design and installation features shall be maintained by the 
lessee at the lessee's offshore field office nearest the OCS facility or 
at another location conveniently available to the District Manager. All 
approvals are subject to field verification. The application shall 
include the following:
    (1) A schematic flow diagram showing size, capacity, design, working 
pressure of separators, storage tanks, compressor pumps, metering 
devices, and other hydrocarbon-handling vessels;

[[Page 446]]

    (2) A schematic flow diagram (API RP 14C, Figure E1, incorporated by 
reference as specified in Sec. 250.198) and the related Safety Analysis 
Function Evaluation chart (API RP 14C, subsection 4.3c, incorporated by 
reference as specified in Sec. 250.198).
    (3) A schematic piping diagram showing the size and maximum 
allowable working pressures as determined in accordance with API RP 14E, 
Design and lnstallation of Offshore Production Platform Piping Systems;
    (4) Electrical system information including the following:
    (i) A plan of each platform deck, outlining all hazardous areas 
classified according to API RP 500, Recommended Practice for 
Classification of Locations for Electrical Installations at Petroleum 
Facilities Classified as Class I, Division 1 and Divisions 2, or API RP 
505, Recommended Practice for Classification of Locations for Electrical 
Installations at Petroleum Facilities Classified as Class I, Zone 0, 
Zone 1, and Zone 2, and outlining areas in which potential ignition 
sources are to be installed;
    (ii) All significant hydrocarbon sources and a description of the 
type of decking, ceiling, walls (e.g., grating or solid), and firewalls; 
and
    (iii) Elementary electrical schematic of any platform safety 
shutdown system with a functional legend.
    (5) Certification that the design for the mechanical and electrical 
systems to be installed was approved by registered professional 
engineers. After these systems are installed, the lessee shall submit a 
statement to the District Manager certifying that the new installations 
conform to the approved designs of this subpart; and
    (6) Design and schematics of the installation and maintenance of all 
fire- and gas-detection systems including the following:
    (i) Type, location, and number of detection heads;
    (ii) Type and kind of alarm, including emergency equipment to be 
activated;
    (iii) Method used for detection;
    (iv) Method and frequency of calibration; and
    (v) A functional block diagram of the detection system, including 
the electric power supply.

[53 FR 10690, Apr. 1, 1988, as amended at 61 FR 60026, Nov. 26, 1996. 
Redesignated at 63 FR 29479, May 29, 1998, as amended at 65 FR 219, Jan. 
4, 2000; 67 FR 51760, Aug. 9, 2002]



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 must be designed, fabricated, and code stamped in 
accordance with the applicable provisions of sections I, IV, and VIII of 
the American Society of Mechanical Engineers (ASME) Boiler and Pressure 
Vessel Code. Pressure and fired vessels must have maintenance 
inspection, rating, repair, and alteration performed in accordance with 
the applicable provisions of the American Petroleum Institute's Pressure 
Vessel Inspection Code: In-Service Inspection, Rating, Repair, and 
Alteration, API 510 (except Sec. Sec. 6.5 and 8.5) (incorporated by 
reference as specified in Sec. 250.198).
    (i) Pressure safety relief valves shall be designed, installed, and 
maintained in accordance with applicable provisions of sections I, IV, 
and VIII of the ANSI/ASME Boiler and Pressure Vessel Code. 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

[[Page 447]]

to the District Manager. The high-pressure sensor shall be set no higher 
than 15 percent or 5 psi, whichever is greater, above the highest 
operating pressure of the vessel. This setting shall also be set 
sufficiently below (15 percent or 5 psi, whichever is greater) the 
safety relief valve's set pressure to assure that the high-pressure 
sensor sounds an alarm before the safety relief valve starts relieving. 
The low-pressure sensor shall sound an alarm no lower than 15 percent or 
5 psi, whichever is greater, below the lowest pressure in the operating 
range.
    (2) Engine exhaust. You must equip engine exhausts to comply with 
the insulation and personnel protection requirements of API RP 14C, 
section 4.2c(4) (incorporated by reference as specified in Sec. 
250.198). Exhaust piping from diesel engines must be equipped with spark 
arresters.
    (3) Firefighting systems. Firefighting systems shall conform to 
subsection 5.2, Fire Water Systems, of API RP 14G, Recommended Practice 
for Fire Prevention and Control on Open Type Offshore Production 
Platforms, and shall be subject to the approval of the District Manager. 
Additional requirements shall apply as follows:
    (i) A firewater system consisting of rigid pipe with firehose 
stations shall be installed. The firewater system shall be installed to 
provide needed protection, especially in areas where fuel handling 
equipment is located.
    (ii) Fuel or power for firewater pump drivers shall be available for 
at least 30 minutes of run time during platform shut-in time. If 
necessary, an alternate fuel or power supply shall be installed to 
provide for this pump-operating time unless an alternate firefighting 
system has been approved by the District Manager;
    (iii) A firefighting system using chemicals may be used in lieu of a 
water system if the District Manager determines that the use of a 
chemical system provides equivalent fire-protection control; and
    (iv) A diagram of the firefighting system showing the location of 
all firefighting equipment shall be posted in a prominent place on the 
facility or structure.
    (4) Fire- and gas-detection system. (i) Fire (flame, heat, or smoke) 
sensors shall be installed in all enclosed classified areas. Gas sensors 
shall be installed in all inadequately ventilated, enclosed classified 
areas. Adequate ventilation is defined as ventilation that is sufficient 
to prevent accumulation of significant quantities of vapor-air mixture 
in concentrations over 25 percent of the lower explosive limit. One 
approved method of providing adequate ventilation is a change of air 
volume each 5 minutes or 1 cubic foot of air-volume flow per minute per 
square foot of solid floor area, whichever is greater. Enclosed areas 
(e.g., buildings, living quarters, or doghouses) are defined as those 
areas confined on more than four of their six possible sides by walls, 
floors, or ceilings more restrictive to air flow than grating or fixed 
open louvers and of sufficient size to allow entry of personnel. A 
classified area is any area classified Class I, Group D, Division 1 or 
2, following the guidelines of API RP 500, or any area classified Class 
I, Zone 0, Zone 1, or Zone 2, following the guidelines of API RP 505.
    (ii) All detection systems shall be capable of continuous 
monitoring. Fire-detection systems and portions of combustible gas-
detection systems related to the higher gas concentration levels shall 
be of the manual-reset type. Combustible gas-detection systems related 
to the lower gas-concentration level may be of the automatic-reset type.
    (iii) A fuel-gas odorant or an automatic gas-detection and alarm 
system is required in enclosed, continuously manned areas of the 
facility that are provided with fuel gas. Living quarters and doghouses 
not containing a gas source and not located in a classified area do not 
require a gas detection system.
    (iv) The District Manager may require the installation and 
maintenance of a gas detector or alarm in any potentially hazardous 
area.
    (v) Fire- and gas-detection systems must be an approved type, 
designed and installed according to API RP 14C, API RP 14G, and either 
API RP 14F or API RP 14FZ (the preceding four documents incorporated by 
reference as specified in Sec. 250.198).

[[Page 448]]

    (c) General platform operations.Safety devices shall not be bypassed 
or blocked out of service unless they are temporarily out of service for 
startup, maintenance, or testing procedures. Only the minimum number of 
safety devices shall be taken out of service. Personnel shall monitor 
the bypassed or blocked out functions until the safety devices are 
placed back in service. Any safety device that is temporarily out of 
service shall be flagged by the person taking such device out of 
service.

[53 FR 10690, Apr. 1, 1988, as amended at 61 FR 60026, Nov. 26, 1996. 
Redesignated at 63 FR 29479, May 29, 1998, as amended at 64 FR 72794, 
Dec. 28, 1999; 65 FR 219, Jan. 4, 2000; 67 FR 51760, Aug. 9, 2002; 68 FR 
43298, July 22, 2003; 70 FR 7403, Feb. 14, 2005; 72 FR 12096, Mar. 15, 
2007]



Sec. 250.1630  Safety-system testing and records.

    (a) Inspection and testing. You must inspect and successfully test 
safety system devices at the interval specified below or more frequently 
if operating conditions warrant. Testing must be in accordance with API 
RP 14C, Appendix D (incorporated by reference as specified in Sec. 
250.198). For safety system devices other than those listed in API RP 
14C, Appendix D, you must utilize the analysis technique and 
documentation specified therein for inspection and testing of these 
components, and the following:
    (1) Safety relief valves on the natural gas feed system for power 
plant operations such as pressure safety valves shall be inspected and 
tested for operation at least once every 12 months. These valves shall 
be either bench tested or equipped to permit testing with an external 
pressure source.
    (2) The following safety devices (excluding electronic pressure 
transmitters and level sensors) must be inspected and tested at least 
once each calendar month, but at no time may more than 6 weeks elapse 
between tests:
    (i) All pressure safety high or pressure safety low, and
    (ii) All level safety high and level safety low controls.
    (3) The following electronic pressure transmitters and level sensors 
must be inspected and tested at least once every 3 months, but at no 
time may more than 120 days elapse between tests:
    (i) All PSH or PSL, and
    (ii) All LSH and LSL controls.
    (4) All pumps for firewater systems shall be inspected and operated 
weekly.
    (5) All fire- (flame, heat, or smoke) and gas-detection systems 
shall be inspected and tested for operation and recalibrated every 3 
months provided that testing can be performed in a nondestructive 
manner.
    (6) Prior to the commencement of production, the lessee shall notify 
the District Manager when the lessee is ready to conduct a preproduction 
test and inspection of the safety system. The lessee shall also notify 
the District Manager upon commencement of production in order that a 
complete inspection may be conducted.
    (b) Records. The lessee shall maintain records for a period of 2 
years for each safety device installed. These records shall be 
maintained by the lessee at the lessee's field office nearest the OCS 
facility or another location conveniently available to the District 
Manager. These records shall be available for MMS review. The records 
shall show the present status and history of each safety device, 
including dates and details of installation, removal, inspection, 
testing, repairing, adjustments, and reinstallation.

[56 FR 32100, July 15, 1991. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 67 FR 51761, Aug. 9, 2002]



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 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.

[[Page 449]]



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.



                  Subpart Q_Decommissioning Activities

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

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

                                 General



Sec. 250.1700  What do the terms ``decommissioning'', ``obstructions'', and 

``facility'' mean?

    (a) Decommissioning means:
    (1) Ending oil, gas, or sulphur operations; and
    (2) Returning the lease or pipeline right-of-way to a condition that 
meets the requirements of regulations of MMS and other agencies that 
have jurisdiction over decommissioning activities.
    (b) Obstructions means structures, equipment, or objects that were 
used in oil, gas, or sulphur operations or marine growth that, if left 
in place, would hinder other users of the OCS. Obstructions may include, 
but are not limited to, shell mounds, wellheads, casing stubs, mud line 
suspensions, well protection devices, subsea trees, jumper assemblies, 
umbilicals, manifolds, termination skids, production and pipeline 
risers, platforms, templates, pilings, pipelines, pipeline valves, and 
power cables.
    (c) Facility means any installation other than a pipeline used for 
oil, gas, or sulphur activities that is permanently or temporarily 
attached to the seabed on the OCS. Facilities include production and 
pipeline risers, templates, pilings, and any other facility or equipment 
that constitutes an obstruction such as jumper assemblies, termination 
skids, umbilicals, anchors, and mooring lines.

[67 FR 35406, May 17, 2002; 67 FR 66047, Oct. 30, 2002]



Sec. 250.1701  Who must meet the decommissioning obligations in this subpart?

    (a) Lessees and owners of operating rights are jointly and severally 
responsible for meeting decommissioning obligations for facilities on 
leases, including the obligations related to lease-term pipelines, as 
the obligations accrue and until each obligation is met.
    (b) All holders of a right-of-way are jointly and severally liable 
for meeting decommissioning obligations for facilities on their right-
of-way, including

[[Page 450]]

right-of-way pipelines, as the obligations accrue and until each 
obligation is met.
    (c) In this subpart, the terms ``you'' or ``I'' refer to lessees and 
owners of operating rights, as to facilities installed under the 
authority of a lease, and to right-of-way holders as to facilities 
installed under the authority of a right-of-way.



Sec. 250.1702  When do I accrue decommissioning obligations?

    You accrue decommissioning obligations when you do any of the 
following:
    (a) Drill a well;
    (b) Install a platform, pipeline, or other facility;
    (c) Create an obstruction to other users of the OCS;
    (d) Are or become a lessee or the owner of operating rights of a 
lease on which there is a well that has not been permanently plugged 
according to this subpart, a platform, a lease term pipeline, or other 
facility, or an obstruction;
    (e) Are or become the holder of a pipeline right-of-way on which 
there is a pipeline, platform, or other facility, or an obstruction; or
    (f) Re-enter a well that was previously plugged according to this 
subpart.



Sec. 250.1703  What are the general requirements for decommissioning?

    When your facilities are no longer useful for operations, you must:
    (a) Get approval from the appropriate District Manager before 
decommissioning wells and from the Regional Supervisor before 
decommissioning platforms and pipelines or other facilities;
    (b) Permanently plug all wells;
    (c) Remove all platforms and other facilities;
    (d) Decommission all pipelines;
    (e) Clear the seafloor of all obstructions created by your lease and 
pipeline right-of-way operations; and
    (f) Conduct all decommissioning activities in a manner that is safe, 
does not unreasonably interfere with other uses of the OCS, and does not 
cause undue or serious harm or damage to the human, marine, or coastal 
environment.



Sec. 250.1704  When must I submit decommissioning applications and reports?

    You must submit decommissioning applications and receive approval 
and submit subsequent reports according to the table in this section.

             Decommissioning Applications and Reports Table
------------------------------------------------------------------------
 Decommissioning applications
          and reports               When to submit        Instructions
------------------------------------------------------------------------
(a) Initial platform removal    In the Pacific OCS      Include
 application [not required in    Region or Alaska OCS    information
 the Gulf of Mexico OCS          Region, submit the      required under
 Region].                        application to the      Sec.
                                 Regional Supervisor     250.1726.
                                 at least 2 years
                                 before production is
                                 projected to cease.
(b) Final removal application   Before removing a       Include
 for a platform or other         platform or other       information
 facility.                       facility in the Gulf    required under
                                 of Mexico OCS Region,   Sec.
                                 or not more than 2      250.1727.
                                 years after the
                                 submittal of an
                                 initial platform
                                 removal application
                                 to the Pacific OCS
                                 Region and the Alaska
                                 OCS Region.
(c) Post-removal report for a   Within 30 days after    Include
 platform or other facility.     you remove a platform   information
                                 or other facility.      required under
                                                         Sec.
                                                         250.1729.
(d) Pipeline decommissioning    Before you              Include
 application.                    decommission a          information
                                 pipeline.               required under
                                                         Sec.
                                                         250.1751(a) or
                                                         Sec.
                                                         250.1752(a), as
                                                         applicable.
(e) Post-pipeline               Within 30 days after    Include
 decommissioning report.         you decommission a      information
                                 pipeline.               required under
                                                         Sec.
                                                         250.1753.
(f) Site clearance report for   Within 30 days after    Include
 a platform or other facility.   you complete site       information
                                 clearance               required under
                                 verification            Sec.
                                 activities.             250.1743(b).
(g) Form MMS-124, Application   (1) Before you          Include
 for Permit to Modify (APM).     temporarily abandon     information
 The submission of your APM      or permanently plug a   required under
 must be accompanied by          well or zone.           Sec. Sec.
 payment of the service fee     (2) Within 30 days       250.1712 and
 listed in Sec.  250.125.       after you plug a well   250.1721.
                                 * * *.                 Include
                                                         information
                                                         required under
                                                         Sec.
                                                         250.1717.
                                (3) Before you install  Refer to Sec.
                                 a subsea protective     250.1722(a).
                                 device.

[[Page 451]]

 
                                (4) Within 30 days      Include
                                 after you complete a    information
                                 protective device       required under
                                 trawl test.             Sec.
                                                         250.1722(d).
                                (5) Before you remove   Refer to Sec.
                                 any casing stub or      250.1723.
                                 mud line suspension
                                 equipment and any
                                 subsea protective
                                 device.
                                (6) Within 30 days      Include
                                 after you complete      information
                                 site clearance          required under
                                 verification            Sec.
                                 activities.             250.1743(a).
------------------------------------------------------------------------


[67 FR 35406, May 17, 2002; 67 FR 44265, July 1, 2002; 67 FR 66047, Oct. 
30, 2002, as amended at 71 FR 40913, July 19, 2006]

                       Permanently Plugging Wells



Sec. 250.1710  When must I permanently plug all wells on a lease?

    You must permanently plug all wells on a lease within 1 year after 
the lease terminates.



Sec. 250.1711  When will MMS order me to permanently plug a well?

    MMS will order you to permanently plug a well if that well:
    (a) Poses a hazard to safety or the environment; or
    (b) Is not useful for lease operations and is not capable of oil, 
gas, or sulphur production in paying quantities.



Sec. 250.1712  What information must I submit before I permanently plug a 

well or zone?

    Before you permanently plug a well or zone, you must submit form 
MMS-124, Application for Permit to Modify, to the appropriate District 
Manager and receive approval. A request for approval must contain the 
following information:
    (a) The reason you are plugging the well (or zone), for completions 
with production amounts specified by the Regional Supervisor, along with 
substantiating information demonstrating its lack of capacity for 
further profitable production of oil, gas, or sulfur;
    (b) Recent well test data and pressure data, if available;
    (c) Maximum possible surface pressure, and how it was determined;
    (d) Type and weight of well-control fluid you will use;
    (e) A description of the work; and
    (f) A current and proposed well schematic and description that 
includes:
    (1) Well depth;
    (2) All perforated intervals that have not been plugged;
    (3) Casing and tubing depths and details;
    (4) Subsurface equipment;
    (5) Estimated tops of cement (and the basis of the estimate) in each 
casing annulus;
    (6) Plug locations;
    (7) Plug types;
    (8) Plug lengths;
    (9) Properties of mud and cement to be used;
    (10) Perforating and casing cutting plans;
    (11) Plug testing plans;
    (12) Casing removal (including information on explosives, if used);
    (13) Proposed casing removal depth; and
    (14) Your plans to protect archaeological and sensitive biological 
features, including anchor damage during plugging operations, a brief 
assessment of the environmental impacts of the plugging operations, and 
the procedures and mitigation measures you will take to minimize such 
impacts.

[67 FR 35406, May 17, 2002; 67 FR 66048, Oct. 30, 2002]



Sec. 250.1713  Must I notify MMS before I begin well plugging operations?

    You must notify the appropriate District Manager at least 48 hours 
before beginning operations to permanently plug a well.



Sec. 250.1714  What must I accomplish with well plugs?

    You must ensure that all well plugs:
    (a) Provide downhole isolation of hydrocarbon and sulphur zones;
    (b) Protect freshwater aquifers; and

[[Page 452]]

    (c) Prevent migration of formation fluids within the wellbore or to 
the seafloor.



Sec. 250.1715  How must I permanently plug a well?

    (a) You must permanently plug wells according to the table in this 
section. The District Manager may require additional well plugs as 
necessary.

[[Page 453]]



                                      Permanent Well Plugging Requirements
----------------------------------------------------------------------------------------------------------------
                        If you have--                                         Then you must use--
----------------------------------------------------------------------------------------------------------------
(1) Zones in open hole......................................  Cement plug(s) set from at least 100 feet below
                                                               the bottom to 100 feet above the top of oil, gas,
                                                               and fresh-water zones to isolate fluids in the
                                                               strata.
(2) Open hole below casing..................................  (i) A cement plug, set by the displacement method,
                                                               at least 100 feet above and below deepest casing
                                                               shoe;
                                                              (ii) A cement retainer with effective back-
                                                               pressure control set 50 to 100 feet above the
                                                               casing shoe, and a cement plug that extends at
                                                               least 100 feet below the casing shoe and at least
                                                               50 feet above the retainer; or
                                                              (iii) A bridge plug set 50 feet to 100 feet above
                                                               the shoe with 50 feet of cement on top of the
                                                               bridge plug, for expected or known lost
                                                               circulation conditions.
(3) A perforated zone that is currently open and not          (i) A method to squeeze cement to all
 previously squeezed or isolated.                              perforations;
                                                              (ii) A cement plug set by the displacement method,
                                                               at least 100 feet above to 100 feet below the
                                                               perforated interval, or down to a casing plug,
                                                               whichever is less; or
                                                              (iii) If the perforated zones are isolated from
                                                               the hole below, you may use any of the plugs
                                                               specified in paragraphs (a)(3)(iii)(A) through
                                                               (E) of this section instead of those specified in
                                                               paragraphs (a)(3)(i) and (a)(3)(ii) of this
                                                               section.
                                                              (A) A cement retainer with effective back-pressure
                                                               control set 50 to 100 feet above the top of the
                                                               perforated interval, and a cement plug that
                                                               extends at least 100 feet below the bottom of the
                                                               perforated interval with at least 50 feet of
                                                               cement above the retainer;
                                                              (B) A bridge plug set 50 to 100 feet above the top
                                                               of the perforated interval and at least 50 feet
                                                               of cement on top of the bridge plug;
                                                              (C) A cement plug at least 200 feet in length, set
                                                               by the displacement method, with the bottom of
                                                               the plug no more than 100 feet above the
                                                               perforated interval;
                                                              (D) A through-tubing basket plug set no more than
                                                               100 feet above the perforated interval with at
                                                               least 50 feet of cement on top of the basket
                                                               plug; or
                                                              (E) A tubing plug set no more than 100 feet above
                                                               the perforated interval topped with a sufficient
                                                               volume of cement so as to extend at least 100
                                                               feet above the uppermost packer in the wellbore
                                                               and at least 300 feet of cement in the casing
                                                               annulus immediately above the packer.
(4) A casing stub where the stub end is within the casing...  (i) A cement plug set at least 100 feet above and
                                                               below the stub end;
                                                              (ii) A cement retainer or bridge plug set at least
                                                               50 to 100 feet above the stub end with at least
                                                               50 feet of cement on top of the retainer or
                                                               bridge plug; or
                                                              (iii) A cement plug at least 200 feet long with
                                                               the bottom of the plug set no more than 100 feet
                                                               above the stub end.
(5) A casing stub where the stub end is below the casing....  A plug as specified in paragraph (a)(1) or (a)(2)
                                                               of this section, as applicable.
(6) An annular space that communicates with open hole and     A cement plug at least 200 feet long set in the
 extends to the mud line.                                      annular space. For a well completed above the
                                                               ocean surface, you must pressure test each casing
                                                               annulus to verify isolation.
(7) A subsea well with unsealed annulus.....................  A cutter to sever the casing, and you must set a
                                                               stub plug as specified in paragraphs (a)(4) and
                                                               (a)(5) of this section.
(8) A well with casing......................................  A cement surface plug at least 150 feet long set
                                                               in the smallest casing that extends to the mud
                                                               line with the top of the plug no more than 150
                                                               feet below the mud line.
(9) Fluid left in the hole..................................  A fluid in the intervals between the plugs that is
                                                               dense enough to exert a hydrostatic pressure that
                                                               is greater than the formation pressures in the
                                                               intervals.
(10) Permafrost areas.......................................  (i) A fluid to be left in the hole that has a
                                                               freezing point below the temperature of the
                                                               permafrost, and a treatment to inhibit corrosion;
                                                               and
                                                              (ii) Cement plugs designed to set before freezing
                                                               and have a low heat of hydration.
----------------------------------------------------------------------------------------------------------------


[[Page 454]]

    (b) You must test the first plug below the surface plug and all 
plugs in lost circulation areas that are in open hole. The plug must 
pass one of the following tests to verify plug integrity:
    (1) A pipe weight of at least 15,000 pounds on the plug; or
    (2) A pump pressure of at least 1,000 pounds per square inch. Ensure 
that the pressure does not drop more than 10 percent in 15 minutes. The 
District Manager may require you to tests other plug(s).

[67 FR 35406, May 17, 2002; 67 FR 44265, July 1, 2002; 67 FR 66048, Oct. 
30, 2002]



Sec. 250.1716  To what depth must I remove wellheads and casings?

    (a) Unless the District Manager approves an alternate depth under 
paragraph (b) of this section, you must remove all wellheads and casings 
to at least 15 feet below the mud line.
    (b) The District Manager may approve an alternate removal depth if:
    (1) The wellhead or casing would not become an obstruction to other 
users of the seafloor or area, and geotechnical and other information 
you provide demonstrate that erosional processes capable of exposing the 
obstructions are not expected; or
    (2) You determine, and MMS concurs, that you must use divers, and 
the seafloor sediment stability poses safety concerns; or
    (3) The water depth is greater than 800 meters (2,624 feet).



Sec. 250.1717  After I permanently plug a well, what information must I 

submit?

    Within 30 days after you permanently plug a well, you must submit 
form MMS-124, Application for Permit to Modify (subsequent report), to 
the appropriate District Manager, and include the following information:
    (a) Information included in Sec. 250.1712 with a final well 
schematic;
    (b) Description of the plugging work;
    (c) Nature and quantities of material used in the plugs; and
    (d) If you cut and pulled any casing string, the following 
information:
    (1) A description of the methods used (including information on 
explosives, if used);
    (2) Size and amount of casing removed; and
    (3) Casing removal depth.

[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]

                        Temporary Abandoned Wells



Sec. 250.1721  If I temporarily abandon a well that I plan to re-enter, what 

must I do?

    You may temporarily abandon a well when it is necessary for proper 
development and production of a lease. To temporarily abandon a well, 
you must do all of the following:
    (a) Submit form MMS-124, Application for Permit to Modify, and the 
applicable information required by Sec. 250.1712 to the appropriate 
District Manager and receive approval;
    (b) Adhere to the plugging and testing requirements for permanently 
plugged wells listed in the table in Sec. 250.1715, except for Sec.  
250.1715 (a)(8). You do not need to sever the casings, remove the 
wellhead, or clear the site;
    (c) Set a bridge plug or a cement plug at least 100-feet long at the 
base of the deepest casing string, unless the casing string has been 
cemented and has not been drilled out. If a cement plug is set, it is 
not necessary for the cement plug to extend below the casing shoe into 
the open hole;
    (d) Set a retrievable or a permanent-type bridge plug or a cement 
plug at least 100 feet long in the inner-most casing. The top of the 
bridge plug or cement plug must be no more than 1,000 feet below the mud 
line. MMS may consider approving alternate requirements for subsea wells 
case-by-case;
    (e) Identify and report subsea wellheads, casing stubs, or other 
obstructions that extend above the mud line according to U.S. Coast 
Guard (USCG) requirements; and
    (f) Except in water depths greater than 300 feet, protect subsea 
wellheads, casing stubs, mud line suspensions, or other obstructions 
remaining above the seafloor by using one of the following methods, as 
approved by the District Manager or Regional Supervisor:
    (1) A caisson designed according to 30 CFR 250, subpart I, and 
equipped with aids to navigation;

[[Page 455]]

    (2) A jacket designed according to 30 CFR 250, subpart I, and 
equipped with aids to navigation; or
    (3) A subsea protective device that meets the requirements in Sec. 
250.1722.
    (g) Within 30 days after you temporarily plug a well, you must 
submit form MMS-124, Application for Permit to Modify (subsequent 
report), and include the following information:
    (1) Information included in Sec. 250.1712 with a well schematic;
    (2) Information required by Sec. 250.1717(b), (c), and (d); and
    (3) A description of any remaining subsea wellheads, casing stubs, 
mudline suspension equipment, or other obstructions that extend above 
the seafloor.

[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]



Sec. 250.1722  If I install a subsea protective device, what requirements 

must I meet?

    If you install a subsea protective device under Sec. 
250.1721(f)(3), you must install it in a manner that allows fishing gear 
to pass over the obstruction without damage to the obstruction, the 
protective device, or the fishing gear.
    (a) Use form MMS-124, Application for Permit to Modify to request 
approval from the appropriate District Manager to install a subsea 
protective device.
    (b) The protective device may not extend more than 10 feet above the 
seafloor (unless MMS approves otherwise).
    (c) You must trawl over the protective device when you install it 
(adhere to the requirements at Sec. 250.1741 (d) through (h)). If the 
trawl does not pass over the protective device or causes damage to it, 
you must notify the appropriate District Manager within 5 days and 
perform remedial action within 30 days of the trawl;
    (d) Within 30 days after you complete the trawling test described in 
paragraph (c) of this section, submit a report to the appropriate 
District Manager using form MMS-124, Application for Permit to Modify, 
that includes the following:
    (1) The date(s) the trawling test was performed and the vessel that 
was used;
    (2) A plat at an appropriate scale showing the trawl lines;
    (3) A description of the trawling operation and the net(s) that were 
used;
    (4) An estimate by the trawling contractor of the seafloor 
penetration depth achieved by the trawl;
    (5) A summary of the results of the trawling test including a 
discussion of any snags and interruptions, a description of any damage 
to the protective covering, the casing stub or mud line suspension 
equipment, or the trawl, and a discussion of any snag removals requiring 
diver assistance; and
    (6) A letter signed by your authorized representative stating that 
he/she witnessed the trawling test.
    (e) If a temporarily abandoned well is protected by a subsea device 
installed in a water depth less than 100 feet, mark the site with a buoy 
installed according to the USCG requirements.
    (f) Provide annual reports to the Regional Supervisor describing 
your plans to either re-enter and complete the well or to permanently 
plug the well.
    (g) Ensure that all subsea wellheads, casing stubs, mud line 
suspensions, or other obstructions in water depths less than 300 feet 
remain protected.
    (1) To confirm that the subsea protective covering remains properly 
installed, either conduct a visual inspection or perform a trawl test at 
least annually.
    (2) If the inspection reveals that a casing stub or mud line 
suspension is no longer properly protected, or if the trawl does not 
pass over the subsea protective covering without causing damage to the 
covering, the casing stub or mud line suspension equipment, or the 
trawl, notify the appropriate District Manager within 5 days, and 
perform the necessary remedial work within 30 days of discovery of the 
problem.
    (3) In your annual report required by paragraph (f) of this section, 
include the inspection date, results, and method used and a description 
of any remedial work you will perform or have performed.
    (h) You may request approval to waive the trawling test required by 
paragraph (c) of this section if you plan to use either:

[[Page 456]]

    (1) A buoy with automatic tracking capabilities installed and 
maintained according to USCG requirements at 33 CFR part 67 (or its 
successor); or
    (2) A design and installation method that has been proven successful 
by trawl testing of previous protective devices of the same design and 
installed in areas with similar bottom conditions.

[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]



Sec. 250.1723  What must I do when it is no longer necessary to maintain a 

well in temporary abandoned status?

    If you or MMS determines that continued maintenance of a well in a 
temporary abandoned status is not necessary for the proper development 
or production of a lease, you must:
    (a) Promptly and permanently plug the well according to Sec. 
250.1715;
    (b) Remove any casing stub or mud line suspension equipment and any 
subsea protective covering. You must submit a request for approval to 
perform such work to the appropriate District Manager using form MMS-
124, Application for Permit to Modify; and
    (c) Clear the well site according to Sec. 250.1740 through Sec.  
250.1742.

[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]

                 Removing Platforms and Other Facilities



Sec. 250.1725  When do I have to remove platforms and other facilities?

    (a) You must remove all platforms and other facilities within 1 year 
after the lease or pipeline right-of-way terminates, unless you receive 
approval to maintain the structure to conduct other activities. 
Platforms include production platforms, well jackets, single-well 
caissons, and pipeline accessory platforms.
    (b) Before you may remove a platform or other facility, you must 
submit a final removal application to the Regional Supervisor for 
approval and include the information listed in Sec. 250.1727.
    (c) You must remove a platform or other facility according to the 
approved application.
    (d) You must flush all production risers with seawater before you 
remove them.
    (e) You must notify the Regional Supervisor at least 48 hours before 
you begin the removal operations.



Sec. 250.1726  When must I submit an initial platform removal application and 

what must it include?

    An initial platform removal application is required only for leases 
and pipeline rights-of-way in the Pacific OCS Region or the Alaska OCS 
Region. It must include the following information:
    (a) Platform or other facility removal procedures, including the 
types of vessels and equipment you will use;
    (b) Facilities (including pipelines) you plan to remove or leave in 
place;
    (c) Platform or other facility transportation and disposal plans;
    (d) Plans to protect marine life and the environment during 
decommissioning operations, including a brief assessment of the 
environmental impacts of the operations, and procedures and mitigation 
measures that you will take to minimize the impacts; and
    (e) A projected decommissioning schedule.

[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]



Sec. 250.1727  What information must I include in my final application to 

remove a platform or other facility?

    You must submit to the Regional Supervisor, a final application for 
approval to remove a platform or other facility. Your application must 
be accompanied by payment of the service fee listed in Sec. 250.125. If 
you are proposing to use explosives, provide three copies of the 
application. If you are not proposing to use explosives, provide two 
copies of the application. Include the following information in the 
final removal application, as applicable:
    (a) Identification of the applicant including:
    (1) Lease operator/pipeline right-of-way holder;
    (2) Address;
    (3) Contact person and telephone number; and
    (4) Shore base.

[[Page 457]]

    (b) Identification of the structure you are removing including:
    (1) Platform Name/MMS Complex ID Number;
    (2) Location (lease/right-of-way, area, block, and block 
coordinates);
    (3) Date installed (year);
    (4) Proposed date of removal (Month/Year); and
    (5) Water depth.
    (c) Description of the structure you are removing including:
    (1) Configuration (attach a photograph or a diagram);
    (2) Size;
    (3) Number of legs/casings/pilings;
    (4) Diameter and wall thickness of legs/casings/pilings;
    (5) Whether piles are grouted inside or outside;
    (6) Brief description of soil composition and condition;
    (7) The sizes and weights of the jacket, topsides (by module), 
conductors, and pilings; and
    (8) The maximum removal lift weight and estimated number of main 
lifts to remove the structure.
    (d) A description, including anchor pattern, of the vessel(s) you 
will use to remove the structure.
    (e) Identification of the purpose, including:
    (1) Lease expiration/right-of-way relinquishment date; and
    (2) Reason for removing the structure.
    (f) A description of the removal method, including:
    (1) A brief description of the method you will use;
    (2) If you are using explosives, the following:
    (i) Type of explosives;
    (ii) Number and sizes of charges;
    (iii) Whether you are using single shot or multiple shots;
    (iv) If multiple shots, the sequence and timing of detonations;
    (v) Whether you are using a bulk or shaped charge;
    (vi) Depth of detonation below the mud line; and
    (vii) Whether you are placing the explosives inside or outside of 
the pilings;
    (3) If you will use divers or acoustic devices to conduct a pre-
removal survey to detect the presence of turtles and marine mammals, a 
description of the proposed detection method; and
    (4) A statement whether or not you will use transducers to measure 
the pressure and impulse of the detonations.
    (g) Your plans for transportation and disposal (including as an 
artificial reef) or salvage of the removed platform.
    (h) If available, the results of any recent biological surveys 
conducted in the vicinity of the structure and recent observations of 
turtles or marine mammals at the structure site.
    (i) Your plans to protect archaeological and sensitive biological 
features during removal operations, including a brief assessment of the 
environmental impacts of the removal operations and procedures and 
mitigation measures you will take to minimize such impacts.
    (j) A statement whether or not you will use divers to survey the 
area after removal to determine any effects on marine life.

[67 FR 35406, May 17, 2002, as amended at 71 FR 40913, July 19, 2006]



Sec. 250.1728  To what depth must I remove a platform or other facility?

    (a) Unless the Regional Supervisor approves an alternate depth under 
paragraph (b) of this section, you must remove all platforms and other 
facilities (including templates and pilings) to at least 15 feet below 
the mud line.
    (b) The Regional Supervisor may approve an alternate removal depth 
if:
    (1) The remaining structure would not become an obstruction to other 
users of the seafloor or area, and geotechnical and other information 
you provide demonstrate that erosional processes capable of exposing the 
obstructions are not expected; or
    (2) You determine, and MMS concurs, that you must use divers and the 
seafloor sediment stability poses safety concerns; or
    (3) The water depth is greater than 800 meters (2,624 feet).



Sec. 250.1729  After I remove a platform or other facility, what information 

must I submit?

    Within 30 days after you remove a platform or other facility, you 
must

[[Page 458]]

submit a written report to the Regional Supervisor that includes the 
following:
    (a) A summary of the removal operation including the date it was 
completed;
    (b) A description of any mitigation measures you took; and
    (c) A statement signed by your authorized representative that 
certifies that the types and amount of explosives you used in removing 
the platform or other facility were consistent with those set forth in 
the approved removal application.



Sec. 250.1730  When might MMS approve partial structure removal or toppling 

in place?

    The Regional Supervisor may grant a departure from the requirement 
to remove a platform or other facility by approving partial structure 
removal or toppling in place for conversion to an artificial reef or 
other use if you meet the following conditions:
    (a) The structure becomes part of a State artificial reef program, 
and the responsible State agency acquires a permit from the U.S. Army 
Corps of Engineers and accepts title and liability for the structure; 
and
    (b) You satisfy any U.S. Coast Guard (USCG) navigational 
requirements for the structure.

        Site Clearance for Wells, Platforms, and Other Facilities



Sec. 250.1740  How must I verify that the site of a permanently plugged well, 

removed platform, or other removed facility is clear of obstructions?

    Within 60 days after you permanently plug a well or remove a 
platform or other facility, you must verify that the site is clear of 
obstructions by using one of the following methods:
    (a) For a well site, you must either:
    (1) Drag a trawl over the site;
    (2) Scan across the location using sonar equipment;
    (3) Inspect the site using a diver;
    (4) Videotape the site using a camera on a remotely operated vehicle 
(ROV); or
    (5) Use another method approved by the District Manager if the 
particular site conditions warrant.
    (b) For a platform or other facility site in water depths less than 
300 feet, you must drag a trawl over the site.
    (c) For a platform or other facility site in water depths 300 feet 
or more, you must either:
    (1) Drag a trawl over the site;
    (2) Scan across the site using sonar equipment; or
    (3) Use another method approved by the Regional Supervisor if the 
particular site conditions warrant.

[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]



Sec. 250.1741  If I drag a trawl across a site, what requirements must I 

meet?

    If you drag a trawl across the site in accordance with Sec. 
250.1740, you must meet all of the requirements of this section.
    (a) You must drag the trawl in a grid-like pattern as shown in the 
following table:

------------------------------------------------------------------------
           For a--                 You must drag the trawl across a--
------------------------------------------------------------------------
(1) Well site................  300-foot-radius circle centered on the
                                well location.
(2) Subsea well site.........  600-foot-radius circle centered on the
                                well location.
(3) Platform site............  1,320-foot-radius circle centered on the
                                location of the platform.
(4) Single-well caisson, well  600-foot-radius circle centered on the
 protector jacket, template,    structure location.
 or manifold.
------------------------------------------------------------------------

    (b) You must trawl 100 percent of the limits described in paragraph 
(a) of this section in two directions.
    (c) You must mark the area to be cleared as a hazard to navigation 
according to USCG requirements until you complete the site clearance 
procedures.

[[Page 459]]

    (d) You must use a trawling vessel equipped with a calibrated 
navigational positioning system capable of providing position accuracy 
of 30 feet.
    (e) You must use a trawling net that is representative of those used 
in the commercial fishing industry (one that has a net strength equal or 
greater than that provided by No. 18 twine).
    (f) You must ensure that you trawl no closer than 300 feet from a 
shipwreck, and 500 feet from a sensitive biological feature.
    (g) If you trawl near an active pipeline, you must meet the 
requirements in the following table:

------------------------------------------------------------------------
            For--               You must trawl--       And you must--
------------------------------------------------------------------------
(1) Buried active pipelines.  ....................  First contact the
                                                     pipeline owner or
                                                     operator to
                                                     determine the
                                                     condition of the
                                                     pipeline before
                                                     trawling over the
                                                     buried pipeline.
(2) Unburied active           no closer than 100    Trawl parallel to
 pipelines that are 8 inches   feet to the either    the pipeline Do not
 in diameter or larger.        side of the           trawl across the
                               pipeline.             pipeline.
(3) Unburied smaller          no closer than 100    Trawl parallel to
 diameter active pipelines     feet to either side   the pipeline. Do
 in the trawl area that have   of the pipeline.      not trawl across
 obstructions (e.g.,                                 the pipeline.
 pipeline valves) present.
(4) Unburied active           parallel to the       ....................
 pipelines in the trawl area   pipeline.
 that are smaller than 8
 inches in diameter and have
 no obstructions present.
------------------------------------------------------------------------

    (h) You must ensure that any trawling contractor you may use:
    (1) Has no corporate or other financial ties to you; and
    (2) Has a valid commercial trawling license for both the vessel and 
its captain.

[67 FR 35406, May 17, 2002; 67 FR 44266, July 1, 2002; 67 FR 66049, Oct. 
30, 2002]



Sec. 250.1742  What other methods can I use to verify that a site is clear?

    If you do not trawl a site, you can verify that the site is clear of 
obstructions by using any of the methods shown in the following table:

------------------------------------------------------------------------
        If you use--               You must--          And you must--
------------------------------------------------------------------------
(a) Sonar...................  cover 100 percent of  Use a sonar signal
                               the appropriate       with a frequency of
                               grid area listed in   at least 500 kHz.
                               Sec.  250.1741(a).
(b) A diver.................  ensure that the       Ensure that the
                               diver visually        diver uses a search
                               inspects 100          pattern of
                               percent of the        concentric circles
                               appropriate grid      or parallel lines
                               area listed in Sec.  spaced no more than
                                 250.1741(a).        10 feet apart.
(c) An ROV (remotely          ensure that the ROV   Ensure that the ROV
 operated vehicle).            camera records        uses a pattern of
                               videotape over 100    concentric circles
                               percent of the        or parallel lines
                               appropriate grid      spaced no more than
                               area listed in Sec.  10 feet apart.
                                 250.1741(a).
------------------------------------------------------------------------


[67 FR 35406, May 17, 2002; 67 FR 44266, July 1, 2002]



Sec. 250.1743  How do I certify that a site is clear of obstructions?

    (a) For a well site, you must submit to the appropriate District 
Manager within 30 days after you complete the verification activities a 
form MMS-124, Application for Permit to Modify, to include the following 
information:
    (1) A signed certification that the well site area is cleared of all 
obstructions;
    (2) The date the verification work was performed and the vessel 
used;
    (3) The extent of the area surveyed;
    (4) The survey method used;
    (5) The results of the survey, including a list of any debris 
removed or a

[[Page 460]]

statement from the trawling contractor that no objects were recovered; 
and
    (6) A post-trawling job plot or map showing the trawled area.
    (b) For a platform or other facility site, you must submit the 
following information to the appropriate Regional Supervisor within 30 
days after you complete the verification activities:
    (1) A letter signed by an authorized company official certifying 
that the platform or other facility site area is cleared of all 
obstructions and that a company representative witnessed the 
verification activities;
    (2) A letter signed by an authorized official of the company that 
performed the verification work for you certifying that they cleared the 
platform or other facility site area of all obstructions;
    (3) The date the verification work was performed and the vessel 
used;
    (4) The extent of the area surveyed;
    (5) The survey method used;
    (6) The results of the survey, including a list of any debris 
removed or a statement from the trawling contractor that no objects were 
recovered; and
    (7) A post-trawling job plot or map showing the trawled area.

[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]

                        Pipeline Decommissioning



Sec. 250.1750  When may I decommission a pipeline in place?

    You may decommission a pipeline in place when the Regional 
Supervisor determines that the pipeline does not constitute a hazard 
(obstruction) to navigation and commercial fishing operations, unduly 
interfere with other uses of the OCS, or have adverse environmental 
effects.



Sec. 250.1751  How do I decommission a pipeline in place?

    You must do the following to decommission a pipeline in place:
    (a) Submit a pipeline decommissioning application in triplicate to 
the Regional Supervisor for approval. Your application must be 
accompanied by payment of the service fee listed in Sec. 250.125. Your 
application must include the following information:
    (1) Reason for the operation;
    (2) Proposed decommissioning procedures;
    (3) Length (feet) of segment to be decommissioned; and
    (4) Length (feet) of segment remaining.
    (b) Pig the pipeline, unless the Regional Supervisor determines that 
pigging is not practical;
    (c) Flush the pipeline;
    (d) Fill the pipeline with seawater;
    (e) Cut and plug each end of the pipeline;
    (f) Bury each end of the pipeline at least 3 feet below the seafloor 
or cover each end with protective concrete mats, if required by the 
Regional Supervisor; and
    (g) Remove all pipeline valves and other fittings that could unduly 
interfere with other uses of the OCS.

[67 FR 35406, May 17, 2002, as amended at 71 FR 40913, July 19, 2006]



Sec. 250.1752  How do I remove a pipeline?

    Before removing a pipeline, you must:
    (a) Submit a pipeline removal application in triplicate to the 
Regional Supervisor for approval. Your application must be accompanied 
by payment of the service fee listed in Sec. 250.125. Your application 
must include the following information:
    (1) Proposed removal procedures;
    (2) If the Regional Supervisor requires it, a description, including 
anchor pattern(s), of the vessel(s) you will use to remove the pipeline;
    (3) Length (feet) to be removed;
    (4) Length (feet) of the segment that will remain in place;
    (5) Plans for transportation of the removed pipe for disposal or 
salvage;
    (6) Plans to protect archaeological and sensitive biological 
features during removal operations, including a brief assessment of the 
environmental impacts of the removal operations and procedures and 
mitigation measures that you will take to minimize such impacts; and
    (7) Projected removal schedule and duration.
    (b) Pig the pipeline, unless the Regional Supervisor determines that 
pigging is not practical; and

[[Page 461]]

    (c) Flush the pipeline.

[67 FR 35406, May 17, 2002, as amended at 71 FR 40913, July 19, 2006]



Sec. 250.1753  After I decommission a pipeline, what information must I 

submit?

    Within 30 days after you decommission a pipeline, you must submit a 
written report to the Regional Supervisor that includes the following:
    (a) A summary of the decommissioning operation including the date it 
was completed;
    (b) A description of any mitigation measures you took; and
    (c) A statement signed by your authorized representative that 
certifies that the pipeline was decommissioned according to the approved 
application.



Sec. 250.1754  When must I remove a pipeline decommissioned in place?

    You must remove a pipeline decommissioned in place if the Regional 
Supervisor determines that the pipeline is an obstruction.



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., 31 U.S.C. 9701.

    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 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.).

[[Page 462]]

    Data means facts, statistics, measurements, or samples that have not 
been analyzed, processed, or interpreted.
    Deep stratigraphic test means drilling that involves the penetration 
into the sea bottom of more than 500 feet (152 meters).
    Director means the Director of the Minerals Management Service, U.S. 
Department of the Interior, or a subordinate authorized to act on the 
Director's behalf.
    Exploration means the commercial search for oil, gas, and sulphur. 
Activities classified as exploration include, but are not limited to:
    (1) Geological and geophysical marine and airborne surveys where 
magnetic, gravity, seismic reflection, seismic refraction, gas sniffers, 
coring, or other systems are used to detect or imply the presence of 
oil, gas, or sulphur; and
    (2) Any drilling, whether on or off a geological structure.
    Geological and geophysical scientific research means any oil, gas, 
or sulphur related investigation conducted in the OCS for scientific 
and/or research purposes. Geological, geophysical, and geochemical data 
and information gathered and analyzed are made available to the public 
for inspection and reproduction at the earliest practicable time. The 
term does not include commercial geological or geophysical exploration 
or research.
    Geological exploration means exploration that uses geological and 
geochemical techniques (e.g., coring and test drilling, well logging, 
and bottom sampling) to produce data and information on oil, gas, and 
sulphur resources in support of possible exploration and development 
activities. The term does not include geological scientific research.
    Geophysical exploration means exploration that utilizes geophysical 
techniques (e.g., gravity, magnetic, or seismic) to produce data and 
information on oil, gas, and sulphur resources in support of possible 
exploration and development activities. The term does not include 
geophysical scientific research.
    Governor means the Governor of a State or the person or entity 
lawfully designated to exercise the powers granted to a Governor 
pursuant to the Act.
    Human environment means the physical, social, and economic 
components, conditions, and factors which interactively determine the 
state, condition, and quality of living conditions, employment, and 
health of those affected, directly or indirectly, by activities 
occurring on the OCS.
    Hydrocarbon occurrence means the direct or indirect detection during 
drilling operations of any liquid or gaseous hydrocarbons by examination 
of well cuttings, cores, gas detector readings, formation fluid tests, 
wireline logs, or by any other means. The term does not include 
background gas, minor accumulations of gas, or heavy oil residues on 
cuttings and cores.
    Information means geological and geophysical data that have been 
analyzed, processed, or interpreted.
    Interpreted geological information means knowledge, often in the 
form of schematic cross sections, 3-dimensional representations, and 
maps, developed by determining the geological significance of geological 
data and analyzed and processed geologic information.
    Interpreted geophysical information means knowledge, often in the 
form of seismic cross sections, 3-dimensional representations, and maps, 
developed by determining the geological significance of geophysical data 
and processed geophysical information.
    Lease means an agreement which is issued under section 8 or 
maintained under section 6 of the Act and which authorizes exploration 
for, and development and production of, minerals or the area covered by 
that authorization, whichever is required by the context.
    Lessee means a person who has entered into, or is the MMS approved 
assignee of, a lease with the United States to explore for, develop, and 
produce the leased minerals. The term ``lessee'' also includes an owner 
of operating rights.
    Marine environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
quality of the marine ecosystem in the coastal zone and in the OCS.

[[Page 463]]

    Material remains mean physical evidence of human habitation, 
occupation, use, or activity, including the site, location, or context 
in which such evidence is situated.
    Minerals mean oil, gas, sulphur, geopressured-geothermal and 
associated resources, and all other minerals which are authorized by an 
Act of Congress to be produced from public lands as defined in section 
103 of the Federal Land Policy and Management Act of 1976 (43 U.S.C. 
1702).
    Notice means a written statement of intent to conduct geological or 
geophysical scientific research related to oil, gas, and sulphur in the 
OCS other than under a permit.
    Oil, gas, and sulphur mean oil, gas, sulphur, geopressured-
geothermal, and associated resources.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside the area of lands beneath navigable waters as 
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301), and of 
which the subsoil and seabed appertain to the United States and are 
subject to its jurisdiction and control.
    Permit means the contract or agreement, other than a lease, issued 
pursuant to this part, under which a person acquires the right to 
conduct on the OCS, in accordance with appropriate statutes, 
regulations, and stipulations:
    (1) Geological exploration for mineral resources;
    (2) Geophysical exploration for mineral resources;
    (3) Geological scientific research; or
    (4) Geophysical scientific research.
    Permittee means the person authorized by a permit issued pursuant to 
this part to conduct activities on the OCS.
    Person means a citizen or national of the United States; an alien 
lawfully admitted for permanent residence in the United States as 
defined in section 8 U.S.C. 1101(a)(20); a private, public, or municipal 
corporation organized under the laws of the United States or of any 
State or territory thereof; and associations of such citizens, 
nationals, resident aliens, or private, public, or municipal 
corporations, States, or political subdivisions of States or anyone 
operating in a manner provided for by treaty or other applicable 
international agreements. The term does not include Federal agencies.
    Processed geological or geophysical information means data collected 
under a permit and later processed or reprocessed. Processing involves 
changing the form of data so as to facilitate interpretation. Processing 
operations may include, but are not limited to, applying corrections for 
known perturbing causes, rearranging or filtering data, and combining or 
transforming data elements. Reprocessing is the additional processing 
other than ordinary processing used in the general course of evaluation. 
Reprocessing operations may include varying identified parameters for 
the detailed study of a specific problem area.
    Secretary means the Secretary of the Interior or a subordinate 
authorized to act on the Secretary's behalf.
    Shallow test drilling means drilling into the sea bottom to depths 
less than those specified in the definition of a deep stratigraphic 
test.
    Significant archaeological resource means those archaeological 
resources that meet the criteria of significance for eligibility to the 
National Register of Historic Places as defined in 36 CFR 60.4.
    Third Party means any person other than the permittee or a 
representative of the United States, including all persons who obtain 
data or information acquired under a permit from the permittee, or from 
another third party, by sale, trade, license agreement, or other means.
    Violation means a failure to comply with any provision of the Act, 
or a provision of a regulation or order issued under the Act, or any 
provision of a lease, license, or permit issued under the Act.
    You means a person who applies for and/or obtains a permit, or files 
a Notice to conduct geological or geophysical exploration or scientific 
research related to oil, gas, and sulphur in the OCS.



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.

[[Page 464]]

    (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. A nonrefundable service fee of 
$1,900 must accompany your application.
    (b) Disapproval of permit application. If MMS disapproves your 
application for a permit, the Regional Director will state the reasons 
for the denial and will advise you of the changes needed to obtain 
approval.
    (c) Notices. You must sign and date a Notice and state:
    (1) The name(s) of the person(s) who will conduct the proposed 
research;
    (2) The name(s) of any other person(s) participating in the proposed 
research, including the sponsor;
    (3) The type of research and a brief description of how you will 
conduct it;
    (4) The location in the OCS, indicated on a map, plat, or chart, 
where you will conduct research;
    (5) The proposed dates you project for your research activity to 
start and end;
    (6) The name, registry number, registered owner, and port of 
registry of vessels used in the operation;
    (7) The earliest practicable time you expect to make the data and 
information resulting from your research activity available to the 
public;

[[Page 465]]

    (8) Your plan of how you will make the data and information you 
collected available to the public;
    (9) That you and others involved will not sell or withhold for 
exclusive use the data and information resulting from your research; and
    (10) At your option, you may submit (as a substitute for the 
material required in paragraphs (c)(7), (c)(8), and (c)(9) of this 
section) the nonexclusive use agreement for scientific research 
attachment to Form 327.
    (d) Filing locations. You must apply for a permit or file a Notice 
at one of the following locations:
    (1) For the OCS off the State of Alaska--the Regional Supervisor for 
Resource Evaluation, Minerals Management Service, Alaska OCS Region, 949 
East 36th Avenue, Anchorage, Alaska 99508-4302.
    (2) For the OCS off the Atlantic Coast and in the Gulf of Mexico--
the Regional Supervisor for Resource Evaluation, Minerals Management 
Service, Gulf of Mexico OCS Region, 1201 Elmwood Park Boulevard, New 
Orleans, Louisiana 70123-2394.
    (3) For the OCS off the coast of the States of California, Oregon, 
Washington, or Hawaii--the Regional Supervisor for Resource Evaluation, 
Minerals Management Service, Pacific OCS Region, 770 Paseo Camarillo, 
Camarillo, California 93010-6064.

[62 FR 67284, Dec. 24, 1997, as amended at 71 FR 40913, July 19, 2006]



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.



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 in Sec. 251.5(d), a drilling plan, an 
environmental report, an Application for Permit to Drill

[[Page 466]]

(Form MMS-123), and a Supplemental APD Information Sheet (Form MMS-123S) 
as follows:
    (1) Drilling plan. The drilling plan must include:
    (i) The proposed type, sequence, and timetable of drilling 
activities;
    (ii) A description of your drilling rig, indicating the important 
features with special attention to safety, pollution prevention, oil-
spill containment and cleanup plans, and onshore disposal procedures;
    (iii) The location of each deep stratigraphic test you will conduct, 
including the location of the surface and projected bottomhole of the 
borehole;
    (iv) The types of geological and geophysical survey instruments you 
will use before and during drilling;
    (v) Seismic, bathymetric, sidescan sonar, magnetometer, or other 
geophysical data and information sufficient to evaluate seafloor 
characteristics, shallow geologic hazards, and structural detail across 
and in the vicinity of the proposed test to the total depth of the 
proposed test well; and
    (vi) Other relevant data and information that the Regional Director 
requires.
    (2) Environmental report. The environmental report must include all 
of the following material:
    (i) A summary with data and information available at the time you 
submitted the related drilling plan. MMS will consider site-specific 
data and information developed since the most recent environmental 
impact statement or other environmental impact analysis in the immediate 
area. The summary must meet the following requirements:
    (A) You must concentrate on the issues specific to the site(s) of 
drilling activity. However, you only need to summarize data and 
information discussed in any environmental reports, analyses, or impact 
statements prepared for the geographic area of the drilling activity.
    (B) You must list referenced material. Include brief descriptions 
and a statement of where the material is available for inspection.
    (C) You must refer only to data that are available to MMS.
    (ii) Details about your project such as:
    (A) A list and description of new or unusual technologies;
    (B) The location of travel routes for supplies and personnel;
    (C) The kinds and approximate levels of energy sources;
    (D) The environmental monitoring systems; and
    (E) Suitable maps and diagrams showing details of the proposed 
project layout.
    (iii) A description of the existing environment. For this section, 
you must include the following information on the area:
    (A) Geology;
    (B) Physical oceanography;
    (C) Other uses of the area;
    (D) Flora and fauna;
    (E) Existing environmental monitoring systems; and
    (F) Other unusual or unique characteristics that may affect or be 
affected by the drilling activities.
    (iv) A description of the probable impacts of the proposed action on 
the environment and the measures you propose for mitigating these 
impacts.
    (v) A description of any unavoidable or irreversible adverse effects 
on the environment that could occur.
    (vi) Other relevant data that the Regional Director requires.
    (3) Copies for coastal States. You must submit copies of the 
drilling plan and environmental report to the Regional Director for 
transmittal to the Governor of each affected coastal State and the 
coastal zone management agency of each affected coastal State that has 
an approved program under the Coastal Zone Management Act. (The Regional 
Director will make the drilling plan and environmental report available 
to appropriate Federal agencies and the public according to the 
Department of the Interior's policies and procedures).
    (4) Certification of coastal zone management program consistency and 
State concurrence. When required under an approved coastal zone 
management program of an affected State, your drilling plan must include 
a certification that the proposed activities described in the plan 
comply with enforceable policies of, and will be conducted in a manner

[[Page 467]]

consistent with such State's program. The Regional Director may not 
approve any of the activities described in the drilling plan unless the 
State concurs with the consistency certification or the Secretary of 
Commerce makes the finding authorized by section 307(c)(3)(B)(iii) of 
the Coastal Zone Management Act.
    (5) Protecting archaeological resources. If the Regional Director 
believes that an archaeological resource may exist in the area that may 
be affected by drilling, the Regional Director will notify you of the 
need to prepare an archaeological report.
    (i) If the evidence suggests that an archaeological resource may be 
present, you must:
    (A) Locate the site of the drilling so as to not adversely affect 
the area where the archaeological resources may be, or
    (B) Establish to the satisfaction of the Regional Director that an 
archaeological resource does not exist or will not be adversely affected 
by drilling. This must be done by further archaeological investigation, 
conducted by an archaeologist and a geophysicist, using survey equipment 
and techniques deemed necessary by the Regional Director. A report on 
the investigation must be submitted to the Regional Director for review.
    (ii) If the Regional Director determines that an archaeological 
resource is likely to be present in the area that may be affected by 
drilling, and may be adversely affected by drilling, the Regional 
Director will notify you immediately. You must take no action that may 
adversely affect the archaeological resource unless further 
investigations determine that the resource is not archaeologically 
significant.
    (iii) If you discover any archaeological resource while drilling, 
you must immediately halt drilling and report the discovery to the 
Regional Director. If investigations determine that the resource is 
significant, the Regional Director will inform you how to protect it.
    (6) Application for permit to drill (APD). Before commencing deep 
stratigraphic test drilling activities under an approved drilling plan, 
you must submit an APD and a Supplemental APD Information Sheet (Forms 
MMS-123 and MMS-123S) and receive approval. You must comply with all 
regulations relating to drilling operations in 30 CFR part 250.
    (7) Revising an approved drilling plan. Before you revise an 
approved drilling plan, you must obtain the Regional Director's 
approval.
    (8) After drilling. When you complete the test activities, you must 
permanently plug and abandon the boreholes of all deep stratigraphic 
tests in compliance with 30 CFR part 250. If the tract on which you 
conducted a deep stratigraphic test is leased to another party for 
exploration and development, and if the lessee has not disturbed the 
borehole, MMS will hold you and not the lessee responsible for problems 
associated with the test hole.
    (9) Deadline for completing a deep stratigraphic test. If your deep 
stratigraphic test well is within 50 geographic miles of a tract that 
MMS has identified for a future lease sale, as listed on the currently 
approved OCS leasing schedule, you must complete all drilling activities 
and submit the data and information to the Regional Director at least 60 
days before the first day of the month in which MMS schedules the lease 
sale. However, the Regional Director may extend your permit duration to 
allow you to complete drilling activities and submit data and 
information if the extension is in the national interest.
    (c) Group participation in test drilling. MMS encourages group 
participation for deep stratigraphic tests.
    (1) Purpose of group participation. The purpose is to minimize 
duplicative G&G activities involving drilling into the seabed of the 
OCS.
    (2) Providing opportunity for participation in a deep stratigraphic 
test. When you propose to drill a deep stratigraphic test, you must give 
all interested persons an opportunity to participate in the test 
drilling through a signed agreement on a cost-sharing basis. You may 
include a penalty for late participation of not more than 100 percent of 
the cost to each original participant in addition to the original share 
cost.
    (i) The participants must assess and distribute late participation 
penalties

[[Page 468]]

in accordance with the terms of the agreement.
    (ii) For a significant hydrocarbon occurrence that the Regional 
Director announces to the public, the penalty for subsequent late 
participants may be raised to not more than 300 percent of the cost of 
each original participant in addition to the original share cost.
    (3) Providing opportunity for participation in a shallow test 
drilling project. When you apply to conduct shallow test drilling 
activities, you must, if ordered by the Regional Director or required by 
the permit, give all interested persons an opportunity to participate in 
the test activity on a cost-sharing basis. You may include a penalty 
provision for late participation of not more than 50 percent of the cost 
to each original participant in addition to the original share cost.
    (4) Procedures for group participation in drilling activities. You 
must:
    (i) Publish a summary statement that describes the approved activity 
in a relevant trade publication;
    (ii) Forward a copy of the published statement to the Regional 
Director;
    (iii) Allow at least 30 days from the summary statement publication 
date for other persons to join as original participants;
    (iv) Compute the estimated cost by dividing the estimated total cost 
of the program by the number of original participants; and
    (v) Furnish the Regional Director with a complete list of all 
participants before starting operations, or at the end of the 
advertising period if you begin operations before the advertising period 
is over. The names of any subsequent or late participants must also be 
furnished to the Regional Director.
    (5) Changes to the original application for test drilling. If you 
propose changes to the original application and the Regional Director 
determines that the changes are significant, the Regional Director will 
require you to publish the changes for an additional 30 days to give 
other persons a chance to join as original participants.
    (d) Bonding requirements. You must submit a bond under this part 
before you may start a deep stratigraphic test.
    (1) Before MMS issues a permit authorizing the drilling of a deep 
stratigraphic test, you must either:
    (i) Furnish to MMS a bond of not less than $200,000 that guarantees 
compliance with all the terms and conditions of the permit; or
    (ii) Maintain a $1 million bond that guarantees compliance with all 
the terms and conditions of the permit you hold for the OCS area where 
you propose to drill.
    (2) You must provide additional security to MMS if the Regional 
Director determines that it is necessary for the permit or area.
    (3) The Regional Director may require you to provide a bond, in an 
amount the Regional Director prescribes, before authorizing you to drill 
a shallow test well.
    (4) Your bond must be on a form approved by the Associate Director 
for Offshore Minerals Management.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 72 FR 25202, May 4, 2007]



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 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.

[[Page 469]]

    (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.



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]

[[Page 470]]



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, 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.

[[Page 471]]



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 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

[[Page 472]]

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 Sec. Sec. 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. Except for high-resolution data and information released under 
30 CFR 250.197(b)(2), MMS will release or disclose data and information 
that you or a third party submit and MMS retains in accordance with 
paragraphs (b)(1), (b)(2), and (b)(3) of this section.
    (1) If the data and information are not related to a deep 
stratigraphic test, MMS will release them to the public in accordance 
with the following table:

------------------------------------------------------------------------
                                             The Regional Director will
  If you or a third party submit and MMS    release them to the public *
               retains * * *                             * *
------------------------------------------------------------------------
(i) Geological data and information.......  10 years after MMS issues
                                             the permit.
(ii) Geophysical data.....................  50 years after MMS issues
                                             the permit.
(iii) Geophysical information.............  25 years after MMS issues
                                             the permit.
------------------------------------------------------------------------

    (2) If the data and information are related to a deep stratigraphic 
test, MMS will release them to the public at the earlier of the 
following times:
    (i) Twenty-five years after you complete the test; or
    (ii) If a lease sale is held after you complete a test well, 60 
calendar days after MMS issues the first lease, any portion of which is 
located within 50

[[Page 473]]

geographic miles (92.7 kilometers) of the test.
    (3) MMS may allow limited inspection, but only by persons with a 
direct interest in related MMS decisions and issues in specific 
geographic areas, and who agree in writing to its confidentiality, of 
G&G data and information submitted under this part that MMS uses to:
    (i) Make unitization determinations on two or more leases;
    (ii) Make competitive reservoir determinations;
    (iii) Ensure proper plans of development for competitive reservoirs;
    (iv) Promote operational safety;
    (v) Protect the environment;
    (vi) Make field determinations; or
    (vii) Determine eligibility for royalty relief.
    (c) Procedure that MMS follows to disclose acquired data and 
information to a contractor for reproduction, processing, and 
interpretation. (1) When practical, the Regional Director will advise 
the person who submitted data and information under Sec. Sec. 251.11 or 
251.12 of the intent to disclose the data or information to an 
independent contractor or agent.
    (2) The person so notified will have at least 5 working days to 
comment on the action.
    (3) When the Regional Director advises the person who submitted the 
data and information, all other owners of the data or information will 
be considered to have been so notified.
    (4) Before disclosure, the contractor or agent must sign a written 
commitment not to sell, trade, license, or disclose data or information 
to anyone without the Regional Director's consent.
    (d) Sharing data and information with coastal States. (1) When MMS 
solicits nominations for leasing lands located within 3 geographic miles 
(5.6 kilometers) of the seaward boundary of any coastal State, the 
Regional Director, in accordance with 30 CFR 252.7 (a)(4) and (b) and 
subsections 8(g) and 26(e) of the Act (43 U.S.C. 1337(g) and 1352(e)), 
will provide the Governor with:
    (i) All information on the geographical, geological, and ecological 
characteristics of the areas and regions MMS proposes to offer for 
lease;
    (ii) An estimate of the oil and gas reserves in the areas proposed 
for leasing; and
    (iii) An identification of any field, geological structure, or trap 
on the OCS within 3 geographic miles (5.6 kilometers) of the seaward 
boundary of the State.
    (2) After receiving nominations for leasing an area of the OCS 
within 3 geographic miles of the seaward boundary of any coastal State, 
MMS will carry out a tentative area identification according to 30 CFR 
part 256, subparts D and E. At that time, the Regional Director will 
consult with the Governor to determine whether any tracts further 
considered for leasing may contain any oil or gas reservoirs that 
underlie both the OCS and lands subject to the jurisdiction of the 
State.
    (3) Before a sale, if a Governor requests, the Regional Director, in 
accordance with 30 CFR 252.7(a)(4) and (b) and sections 8(g) and 26(e) 
of the Act (43 U.S.C. 1337(g) and 1352(e)), will share with the Governor 
information that identifies potential and/or proven common hydrocarbon 
bearing areas within 3 geographic miles of the seaward boundary of that 
State.
    (4) Information received and knowledge gained by a State official 
under paragraph (d) of this section is subject to applicable 
confidentiality requirements of:
    (i) The Act; and
    (ii) The regulations at 30 CFR parts 250, 251, and 252.

[62 FR 67284, Dec. 24, 1997, as amended at 71 FR 16039, Mar. 30, 2006; 
71 FR 62050, Oct. 20, 2006; 72 FR 25202, May 4, 2007]



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.

[[Page 474]]

    (c) We use the information collected under this part to:
    (1) Evaluate permit applications and monitor scientific research 
activities for environmental and safety reasons.
    (2) Determine that explorations do not harm resources, result in 
pollution, create hazardous or unsafe conditions, or interfere with 
other users in the area.
    (3) Approve reimbursement of certain expenses.
    (4) Monitor the progress and activities carried out under an OCS G&G 
permit.
    (5) Inspect and select G&G data and information collected under an 
OCS G&G permit.
    (d) Respondents are Federal OCS permittees and Notice filers. 
Responses are mandatory or are required to obtain or retain a benefit. 
We will protect information considered proprietary under applicable law 
and under regulations at 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;

[[Page 475]]

    (3) Which is receiving, or in accordance with the proposed activity 
will receive, oil for processing, refining, or transshipment which was 
extracted from the OCS and transported directly to such State by means 
of vessels or by a combination of means including vessels;
    (4) Which is designated by the Director as a State in which there is 
a substantial probability of significant impact on or damage to the 
coastal, marine, or human environment, or a State in which there will be 
significant changes in the social, governmental, or economic 
infrastructure, resulting from the exploration, development, and 
production of oil and gas anywhere on the OCS; or
    (5) In which the Director finds that because of such activity there 
is, or will be, a significant risk of serious damage, due to factors 
such as prevailing winds and currents, to the marine or coastal 
environment in the event of any oilspill, blowout, or release of oil or 
gas from vessels, pipelines, or other transshipment facilities.
    (d) Analyzed geological information means data collected under a 
permit or a lease which have been analyzed. Analysis may include, but is 
not limited to, identification of lithologic and fossil content, core 
analyses, laboratory analyses of physical and chemical properties, logs 
or charts of electrical, radioactive, sonic, and other well logs, and 
descriptions of hydrocarbon shows or hazardous conditions.
    (e) Area adjacent to a State means all of that portion of the OCS 
included within a planning area if such planning area is bordered by 
that State. The portion of the OCS in the Navarin Basin Planning Area is 
deemed to be adjacent to the State of Alaska. The States of New York and 
Rhode Island are deemed to be adjacent to both the Mid-Atlantic Planning 
Area and the North Atlantic Planning Area.
    (f) Data means facts and statistics or samples which have not been 
analyzed or processed.
    (g) Development means those activities which take place following 
discovery of oil or natural gas in paying quantities, including 
geophysical activity, drilling, platform construction, and operation of 
all onshore support facilities, and which are for the purpose of 
ultimately producing the oil and gas discovered.
    (h) Director means the Director of the Minerals Management Service 
of the U.S. Department of the Interior or a designee of the Director.
    (i) Exploration means the process of searching for oil and natural 
gas, including: (1) Geophysical surveys where magnetic, gravity, 
seismic, or other systems are used to detect or imply the presence of 
such oil or natural gas, and (2) any drilling, whether on or off known 
geological structures, including the drilling of a well in which a 
discovery of oil or natural gas in paying quantities is made and the 
drilling of any additional delineation well after such discovery which 
is needed to delineate any reservoir and to enable the lessee to 
determine whether to proceed with development and production.
    (j) Governor means the Governor of a State, or the person or entity 
designated by, or pursuant to, State law to exercise the powers granted 
to a Governor pursuant to the Act.
    (k) Information, when used without a qualifying adjective, includes 
analyzed geological information, processed geophysical information, 
interpreted geological information, and interpreted geophysical 
information.
    (l) Interpreted geological information means knowledge, often in the 
form of schematic cross sections and maps, developed by determining the 
geological significance of data and analyzed geological information.
    (m) Interpreted geophysical information means knowledge, often in 
the form of schematic cross sections and maps, developed by determining 
the geological significance of geophysical data and processed 
geophysical information.
    (n) Lease means any form of authorization which is issued under 
section 8 or maintained under section 6 of the Act and which authorizes 
exploration for, and development and production of, oil or natural gas, 
or the land covered by such authorization, whichever is required by the 
context.
    (o) Lessee means the party authorized by a lease, or an approved 
assignment thereof, to explore for and develop and produce the leased 
deposits in accordance with the regulations in part 250 of

[[Page 476]]

this chapter, including all parties holding such authority by or through 
the lessee.
    (p) Outer Continental Shelf (OCS) means all submerged lands which 
lie seaward and outside of the area of lands beneath navigable waters as 
defined in the Submerged Lands Act (67 Stat. 29) and of which the 
subsoil and seabed appertain to the United States and are subject to its 
jurisdiction and control.
    (q) Permittee means the party authorized by a permit issued pursuant 
to part 251 of this chapter to conduct activities on the OCS.
    (r) Processed geophysical information means data collected under a 
permit or a lease which have been processed. Processing involves 
changing the form of data so as to facilitate interpretation. 
Processsing operations may include, but are not limited to, applying 
corrections for known perturbing causes, rearranging or filtering data, 
and combining or transforming data elements.
    (s) Production means those activities which take place after the 
successful completion of any means for the removal of oil or natural 
gas, including such removal, field operations, transfer of oil or 
natural gas to shore, operation monitoring, maintenance, and workover 
drilling.
    (t) Secretary means the Secretary of the Interior or a designee of 
the Secretary.

[44 FR 46408, Aug. 7, 1979, as amended at 49 FR 10670, Mar. 22, 1984; 51 
FR 10382, Mar. 26, 1986]



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

[[Page 477]]

the data or information to an independent contractor or agent. The 
Director's notice of intent will afford the permittee(s) or lessee(s) a 
period of not less than 5 working days within which to comment on the 
intended action. When the Director so notifies a lessee or permittee of 
the intent to disclose data or information to an independent contractor 
or agent, all other owners of such data or information shall be deemed 
to have been notified of the Director's intent. Prior to any such 
disclosure, the contractor or agent shall be required to execute a 
written commitment not to disclose any data or information to anyone 
without the express consent of the Director, and not to make any 
disclosure or use of the data or information other than that provided in 
the contract. Contracts between the Minerals Management Service and 
independent contractors shall be available to the lessee(s) or 
permittee(s) for inspection. In the event of any unauthorized use or 
disclosure of data or information by the contractor or agent, or by an 
employee thereof, the responsible contractor or agent or employee 
thereof shall be liable for penalties pursuant to section 24 of the Act.
    (e)(1) After delivery of data or information in accordance with 
paragraph (b)(1) of this section and upon receipt of a request for 
reimbursement and a determination by the Director that the requested 
reimbursement is proper, the lessee or permittee shall be reimbursed for 
the cost of reproducing the data or information at the lessee's or 
permittee's lowest rate or at the lowest commercial rate established in 
the area, whichever is less. Requests for reimbursement must be made 
within 60 days of the delivery date of the data or information requested 
under paragraph (b)(1) of this section.
    (2) After delivery of data or information in accordance with 
paragraph (b)(3) of this section, and upon receipt of a request for 
reimbursement and a determination by the Director that the requested 
reimbursement is proper, the lessee or permittee shall be reimbursed for 
the cost of processing or reprocessing and of reproducing the requested 
data or information. Requests for reimbursement must be made within 60 
days of the delivery date of the data or information and shall be for 
only the costs attributable to processing or reprocessing and 
reproducing, as distinguished from the costs of data acquisition.
    (3) Requests for reimbursement are to contain a breakdown of costs 
in sufficient detail to allow separation of reproduction, processing, 
and reprocessing costs from acquisition and other costs.
    (f) Each Federal Department or Agency shall provide the Director 
with any data which it has obtained pursuant to section 11 of the Act 
and any other information which may be necessary or useful to assist the 
Director in carrying out the provisions of the Act.

[44 FR 46408, Aug. 7, 1979, as amended at 51 FR 17176, May 9, 1986]



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

[[Page 478]]

the development of the Summary Report. The Summary Report shall include:
    (1) Estimates of oil and gas reserves; estimates of the oil and gas 
resources that may be found within areas which the Secretary has leased 
or plans to offer for lease; and when available, projected rates and 
volumes of oil and gas to be produced from leased areas;
    (2) Magnitude of the approximate projections and timing of 
development, if and when oil or gas, or both, is discovered;
    (3) Methods of transportation to be used, including vessels and 
pipelines and approximate location of routes to be followed; and
    (4) General location and nature of near-shore and onshore facilities 
expected to be utilized.
    (b) When the Director determines that significant changes have 
occurred in the information contained in a Summary Report, the Director 
shall prepare and make available the new or revised information to each 
affected State, and, upon request, to the executive of any affected 
local government.



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 479]]

    (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 480]]

               Subpart B_Applicability and Amount of OSFR

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

                Subpart C_Methods for Demonstrating OSFR

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

         Subpart D_Requirements for Submitting OSFR Information

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

                   Subpart E_Revocation and Penalties

253.50 How can MMS refuse or invalidate my OSFR evidence?
253.51 What are the penalties for not complying with this part?

        Subpart F_Claims for Oil-Spill Removal Costs and Damages

253.60 To whom may I present a claim?
253.61 When is a guarantor subject to direct action for claims?
253.62 What are the designated applicant's notification obligations 
          regarding a claim?

Appendix to Part 253--List of U.S. Geological Survey Topographic Maps

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

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

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



                            Subpart A_General



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 481]]

    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 482]]

    (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 483]]

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 484]]



------------------------------------------------------------------------
  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
    (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,

[[Page 485]]

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 Sec. Sec. 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.
    (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

[[Page 486]]

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 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

[[Page 487]]

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 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 Sec. Sec. 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

[[Page 488]]

    (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 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,

[[Page 489]]

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.



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

[[Page 490]]

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 $27,500 per 
COF per day of violation (that is, each day a COF is operated without 
acceptable evidence of OSFR).
    (b) MMS will determine the date of a noncompliance. MMS will assess 
penalties in accordance with an OSFR penalty schedule using the 
procedures found at 30 CFR part 250, subpart N. You may obtain a copy of 
the penalty schedule from MMS at the address in 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; 
72 FR 8899, Feb. 28, 2007]



        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:

------------------------------------------------------------------------
 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,

[[Page 491]]

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 to Part 253--List of U.S. Geological Survey Topographic Maps

    Alabama (1:24,000 scale): Bellefontaine; Bon Secour Bay; Bridgehead; 
Coden; Daphne; Fort Morgan; Fort Morgan NW; Grand Bay; Grand Bay SW; 
Gulf Shores; Heron Bay; Hollingers Island; Isle Aux Herbes; Kreole; 
Lillian; Little Dauphin Island; Little Point Clear; Magnolia Springs; 
Mobile; Orange Beach; Perdido Beach; Petit Bois Island; Petit Bois Pass; 
Pine Beach; Point Clear; Saint Andrews Bay; West Pensacola.
    Alaska (1:63,360 scale): Afognak (A-1, A-2, A-3, A-4, A-5, A-0&B-0, 
B-1, B-2, B-3, C-1&2, C-2&3, C-5, C-6, D-1, D-4, D-5); Anchorage (A-1, 
A-2, A-3, A-4, A-8, B-7, B-8); Barrow (A-1, A-2, A-3, A-4, A-5, B-3, B-
4); Baird Mts. (A-6); Barter Island (A-3, A-4, A-5); Beechy Point (A-1, 
A-2, B-1, B-2, B-3, B-4, B-5, C-4, C-5); Bering Glacier (A-1, A-2, A-3, 
A-4, A-5, A-6, A-7, A-8); Black (A-1, A-2, B-1, C-1); Blying Sound (C-7, 
C-8, D-1&2, D-3, D-4, D-5, D-6, D-7, D-8); Candle (D-6); Cordova (A-1, 
A-2, A-3, A-4, A-7&8, B-2, B-3, B-4, B-5, B-6, B-7, B-8, C-5, C-6, C-7, 
C-8, D-6, D-7, D-8); De Long Mts. (D-4, D-5); Demarcation Point (C-1, C-
2, D-2, D-3); Flaxman Island (A-1, A-3, A-4, A-5, B-5); Harrison Bay (B-
1, B-2, B-3, B-4, C-1, C-3, C-4, C-5, D-4, D-5); Icy Bay (D1, D-2&3); 
Iliamna (A-2, A-3, A-4, B-2, B-3, C-1, C-2, D-1); Karluk (A-1, A-2, B-2, 
B-3, C-1, C-2, C-4&5, C-6); Kenai (A-4, A-5, A-7, A-8, B-4, B-6, B-7, B-
8, C-4, C-5, C-6, C-7, D-1, D-2, D-3, D-4, D-5); Kodiak (A-3, A-4, A-5, 
A-6, B-1&2, B-3, B-4, B-6, C-1, C-2, C-3, C-5, C-6, D-1, D-2, D-3, D-4, 
D-5, D-6); Kotzebue (A-1, A-2, A-3, A-4, B-4, B-6, C-1, C-4, C-5, C-6, 
D-1, D-2); Kwiguk (C-6, D-6); Meade River (D-1, D-3, D-4, D-5); 
Middleton Island (B-7, D-1&2); Mt. Katmai (A-1, A-2, A-3; B-1); Mt. 
Michelson (D-1, D-2, D-3); Mt. St. Elias (A-5); Noatak (A-1, A-2, A-3, 
A-4, B-4, C-4, C-5, D-6, D-7); Nome (B-1, C-1, C-2, C-3, D-3, D-4, D-7); 
Norton Bay (A-4, B-4, B-5, B-6, C-4, C-5, C-6, D-4, D-5, D-6); Point 
Hope (A-1, A-2, B-2, B-3, C-2, C-3, D-1, D-2); Point Lay (A-3&4, B-2&3, 
C-2, D-1, D-2); Selawik (A-5, A-6, B-5, B-6, C-5, C-6, D-6); Seldovia 
(A-3, A-4, A-5, A-6, B-1, B-2, B-3, B-4, B-5, B-6, C-1, C-2, C-3, C-4, 
C-5, D-1, D-3, D-4, D-5, D-8); Seward (A-1, A-2, A-3, A-4, A-5, A-6, A-
7, B-1, B-2, B-3, B-4, B-5, C-1, C-2, C-3, C-4, C-5, D-1, D-2, D-3, D-4, 
D-5, D-6, D-7, D-8); Shishmaref (A-2, A-3, A-4, B-1, B-2, B-3); Solomon 
(B-2, B-3, B-6, C-1, C-2, C-3, C-4, C-5, C-6); St. Michael (A-2, A-3, A-
4, A-5, A-6, B-1, B-2, C-1, C-2); Teller (A-2, A-3, A-4, B-3, B-4, B-5, 
B-6, C-6, C-7, D-4, D-5, D-6, D-8); Teshekpuk (D-1, D-2, D-3, D-4, D-5); 
Tyonek (A-1, A-2, A-3, A-4, B-1, B-2); Unalakleet (B-5, B-6, C-4, C-5, 
D-4); Valdez (A-7, A-8); Wainwright (A-5, A-6&7, B-2, B-3, B-4, B-5&6, 
C-2, C-3 , D-1, D-2; Yakutat (A-1, A-2, A-2, B-3, B-4, B-5, C-4, C-5, C-
6, C-7, C-8, D-3, D-4, D-5, D-6, D-8).
    California (1:24,000 scale): Arroyo Grande NE; Beverly Hills; 
Carpinteria; Casmalia; Dana Point; Del Mar; Dos Pueblos Canyon; 
Encinitas; Gaviota; Goleta; Guadalupe; Imperial Beach; Laguna Beach; La 
Jolla; Las Pulgas Canyon; Lompoc Hills; Long Beach; Los Alamitos; Malibu 
Beach; Morro Bay South; National City; Newport Beach; Oceano; Oceanside; 
Oxnard; Pismo Beach; Pitas Point; Point Arguello; Point Conception; 
Point Dune; Point Loma; Point Mugu; Point Sal; Port San Luis; Rancho 
Santa Fe; Redondo Beach; Sacate; San Clemente; San Juan Capistrano; San 
Luis Rey; San Onofre Bluff; San Pedro; Santa Barbara; Saticoy; Seal 
Beach; Surf; Tajiguas; Topanga; Torrance; Tranquillon Mountain; Triunfo 
Pass; Tustin; Venice; Ventura; White Ledge Peak.
    Florida (1:24,000 scale): Allanton; Alligator Bay; Anna Maria; 
Apalachicola; Aripeka; Bayport; Beacon Beach; Beacon Hill; Bee Ridge; 
Belle Meade; Belle Meade NW; Beverly; Big Lostmans Bay; Bird Keys; 
Bokeelia; Bonita Springs; Bradenton; Bradenton Beach; Bruce; Bunker; 
Cape Romano; Cape Saint George; Cape San Blas; Captiva; Carrabelle; 
Cedar Key; Chassahowitzka; Chassahowitzka Bay; Chiefland SW; Choctaw 
Beach; Chokoloskee; Clearwater; Clive Key; Cobb Rocks; Cockroach Bay; 
Crawfordville East; Crooked Island; Crooked Point; Cross City SW; 
Crystal River; Destin; Dog Island; Dunedin; East Pass; Egmont Key; El 
Jobean;

[[Page 492]]

Elfers; Englewood; Englewood NW; Estero; Everglades City; Fivay 
Junction; Flamingo; Fort Barrancas; Fort Myers Beach; Fort Myers SW; 
Fort Walton Beach; Freeport; Gandy Bridge; Garcon Point; Gator Hook 
Swamp; Gibsonton; Goose Island; Grayton Beach; Green Point; Gulf Breeze; 
Harney River; Harold SE; Holley; Holt SW; Homosassa; Horseshoe Beach; 
Indian Pass; Jackson River; Jena; Keaton Beach; Laguna Beach; Lake 
Ingraham East; Lake Ingraham West; Lake Wimico; Laurel; Lebanon Station; 
Lighthouse Point; Lillian; Long Point; Lostmans River Ranger Station; 
Manlin Hammock; Marco Island; Mary Esther; Matlacha; McIntyre; Milton 
South; Miramar Beach; Myakka River; Naples North; Naples South; Navarre; 
New Inlet; Niceville; Nutall Rise; Ochopee; Okefenokee Slough; Oldsmar; 
Orange Beach; Oriole Beach; Overstreet; Ozello; Pace; Palmetto; Panama 
City; Panama City Beach; Panther Key; Pass-A-Grille Beach; Pavillion 
Key; Pensacola; Perdido Bay; Pickett Bay; Pine Island Center; Placida; 
Plover Key; Point Washington; Port Boca Grande; Port Richey; Port Richey 
NE; Port Saint Joe; Port Tampa; Punta Gorda; Punta Gorda SE; Punta Gorda 
SW; Red Head; Red Level; Rock Islands; Royal Palm Hammock; Safety 
Harbor; Saint Joseph Point; Saint Joseph Spit; Saint Marks; Saint Marks 
NE; Saint Petersburg; Saint Teresa Beach; Salem SW; Sandy Key; Sanibel; 
Sarasota; Seahorse Key; Seminole; Seminole Hills; Shark Point; Shark 
River Island; Shired Island; Snipe Island; Sopchoppy; South of Holley; 
Southport; Sprague Island; Spring Creek; Springfield; Steinhatchee; 
Steinhatchee SE; Steinhatchee SW; Sugar Hill; Sumner; Suwannee; Tampa; 
Tarpon Springs; Valparaiso; Venice; Vista; Waccassasa Bay; Ward Basin; 
Warrior Swamp; Weavers Station; Weeki Wachee Spring; West Bay; West 
Pass; West Pensacola; Whitewater Bay West; Withlacoochee Bay; Wulfert; 
Yankeetown.
    Louisiana (1:24,000 scale): Alligator Point; Barataria Pass; Bastian 
Bay; Bay Batiste; Bay Coquette; Bay Courant; Bay Dosgris; Bay Ronquille; 
Bay Tambour; Bayou Blanc; Bayou Lucien; Belle Isle; Belle Pass; Big 
Constance Lake; Black Bay North; Black Bay South; Breton Islands; Breton 
Islands SE; Buras; Burrwood Bayou East; Burwood Bayou West; Calumet 
Island; Cameron; Caminada Pass; Cat Island; Cat Island Pass; Central 
Isles Dernieres; Chandeleur Light; Chef Mentur; Cheniere Au Tigre; 
Cocodrie; Coquille Point; Cow Island; Creole; Cypremort Point; Deep 
Lake; Dixon Bay; Dog Lake; Door Point; East Bay Junop; Eastern Isles; 
Dernieres; Ellerslie; Empire; English Lookout; False Mouth Bayou; 
Fearman Lake; Floating Turf Bayou; Fourleague Bay; Franklin; Freemason 
Island; Garden Island Pass; Grand Bayou; Grand Bayou du Large; Grand 
Chenier; Grand Gosier Islands; Grand Isle; Hackberry Beach; Hammock 
Lake; Happy Jack; Hebert Lake; Hell Hole Bayou; Hog Bayou; Holly Beach; 
Intercoastal City; Isle Au Pitre; Jacko Bay; Johnson Bayou; Kemper; Lake 
Athanasio; Lake Cuatro Caballo; Lake Eloi; Lake Eugene; Lake Felicity; 
Lake La Graisse; Lake Merchant; Lake Point; Lake Salve; Lake Tambour; 
Leeville; Lena Lagoon; Lost Lake; Main Pass; Malheureux Point; Marone 
Point; Martello Castle; Mink Bayou; Mitchell Key; Morgan City SW; Morgan 
Harbor; Mound Point; Mulberry Island East; Mulberry Island West; New 
Harbor Islands; North Islands; Oak Mound Bayou; Oyster Bayou; Pass A 
Loutre East; Pass A Loutre West; Pass du Bois; Pass Tante Phine; Pecan 
Island; Pelican Pass; Peveto Beach; Pilottown; Plumb Bayou; Point Au 
Fer; Point Au Fer NE; Point Chevreuil; Point Chicot; Port Arthur South; 
Port Sulphur; Pte. Aux Marchuttes; Proctor Point; Pumpkin Islands; 
Redfish Point; Rollover Lake; Sabine Pass; Saint Joe Pass; Smith Bayou; 
South of South Pass; South Pass; Stake Islands; Taylor Pass; Texas 
Point; Three Mile Bay; Tigre Lagoon; Timbalier Island; Triumph; Venice; 
Weeks; West of Johnson Bayou; Western Isles Dernieres; Wilkinson Bay; 
Yscloskey.
    Mississippi (1:24,000 scale): Bay Saint Louis; Biloxi; Cat Island; 
Chandeleur Light; Deer Island; Dog Keys Pass; English Lookout; Gautier 
North; Gautier South; Grand Bay SW; Gulfport North; Gulfport NW; 
Gulfport South; Horn Island East; Horn Island West; Isle Au Pitre; 
Kreole; Ocean Springs; Pascagoula North; Pascagoula South; Pass 
Christian; Petit Bois Island; Saint Joe Pass; Ship Island; Waveland.
    Texas (1:24,000 scale): Allyns Bright; Anahuac; Aransas Pass; 
Austwell; Bacliff; Bayside; Big Hill Bayou; Brown Cedar Cut; Caplen; 
Carancahua Pass; Cedar Lakes East; Cedar Lakes West; Cedar Lane NE; 
Christmas Point; Clam Lake; Corpus Christi; Cove; Crane Islands NW; 
Crane Islands SW; Decros Point; Dressing Point; Estes; Flake; Freeport; 
Frozen Point; Galveston; Green Island; Hawk Island; High Island; 
Hitchcock; Hoskins Mound; Jones Creek; Keller Bay; Kleberg Point; La 
Comal; La Leona; La Parra Ranch NE; Laguna Vista; Lake Austin; Lake 
Como; Lake Stephenson; Lamar; Long Island; Los Amigos; Windmill; Maria 
Estella Well; Matagorda; Matagorda SW; Mesquite Bay; Mission Bay; 
Morgans Point; Mosquito Point; Mouth of Rio Grande; Mud Lake; North of 
Port Isabel NW; North of Port Isabel SW; Oak Island; Olivia; Oso Creek 
NE; Oyster Creek; Palacios; Palacios NE; Palacios Point; Palacios SE; 
Panther Point; Panther Point NE; Pass Cavallo SW; Pita Island; Point 
Comfort; Point of Rocks; Port Aransas; Port Arthur South; Port Bolivar; 
Port Ingleside; Port Isabel; Port Isabel NW; Port Lavaca East; Port 
Mansfield; Port

[[Page 493]]

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.
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

[[Page 494]]

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 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

[[Page 495]]

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.
    District Manager means the MMS officer with authority and 
responsibility for a district within an MMS Region.
    Facility means any structure, group of structures, equipment, or 
device (other than a vessel) which is used for one or more of the 
following purposes: Exploring for, drilling for, producing, storing, 
handling, transferring, processing, or transporting oil. The term 
excludes deep-water ports and their associated pipelines as defined by 
the Deepwater Port Act of 1974, but includes other pipelines used for 
one or more of these purposes. A mobile offshore drilling unit is 
classified as a facility when engaged in drilling or downhole 
operations.
    Maximum extent practicable means within the limitations of available 
technology, as well as the physical limitations of personnel, when 
responding to a worst case discharge in adverse weather conditions.
    National Contingency Plan means the National Oil and Hazardous 
Substances Pollution Contingency Plan prepared and published under 
section 311(d) of the FWPCA, (33 U.S.C. 1321(d)) or revised under 
section 105 of the Comprehensive Environmental Response Compensation and 
Liability Act (42 U.S.C. 9605).
    National Contingency Plan Product Schedule means a schedule of 
dispersants and other chemical or biological products, maintained by the 
Environmental Protection Agency, that may be authorized for use on oil 
discharges in accordance with the procedures found at 40 CFR 300.910.
    Oil means oil of any kind or in any form, including but not limited 
to petroleum, fuel oil, sludge, oil refuse, and oil mixed with wastes 
other than dredged spoil. This also includes hydrocarbons produced at 
the wellhead in liquid form (includes distillates or condensate 
associated with produced natural gas), and condensate that has been

[[Page 496]]

separated from a gas prior to injection into a pipeline. It does not 
include petroleum, including crude oil or any fraction thereof, which is 
specifically listed or designated as a hazardous substance under 
paragraphs (A) through (F) of section 101(14) of the Comprehensive 
Environmental Response, Compensation, and Liability Act (42 U. S. C. 
9601) and which is subject to the provisions of that Act. It also does 
not include animal fats and oils and greases and fish and marine mammal 
oils, within the meaning of paragraph (2) of section 61(a) of title 13, 
United States Code, and oils of vegetable origin, including oils from 
the seeds, nuts, and kernels referred to in paragraph (1)(A) of that 
section.
    Oil spill removal organization (OSRO) means an entity contracted by 
an owner or operator to provide spill-response equipment and/or manpower 
in the event of an oil or hazardous substance spill.
    Outer Continental Shelf means all submerged lands lying seaward and 
outside of the area of lands beneath navigable waters as defined in 
section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the 
subsoil and seabed appertain to the United States and are subject to its 
jurisdiction and control.
    Owner or operator means, in the case of an offshore facility, any 
person owning or operating such offshore facility. In the case of any 
abandoned offshore facility, it means the person who owned such facility 
immediately prior to such abandonment.
    Pipeline means pipe and any associated equipment, appurtenance, or 
building used or intended for use in the transportation of oil located 
seaward of the coast line, except those used for deep-water ports. 
Pipelines do not include vessels such as barges or shuttle tankers used 
to transport oil from facilities located seaward of the coast line.
    Qualified individual means an English-speaking representative of an 
owner or operator, located in the United States, available on a 24-hour 
basis, with full authority to obligate funds, carry out removal actions, 
and communicate with the appropriate Federal officials and the persons 
providing personnel and equipment in removal operations.
    Regional Response Plan means a spill-response plan required by this 
part which covers multiple facilities or leases of an owner or operator, 
including affiliates, which are located in the same MMS Region.
    Regional Supervisor means the MMS official with responsibility and 
authority for operations or other designated program functions within an 
MMS Region.
    Remove means containment and cleanup of oil from water and 
shorelines or the taking of other actions as may be necessary to 
minimize or mitigate damage to the public health or welfare, including, 
but not limited to, fish, shellfish, wildlife, public and private 
property, shorelines, and beaches.
    Spill is synonymous with ``discharge'' for the purposes of this 
part.
    Spill management team means the trained persons identified in a 
response plan who staff the organizational structure to manage spill 
response.
    Spill-response coordinator means a trained person charged with the 
responsibility and designated the commensurate authority for directing 
and coordinating response operations.
    Spill-response operating team means the trained persons who respond 
to spills through deployment and operation of oil-spill response 
equipment.
    State waters located seaward of the coast line means the belt of the 
seas measured from the coast line and extending seaward a distance of 3 
miles (except the coast of Texas and the Gulf coast of Florida, where 
the State waters extend seaward a distance of 3 leagues).
    You means the owner or the operator as defined in this section.

[62 FR 13996, Mar. 25, 1997, as amended at 71 FR 46400, Aug. 14, 2006]



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.

[[Page 497]]

    (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]



     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.

[[Page 498]]



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 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

[[Page 499]]

    (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 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));

[[Page 500]]

    (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 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

[[Page 501]]

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.
    (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.

[[Page 502]]

    (3) An annual notification exercise for each facility that is manned 
on a 24- hour basis. The exercise must test the ability of facility 
personnel to communicate pertinent information in a timely manner to the 
qualified individual.
    (4) A semiannual deployment exercise of any response equipment which 
the MMS Regional Supervisor requires an owner or operator to maintain at 
the facility or on dedicated vessels. You must deploy and operate each 
type of this equipment at least once each year. Each type need not be 
deployed and operated at each exercise.
    (c) During your exercises, you must simulate conditions in the area 
of operations, including seasonal weather variations, to the extent 
practicable. The exercises must cover a range of scenarios over the 3-
year exercise period, simulating responses to large continuous spills, 
spills of short duration and limited volume, and your worst case 
discharge scenario.
    (d) MMS will recognize and give credit for any documented exercise 
conducted that satisfies some part of the required triennial exercise. 
You will receive this credit whether the owner or operator, an OSRO, or 
a Government regulatory agency initiates the exercise. MMS will give you 
credit for an actual spill response if you evaluate the response and 
generate a proper record. Exercise documentation should include the 
following information:
    (1) Type of exercise;
    (2) Date and time of the exercise;
    (3) Description of the exercise;
    (4) Objectives met; and
    (5) Lessons learned.
    (e) All records of spill-response exercises must be maintained for 
the complete 3-year exercise cycle. Records should be maintained at the 
facility or at a corporate location designated in the plan. Records 
showing that OSRO's and oil spill removal cooperatives have deployed 
each type of equipment also must be maintained for the 3-year cycle.
    (f) You must inform the Regional Supervisor of the date of any 
exercise required by paragraph (b)(1), (2), or (4) of this section at 
least 30 days before the exercise. This will allow MMS personnel the 
opportunity to witness any exercises.
    (g) The Regional Supervisor periodically will initiate unannounced 
drills to test the spill response preparedness of owners and operators.
    (h) The Regional Supervisor may require changes in the frequency or 
location of the required exercises, equipment to be deployed and 
operated, or deployment procedures or strategies. The Regional 
Supervisor may evaluate the results of the exercises and advise the 
owner or operator of any needed changes in response equipment, 
procedures, or strategies.
    (i) Compliance with the National Preparedness for Response Exercise 
Program (PREP) Guidelines will satisfy the exercise requirements of this 
section. Copies of the PREP document may be obtained from the Regional 
Supervisor.



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

[[Page 503]]

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 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).

[[Page 504]]

    (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 Sec. Sec. 254.51, 254.52, and 254.53.



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

[[Page 505]]

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.
256.7 Cross references.
256.8 Leasing maps and diagrams.
256.10 Information to States.
256.11 Helium.
256.12 Supplemental sales.

                  Subpart B_Oil and Gas Leasing Program

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

                 Subpart C_Reports From Federal Agencies

256.22 General.

             Subpart D_Call for Information and Nominations

256.23 Information on areas.
256.25 Areas near coastal States.

              Subpart E_Area Identification and Tract Size

256.26 General.
256.28 Tract size.

                          Subpart F_Lease Sales

256.29 Proposed notice of sale.
256.31 State comments.
256.32 Notice of sale.

                      Subpart G_Issuance of Leases

256.35 Qualifications of lessees.
256.37 Lease term.
256.38 Joint bidding provisions.
256.40 Definitions.
256.41 Joint bidding requirements.
256.43 Chargeability for production.
256.44 Bids disqualified.
256.46 Submission of bids.
256.47 Award of leases.
256.49 Lease form.
256.50 Dating of leases.

[[Page 506]]

Subpart H--Rentals and Royalties [Reserved]

                            Subpart I_Bonding

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

            Subpart J_Assignments, Transfers, and Extensions

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

                     Subpart K_Termination of Leases

256.76 Relinquishment of leases or parts of leases.
256.77 Cancellation of leases.

                       Subpart L_Section 6 Leases

256.79 Effect of regulations on lease.
256.80 Leases of other minerals.

                            Subpart M_Studies

256.82 Environmental studies.

Appendix A to Part 256--Oil and Gas Cash Bonus Bid

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

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



  Subpart A_Outer Continental Shelf Oil, Gas, and Sulphur Management, 
                                 General



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 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

[[Page 507]]

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;
    (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;

[[Page 508]]

    (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 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

[[Page 509]]

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.
    (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

[[Page 510]]

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. 256.16  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 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

[[Page 511]]

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 Sec. Sec. 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 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

[[Page 512]]

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 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]

[[Page 513]]



                          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 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

[[Page 514]]

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]



Sec. 256.38  Joint bidding provisions.



Sec. 256.40  Definitions.

    The following definitions apply to Sec. Sec. 256.38 through 256.44 
of this part.
    (a) Single bid means a bid submitted by one person for an oil and 
gas lease under section 8(a) of the Act.
    (b) Joint bid means a bid submitted by two or more persons for an 
oil and gas lease under section 8(a) of the Act.
    (c) Average daily production is the total of all production in an 
applicable production period which is chargeable under 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

[[Page 515]]

interest, a production payment, or a carried interest.
    (g) Liquefied petroleum products means natural gas liquid products 
including the following: ethane, propane, butane, pentane, natural 
gasoline, and other natural gas products recovered by a process of 
absorption, adsorption, compression, or refrigeration cycling, or a 
combination of such processes.
    (h) Natural gas means a mixture of hydrocarbons and varying 
quantities of nonhydrocarbons that exist in the gaseous phase.
    (i) Oil and gas lease means an oil and gas lease either offered or 
issued pursuant to the provisions of the Act.
    (j) Owned means:
    (1) With respect to crude oil--having either an economic interest in 
or a power of disposition over the production of crude oil;
    (2) With respect to natural gas--having either an economic interest 
in or a power of disposition over the production of natural gas; and
    (3) With respect to liquefied petroleum products--having either an 
economic interest in or a power of disposition over any liquefied 
petroleum product at the time of completion of the liquefaction process.
    (k) Prior production period means the continuous six month period of 
January 1 through June 30 preceding November 1 through April 30 for 
joint bids submitted during the six month bidding period from November 1 
through April 30, and means the continuous six month period of July 1 
through December 31 preceding May 1 through October 31 for joint bids 
submitted during the six month bidding period from May 1 through October 
31.
    (l) Production--(1) Of crude oil means the volume of crude oil 
produced worldwide from reservoirs during the prior production period. 
The amount of such crude oil production shall be established by 
measurement of volumes delivered at the point of custody transfer (e.g., 
from storage tanks to pipelines, trucks, tankers, or other media for 
transport to refineries or terminals) with adjustments for:
    (i) Net differences between opening and closing inventories, and
    (ii) Basic sediment and water;
    (2) Of natural gas means the volume of natural gas produced 
worldwide from natural oil and gas reservoirs during the prior 
production period, with adjustments, where applicable, to reflect
    (i) The volume of gas returned to natural reservoirs; and
    (ii) The reduction of volume resulting from the removal of natural 
gas liquids and nonhydrocarbon gases.
    (3) Of liquefied petroleum products means the volume of natural gas 
liquids produced from reservoir gas and liquefied at surface separators, 
field facilities, or gas processing plants worldwide during the prior 
production period; these liquefied petroleum products include the 
following:
    (i) Condensate--natural gas liquids recovered from gas well gas 
(associated and non-associated) in separators or field facilities;
    (ii) Gas plant products--natural gas liquids recovered from natural 
gas in gas processing plants and from field facilities. Gas plant 
products shall include the following as classified according to the 
standards of the Natural Gas Processors Association (NGPA) or the 
American Society for Testing and Materials (ASTM):
    (A) Ethane--C2 H6
    (B) Propane--C3 H8
    (C) Butane--C4 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

[[Page 516]]

    (1) From May 1 through October 31; or
    (2) From November 1 through April 30, respectively.

[44 FR 38276, June 29, 1979; 44 FR 55380, Sept. 26, 1979. Redesignated 
at 47 FR 47006, Oct. 22, 1982, as amended at 66 FR 11518, Feb. 23, 2001]



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 
Sec. Sec. 256.41(a), 256.44, 256.46(g) and 256.62(b) of this part if it 
is found, on the record, after an opportunity for an agency hearing, 
that lands being offered have extremely high cost exploration and 
development problems and that exploration and development will not occur 
on such lands unless the exemption is granted.

[44 FR 38276, June 29, 1979; 44 FR 55380, Sept. 26, 1979, as amended at 
45 FR 69174, Oct. 17, 1980; 47 FR 25971, June 16, 1982. Redesignated and 
amended at 47 FR 47006, 47007, Oct. 22, 1982]



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

[[Page 517]]

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.
    (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

[[Page 518]]

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).
    (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.

[[Page 519]]

    (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 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.

[[Page 520]]

    (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
    (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 Gulf of Mexico and the area offshore the Atlantic Coast.
    (2) The area offshore the Pacific Coast States of California, 
Oregon, Washington, and Hawaii; and
    (3) The area offshore the Coast of Alaska.
    (c) The requirement to maintain a lease bond (or substitute security 
instruments) under paragraph (a)(1) of this section and 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 
alternative form of security maintained under this section, the surety's 
remaining liability under the bond or alternative form of security is 
reduced by the amount of that payment. See paragraph (e) of this section 
for the requirement to replace the reduced bond coverage.
    (e) If the value of your surety bond or alternative security is 
reduced because of a default, or for any other reason, you must provide 
additional bond coverage sufficient to meet the security required under 
this subpart within 6 months, or such shorter period of time as the 
Regional Director may direct.

[[Page 521]]

    (f) You may pledge U.S. Department of the Treasury (Treasury) 
securities instead of a bond. The Treasury securities you pledge must be 
negotiable for an amount of cash equal to the value of the bond they 
replace.
    (1) If you pledge Treasury securities under this paragraph (f), you 
must monitor their value. If their market value falls below the level of 
bond coverage required under this subpart, you must pledge additional 
Treasury securities to raise the value of the securities pledged to the 
required amount.
    (2) If you pledge Treasury securities, you must include authority 
for the Regional Director to sell them and use the proceeds when the 
Regional Director determines that you fail to satisfy any lease 
obligation.
    (g) You may pledge alternative types of security instruments instead 
of providing a bond if the Regional Director determines that the 
alternative security protects the interests of the United States to the 
same extent as the required bond.
    (1) If you pledge an alternative type of security under this 
paragraph, you must monitor the security's value. If its market value 
falls below the level of bond coverage required under this subpart, you 
must pledge additional securities to raise the value of the securities 
pledged to the required amount.
    (2) If you pledge an alternative type of security, you must include 
authority for the Regional Director to sell the security and use the 
proceeds when the Regional Director determines that you failed to 
satisfy any lease obligation.
    (h) If you fail to replace a deficient bond or to provide additional 
bond coverage upon demand, the Regional Director may:
    (1) Assess penalties under part 250, subpart N of this chapter;
    (2) Suspend production and other operations on your leases in 
accordance with 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, as amended at 66 
FR 60150, Dec. 3, 2001]



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.
    (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

[[Page 522]]

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 Sec. Sec. 256.52(a) and 
256.53 (a) and (b) of this part) is necessary to ensure compliance with 
the obligations under your lease and the regulations in this chapter.
    (1) The Regional Director's determination will be based on his/her 
evaluation of your ability to carry out present and future financial 
obligations demonstrated by:
    (i) Financial capacity substantially in excess of existing and 
anticipated lease and other obligations, as evidenced by audited 
financial statements (including auditor's certificate, balance sheet, 
and profit and loss sheet);
    (ii) Projected financial strength significantly in excess of 
existing and future lease obligations based on the estimated value of 
your existing OCS lease production and proven reserves of future 
production;
    (iii) Business stability based on 5 years of continuous operation 
and production of oil and gas or sulphur in the OCS or in the onshore 
oil and gas industry;
    (iv) Reliability in meeting obligations based on:
    (A) Credit rating(s); or
    (B) Trade references, including names and addresses of other 
lessees, drilling contractors, and suppliers with whom you have dealt; 
and
    (v) Record of compliance with laws, regulations, and lease terms.
    (2) You may satisfy the Regional Director's demand for additional 
security by increasing the amount of your existing bond or by providing 
a supplemental bond or bonds.
    (e) The Regional Director will determine the amount of supplemental 
bond required to guarantee compliance. The Regional Director will 
consider potential underpayment of royalty and cumulative obligations to 
abandon wells, remove platforms and facilities, and clear the seafloor 
of obstructions in the Regional Director's case-specific analysis.
    (f) If your cumulative potential obligations and liabilities either 
increase or decrease, the Regional Director may adjust the amount of 
supplemental bond required.
    (1) If the Regional Director proposes an adjustment, the Regional 
Director will:
    (i) Notify you and the surety of any proposed adjustment to the 
amount of bond required; and
    (ii) Give you an opportunity to submit written or oral comment on 
the adjustment.
    (2) If you request a reduction of the amount of supplemental bond 
required, you must submit evidence to the Regional Director 
demonstrating that the projected amount of royalties due the Government 
and the estimated costs of lease abandonment and cleanup are less than 
the required bond amount. If the Regional Director finds that the 
evidence you submit is convincing, he/she may reduce the amount of 
supplemental bond required.

[58 FR 45262, Aug. 27, 1993. Redesignated and amended at 62 FR 27956, 
May 22, 1997]

[[Page 523]]



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 Sec. Sec. 256.52 and 256.53 of this 
part to the Regional Director and advise the Regional Director of the 
lapse in your previous bond.
    (b) You must notify the Regional Director of any action filed 
alleging that you, your surety, or guarantor are insolvent or bankrupt. 
You must notify the Regional Director within 72 hours of learning of 
such an action. All bonds must require the surety to provide this 
information to you and directly to MMS.

[62 FR 27957, May 22, 1997]



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. 250.1703 of this chapter.
    (2) You must fully fund the lease-specific abandonment account to 
cover all the costs of lease abandonment and site clearance as estimated 
by MMS within the timeframe the Regional Director prescribes.
    (3) You must provide binding instructions under which the 
institution managing the account is to purchase Treasury securities 
pledged to MMS under paragraph (d) of this section.
    (b) Any interest paid on funds in a lease-specific abandonment 
account

[[Page 524]]

will be treated as other funds in the account unless the Regional 
Director authorizes in writing the payment of interest to the party who 
deposits the funds.
    (c) The Regional Director may allow you to pledge Treasury 
securities that are made payable upon demand to the Regional Director to 
satisfy your obligation to make payments into a lease-specific 
abandonment account.
    (d) Before the amount of funds in a lease-specific abandonment 
account equals the maximum insurable amount as determined by the Federal 
Deposit Insurance Corporation or the Federal Savings and Loan Insurance 
Corporation, the institution managing the account must use the funds in 
the account to purchase Treasury securities pledged to MMS under 
paragraph (c) of this section. The institution managing the lease 
specific-abandonment account will join with the Regional Director to 
establish a Federal Reserve Circular 154 account to hold these Treasury 
securities, unless the Regional Director authorizes the managing 
institution to retain the pledged Treasury securities in a separate 
trust account. You may obtain a copy of the current Treasury Circular 
No. 154 from the Surety Bond Branch, Financial Management Service, 
Department of the Treasury, East-West Highway, Hyattsville, MD 20782.
    (e) The Regional Director may require you to create an overriding 
royalty or production payment obligation for the benefit of a lease-
specific account pledged for the abandonment and clearance of a lease. 
The required obligation may be associated with oil and gas or sulphur 
production from a lease other than the lease bonded through the lease-
specific abandonment account.

[62 FR 27957, May 22, 1997; 64 FR 9066, Feb. 24, 1999, as amended at 67 
FR 35412, May 17, 2002]



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 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;

[[Page 525]]

    (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.
    (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

[[Page 526]]

    (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 MMS will 
terminate the period of liability of a bond or cancel a bond. 
Terminating the period of liability of a bond ends the period during 
which obligations continue to accrue but does not relieve the surety of 
the responsibility for obligations that accrued during the period of 
liability. Canceling a bond relieves the surety of all liability. The 
liabilities that accrue during a period of liability include obligations 
that started to accrue prior to the beginning of the period of liability 
and had not been met and obligations that begin accruing during the 
period of liability.
    (a) When the surety under your bond requests termination:
    (1) The Regional Director will terminate the period of liability 
under your bond within 90 days after MMS receives the request; and
    (2) If you intend to continue operations, or have not met all end of 
lease obligations, you must provide a replacement bond of an equivalent 
amount.
    (b) If you provide a replacement bond, the Regional Director will 
cancel your previous bond and the surety that provided your previous 
bond will not retain any liability, provided that:
    (1) The new bond is equal to or greater than the bond that was 
terminated, or you provide an alternative form of security, and the 
Regional Director determines that the alternative form of security 
provides a level of security equal to or greater than that provided for 
by the bond that was terminated;
    (2) For a base bond submitted under Sec. 256.52(a) or under Sec.  
256.53(a) or (b), the surety issuing the new bond agrees to assume all 
outstanding liabilities that accrued during the period of liability that 
was terminated; and
    (3) For supplemental bonds submitted under Sec. 256.53(d), the 
surety issuing the new supplemental bond agrees to assume that portion 
of the outstanding liabilities that accrued during the period of 
liability which was terminated and that the Regional Director determines 
may exceed the coverage of the base bond, and of which the Regional 
Director notifies the provider of the bond.
    (c) This paragraph applies if the period of liability is terminated 
for a bond but the bond is not replaced by a bond of an equivalent 
amount. The surety that provided your terminated bond will continue to 
be responsible for accrued obligations:
    (1) Until the obligations are satisfied; and
    (2) For additional periods of time in accordance with paragraph (d) 
of this section.
    (d) When your lease expires or is terminated, the surety that issued 
a bond will continue to be responsible, and the Regional Director will 
retain other forms of security as shown in the following table:

[[Page 527]]



------------------------------------------------------------------------
                                  The period of
For the following type of bond    liability will     Your bond will be
                                       end            cancelled . . .
------------------------------------------------------------------------
(1) Base bonds submitted under  When the Regional  Seven years after the
 Sec.  256.52(a), Sec.          Director           termination of the
 256.53(a), or (b).              determines that    lease, 6 years after
                                 you have met all   completion of all
                                 of your            bonded obligations,
                                 obligations        or at the conclusion
                                 under the lease.   of any appeals or
                                                    litigation related
                                                    to your bonded
                                                    obligation,
                                                    whichever is the
                                                    latest. The Regional
                                                    Director will reduce
                                                    the amount of your
                                                    bond or return a
                                                    portion of your
                                                    security if the
                                                    Regional Director
                                                    determines that you
                                                    need less than the
                                                    full amount of the
                                                    base bond to meet
                                                    any possible future
                                                    problems.
(2) Supplemental bonds          When the Regional  When you meet your
 submitted under Sec.           Director           bonded obligations,
 256.53(d).                      determines that    unless the Regional
                                 you have met all   Director:
                                 your obligations  (i) Determines that
                                 covered by the     the future potential
                                 supplemental       liability resulting
                                 bond.              from any undetected
                                                    problems is greater
                                                    than the amount of
                                                    the base bond; and
                                                   (ii) Notifies the
                                                    provider of the bond
                                                    that the Regional
                                                    Director will wait 7
                                                    years before
                                                    cancelling all or a
                                                    part of the bond (or
                                                    longer period as
                                                    necessary to
                                                    complete any appeals
                                                    or judicial
                                                    litigation related
                                                    to your bonding
                                                    obligation).
------------------------------------------------------------------------

    (e) For all bonds, the Regional Director may reinstate your bond as 
if no cancellation or release had occurred if:
    (1) A person makes a payment under the lease and the payment is 
rescinded or must be repaid by the recipient because the person making 
the payment is insolvent, bankrupt, subject to reorganization, or placed 
in receivership; or
    (2) The responsible party represents to MMS that it has discharged 
its obligations under the lease, and the representation was materially 
false when the bond was canceled or released.

[66 FR 60150, Dec. 3, 2001]



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.

[[Page 528]]

    (e) If the Regional Director determines that your bond and/or other 
security is forfeited, the Regional Director will:
    (1) Collect the forfeited amount; and
    (2) Use the funds collected to bring your leases into compliance and 
to correct any default.
    (f) If the amount the Regional Director collects under your bond and 
other security is insufficient to pay the full cost of corrective 
actions he/she may:
    (1) Take or direct action to obtain full compliance with your lease 
and the regulations in this chapter; and
    (2) Recover from you, any co-lessee, operating rights owner, and/or 
any third-party guarantor responsible under this subpart all costs in 
excess of the amount he/she collects under your forfeited bond and other 
security.
    (g) The amount that the Regional Director collects under your 
forfeited bond and other security may exceed the costs of taking the 
corrective actions required to obtain full compliance with the terms and 
conditions of your lease and the regulations in this chapter. In this 
case, the Regional Director will return the excess funds to the party 
from whom they were collected.

[62 FR 27958, May 22, 1997]



            Subpart J_Assignments, Transfers, and Extensions



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 Q.
    (f) If your assignee, or a subsequent assignee, fails to perform any 
obligation under the lease or the regulations in this chapter, the 
Regional Director may require you to bring the lease into compliance to 
the extent that the obligation accrued before the Regional Director 
approved the assignment of your interest in the lease.

[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982, 
and amended at 58 FR 45262, Aug. 27, 1993; 62 FR 27959, May 22, 1997; 67 
FR 35412, May 17, 2002]



Sec. 256.63  Service fees.

    (a) The table in this paragraph (a) shows the fees that you must pay 
to MMS for the services listed. The fees will be adjusted periodically 
according to the Implicit Price Deflator for Gross Domestic Product by 
publication of a document in the Federal Register. If a significant 
adjustment is needed to arrive at the new actual cost for any reason 
other than inflation, then a proposed rule containing the new fees will 
be published in the Federal Register for comment.

[[Page 529]]



                            Service Fee Table
                     [Effective September 26, 2005]
------------------------------------------------------------------------
                  Service                   Fee amount   30 CFR citation
------------------------------------------------------------------------
(1) Record Title/Operating Rights                 $170     Sec.  256.64
 (Transfer)...............................
(2) Non-required Document Filing..........          25     Sec.  256.64
------------------------------------------------------------------------

    (b) Once a fee is paid, it is nonrefundable, even if an application 
or other request is withdrawn. If your application is returned to you as 
incomplete, you are not required to submit a new fee with the amended 
application.

[70 FR 49876, Aug. 25, 2005]



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, you must file instruments 
creating or transferring carried working interests, overriding royalty 
interests, or payments out of production with the Regional Director for 
record purposes.
    (8) You must pay the service fee listed in Sec. 256.63 of this 
subpart with your application for approval of any instrument of transfer 
you are required to file (Record Title/Operating Rights (Transfer) Fee). 
Where multiple transfers of interest are included in a single 
instrument, a separate fee applies to each individual transfer of 
interest. For any document you are not required to file by these 
regulations but which you submit for record purposes per lease affected, 
you must also pay the service fee listed in Sec. 256.63 (Non-required 
Document Filing Fee). Such documents may be rejected at the discretion 
of the authorized officer.
    (9) Notwithstanding the provisions of paragraph (a)(8) of this 
section, the requirements to pay a filing fee in connection with any 
application for approval of any instrument of transfer and to pay a fee 
in connection with documents not required to be filed are suspended 
until January 3, 2006.
    (b) An attorney in fact, in behalf of the holder of a lease, 
operating rights or sublease, shall furnish evidence of authority to 
execute the assignment or application for approval and the statement 
required by 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

[[Page 530]]

furnish a bond in the amount prescribed in Sec. Sec. 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 agreements applicable to the acquisition of that lease or a 
fractional interest.

[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982, 
as amended at 62 FR 27959, May 22, 1997; 62 FR 39775, July 24, 1997; 70 
FR 49877, Aug. 25, 2005; 70 FR 61893, Oct. 27, 2005]



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

[[Page 531]]

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 
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

[[Page 532]]

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 
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.

[[Page 533]]



                            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.

           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]

[[Page 534]]



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.
260.1 What is the purpose of this part?
260.2 What definitions apply to this part?
260.3 What is MMS's authority to collect information?

                        Subpart B_Bidding Systems

                           General Provisions

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

                             Eligible Leases

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

                     Royalty Suspension (RS) Leases

260.120 How does royalty suspension apply to leases issued in a sale 
          held after November 2000?
260.121 When does a lease issued in a sale held after November 2000 get 
          a royalty suspension?
260.122 How long will a royalty suspension volume be effective for a 
          lease issued in a sale held after November 2000?
260.123 How do I measure natural gas production for a lease issued in a 
          sale held after November 2000?
260.124 How will royalty suspension apply if MMS assigns a lease issued 
          in a sale held after November 2000 to a field that has an 
          eligible or pre-Act lease?

                    Bidding System Selection Criteria

260.130 What criteria does MMS use for selecting bidding systems and 
          bidding system components?

[[Page 535]]

Subpart C [Reserved]

                         Subpart D_Joint Bidding

260.301 What is the purpose of this subpart?
260.302 What definitions apply to this subpart?
260.303 What are the joint bidding requirements?

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

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



                      Subpart A_General Provisions



Sec. 260.1  What is the purpose of this part?

    Part 260 implements the Outer Continental Shelf Lands Act (OCSLA), 
43 U.S.C. 1331 et seq., as amended, by providing regulations to foster 
competition including, but not limited to:
    (a) Implementing alternative bidding systems;
    (b) Prohibiting joint bidding for development rights by certain 
types of joint ventures; and
    (c) Establishing diligence requirements for Federal OCS leases.



Sec. 260.2  What definitions apply to this part?

    OCS lease means a Federal lease for oil and gas issued under the 
OCSLA.
    OCSLA means the Outer Continental Shelf Lands Act, (43 U.S.C. 1331 
et seq.), as amended.
    Person includes, in addition to a natural person, an association, a 
State, or a private, public, or municipal corporation.
    We means the Minerals Management Service (MMS).
    You means the lessee or operating rights holder.



Sec. 260.3  What is MMS's authority to collect information?

    The Paperwork Reduction Act of 1995 (PRA) requires us to inform you 
that we may not conduct or sponsor and you are not required to respond 
to a collection of information unless it displays a currently valid OMB 
control number. OMB approved the information collection requirements in 
part 260 under 44 U.S.C. 3501 et seq. and assigned OMB control number 
1010-0143. The PRA also requires us to inform you of the following:
    (a) We use the information collected under Sec. Sec. 260.114(a)(2), 
(c)(1) and 260.124 (a)(2):
    (1) To make decisions on requests for reconsideration of our 
assignment of a lease that has a qualifying well to an existing field or 
designate a new field under Sec. Sec. 260.114(a) and 260.124(a), and
    (2) To ensure that the royalty suspension volume is properly 
allocated among constituent leases in a field under Sec. 260.117.
    (b) Respondents are Federal OCS oil and gas lessees and operating 
rights holders. Responses are required to obtain or retain a benefit. We 
will protect proprietary information under applicable law and part 250 
of this chapter.
    (c) You may send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Minerals 
Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 
20240.



                        Subpart B_Bidding Systems

                           General Provisions



Sec. 260.101  What is the purpose of this subpart?

    This subpart establishes the bidding systems that we may use to 
offer and sell Federal leases for the exploration, development, and 
production of oil and gas resources located on the OCS.



Sec. 260.102  What definitions apply to this subpart?

    Act means the Outer Continental Shelf Deep Water Royalty Relief Act, 
Pub. L. 104-58, 43 U.S.C. 1337(3).
    Eligible lease means a lease that:
    (1) Is issued as part of an OCS lease sale held after November 28, 
1995, and before November 28, 2000;
    (2) Is located in the Gulf of Mexico in water depths of 200 meters 
or deeper;
    (3) Lies wholly west of 87 degrees, 30 minutes West longitude; and
    (4) Is offered subject to a royalty suspension volume.
    Field means an area consisting of a single reservoir or multiple 
reservoirs all grouped on, or related to, the same general geological 
structural feature

[[Page 536]]

and/or stratigraphic trapping condition. Two or more reservoirs may be 
in a field, separated vertically by intervening impervious strata, or 
laterally by local geologic barriers, or by both.
    Highest responsible qualified bidder means a person who has met the 
appropriate requirements of 30 CFR part 256, subpart G of this title, 
and has submitted a bid higher than any other bids by qualified bidders 
on the same tract.
    Highest royalty rate means the highest percent rate payable to the 
United States, as specified in the lease, in the amount or value of the 
production saved, removed, or sold.
    Lease period means the time from lease issuance until 
relinquishment, expiration, or termination.
    Lowest royalty rate means the lowest percent rate payable to the 
United States, as specified in the lease, in the amount or value of the 
production saved, removed, or sold.
    OCS lease sale means the Department of the Interior (DOI) proceeding 
by which leases for certain OCS tracts are offered for sale by 
competitive bidding and during which bids are received, announced, and 
recorded.
    Pre-Act lease means a lease that:
    (1) Is issued as part of an OCS lease sale held before November 28, 
1995;
    (2) Is located in the Gulf of Mexico in water depths of 200 meters 
or deeper; and
    (3) Lies wholly west of 87 degrees, 30 minutes West longitude. (See 
part 203 of this title.)
    Production period means the period during which the amount of oil 
and gas produced from a tract (or, if the tract is unitized, the amount 
of oil and gas as allocated under a unitization formula) will be 
measured for purposes of determining the amount of royalty payable to 
the United States
    Qualified bidder means a person who has met the appropriate 
requirements of 30 CFR part 256, subpart G of this title.
    Royalty rate means the percentage of the amount or value of the 
production saved, removed, or sold that is due and payable to the United 
States Government.
    Royalty suspension (RS) lease means a lease that:
    (1) Is issued as part of an OCS lease sale held after November 28, 
2000;
    (2) Is in locations or planning areas specified in a particular 
Notice of OCS Lease Sale; and
    (3) Is offered subject to a royalty suspension specified in a Notice 
of OCS Lease Sale published in the Federal Register.
    Tract means a designation assigned solely for administrative 
purposes to a block or combination of blocks that are identified by a 
leasing map or an official protraction diagram prepared by the DOI.
    Value of production means the value of all oil and gas production 
saved, removed, or sold from a tract (or, if the tract is unitized, the 
value of all oil and gas production saved, removed, or sold and credited 
to the tract under a unitization formula) during a period of production. 
The value of production is determined under part 206 of this title.

[66 FR 11518, Feb. 23, 2001, as amended at 72 FR 25202, May 4, 2007]



Sec. 260.110  What bidding systems may MMS use?

    We will apply a single bidding system selected from those listed in 
this section to each tract included in an OCS lease sale. The following 
table lists bidding systems, the bid variables, and characteristics.

----------------------------------------------------------------------------------------------------------------
        For the bidding system--                The bid variable is the--         And the characteristics are--
----------------------------------------------------------------------------------------------------------------
(a) Cash bonus bid with a fixed royalty   Cash bonus..........................  The highest responsible
 rate of not less than 12.5 percent.                                             qualified bidder will pay a
                                                                                 royalty rate of not less than
                                                                                 12.5 percent at the beginning
                                                                                 of the lease period. We will
                                                                                 specify the royalty rate for
                                                                                 each tract offered in the
                                                                                 Notice of OCS Lease Sale
                                                                                 published in the Federal
                                                                                 Register.
----------------------------------------------------------------------------------------------------------------
(b) Royalty rate bid with fixed cash      Royalty rate........................  We will specify the fixed amount
 bonus.                                                                          of cash bonus the highest
                                                                                 responsible qualified bidder
                                                                                 must pay in the Notice of OCS
                                                                                 Lease Sale published in the
                                                                                 Federal Register.
----------------------------------------------------------------------------------------------------------------

[[Page 537]]

 
(c) Cash bonus bid with a sliding         Cash bonus..........................  (1) We will calculate the
 royalty rate of not less than 12.5                                              royalty rate the highest
 percent at the beginning of the lease                                           responsible qualified bidder
 period.                                                                         must pay using either:
                                                                                (i) A sliding-scale formula,
                                                                                 which relates the royalty rate
                                                                                 to the adjusted value or volume
                                                                                 of production, or
                                                                                (ii) A schedule that establishes
                                                                                 the royalty rate that we will
                                                                                 apply to specified ranges of
                                                                                 the adjusted value or volume of
                                                                                 production.
                                                                                (2) We will determine the
                                                                                 adjusted value of production by
                                                                                 applying an inflation factor to
                                                                                 the actual value of production.
                                                                                (3) If you are the successful
                                                                                 high bidder, your lease will
                                                                                 include the sliding-scale
                                                                                 formula or schedule and will
                                                                                 specify the lowest and highest
                                                                                 royalty rates that will apply.
                                                                                (4) You will pay a royalty rate
                                                                                 of not less than 12.5 percent
                                                                                 at the beginning of the lease
                                                                                 period.
                                                                                (5) We will include the sliding-
                                                                                 scale royalty formula or
                                                                                 schedule, inflation factor and
                                                                                 procedures for making the
                                                                                 inflation adjustment and
                                                                                 determining the value or amount
                                                                                 of production in the Notice of
                                                                                 OCS Lease Sale published in the
                                                                                 Federal Register.
----------------------------------------------------------------------------------------------------------------
(d) Cash bonus bid with fixed share of    Cash bonus..........................  (1) If we award you a lease as
 the net profits of no less than 30                                              the highest responsible
 percent.                                                                        qualified bidder, you will
                                                                                 determine the amount of the net
                                                                                 profit share payment to the
                                                                                 United States for each month by
                                                                                 multiplying the net profit
                                                                                 share base times the net profit
                                                                                 share rate, according to Sec.
                                                                                 220.022. You will calculate the
                                                                                 net profit share base according
                                                                                 to Sec.  220.021.
                                                                                (2) You will pay a net profit
                                                                                 share of not less than 30
                                                                                 percent.
                                                                                (3) We will specify the capital
                                                                                 recovery factor, as described
                                                                                 in Sec.  220.020, and the net
                                                                                 profit share rate, both of
                                                                                 which may vary from tract to
                                                                                 tract, in the Notice of OCS
                                                                                 Lease Sale published in the
                                                                                 Federal Register.
----------------------------------------------------------------------------------------------------------------
(e) Cash bonus with variable royalty      Cash bonus..........................  (1) We may suspend or defer
 rate(s) during one or more periods of                                           royalty for a period, volume,
 production.                                                                     or value of production.
                                                                                 Notwithstanding suspensions or
                                                                                 deferrals, we may impose a
                                                                                 minimum royalty. The
                                                                                 suspensions or deferrals may
                                                                                 vary based on prices or price
                                                                                 changes of oil and/or gas.
                                                                                (2) You may pay a royalty rate
                                                                                 less than 12.5 percent on
                                                                                 production but not less than
                                                                                 zero percent.
                                                                                (3) We will specify the
                                                                                 applicable royalty rates(s) and
                                                                                 suspension or deferral
                                                                                 magnitudes, formulas, or
                                                                                 relationships in the Notice of
                                                                                 OCS Lease Sale published in the
                                                                                 Federal Register.
----------------------------------------------------------------------------------------------------------------
(f) Cash bonus with royalty rate(s)       Cash bonus..........................  We will base the royalty rate on
 based on formula(s) or schedule(s)                                              formula(s) or schedule(s)
 during one or more periods of                                                   specified in the Notice of OCS
 production.                                                                     Lease Sale published in the
                                                                                 Federal Register.
----------------------------------------------------------------------------------------------------------------
(g) Cash bonus with a fixed royalty rate  Cash bonus..........................  Except for periods of royalty
 of not less than 12.5 percent, at the                                           suspension, you will pay a
 beginning of the lease period,                                                  fixed royalty rate of not less
 suspension of royalties for a period,                                           than 12.5 percent. If we award
 volume, or value of production, or                                              to you a lease under this
 depending upon selected characteristics                                         system, you must calculate the
 of extraction, and with suspensions                                             royalty due during the
 that may vary based on the price of                                             designated period using the
 production.                                                                     rate, formula, or schedule
                                                                                 specified in the lease. We will
                                                                                 specify the royalty rate,
                                                                                 formula, or schedule in the
                                                                                 Notice of OCS Lease Sale
                                                                                 published in the Federal
                                                                                 Register.
----------------------------------------------------------------------------------------------------------------



Sec. 260.111  What conditions apply to the bidding systems that MMS uses?

    (a) For each of the bidding systems in Sec. 260.110, we will 
include an annual rental fee. Other fees and provisions may apply as 
well. The Notice of OCS Lease Sale published in the Federal Register 
will specify the annual rental and any other fees the highest 
responsible qualified bidder must pay and any other provisions.
    (b) If we use any deferment or schedule of payments for the cash 
bonus bid, we will specify and include it in the Notice of OCS Lease 
Sale published in the Federal Register.

[[Page 538]]

    (c) For the bidding systems listed in this subpart, if the bid 
variable is a cash bonus bid, the highest bid by a qualified bidder 
determines the amount of cash bonus to be paid. We will include the 
minimum bid level(s) in the Notice of OCS Lease Sale published in the 
Federal Register.
    (d) For the bidding systems listed in this subpart, if the bid 
variable is the royalty rate, the highest bid by a qualified bidder 
determines the royalty rate to be paid. We will include the minimum 
royalty rate(s) in the Notice of OCS Lease Sale published in the Federal 
Register.
    (e) We may, by rule, add to or modify the bidding systems listed in 
Sec. 260.110, according to the procedural requirements of the OCSLA, 43 
U.S.C. 1331 et seq., as amended by Public Law 95-372, 92 Stat. 629.

                             Eligible Leases



Sec. 260.112  How do royalty suspension volumes apply to eligible leases?

    Royalty suspension volumes, as specified in section 304 of the Act, 
apply to eligible leases that meet the criteria in Sec. 260.113. For 
purposes of this section and Sec. Sec. 260.113 through 260.117:
    (a) Any volumes of production that are not normally royalty-bearing 
under the lease or the regulations (e.g., fuel gas) do not count against 
royalty suspension volumes; and
    (b) Production includes volumes allocated to a lease under an 
approved unit agreement.



Sec. 260.113  When does an eligible lease qualify for a royalty suspension 

volume?

    (a) Your eligible lease may receive a royalty suspension volume only 
if it is in a field where no current lease produced oil or gas (other 
than test production) before November 28, 1995. For eligible leases, the 
bidding system in Sec. 260.110(g) applies only to leases in fields that 
meet this condition.
    (b) You may receive a royalty suspension volume only if your entire 
lease is west of 87 degrees, 30 minutes West longitude. A field that 
lies on both sides of that meridian will receive a royalty suspension 
volume only for those eligible leases lying entirely west of the 
meridian.



Sec. 260.114  How does MMS assign and monitor royalty suspension volumes for 

eligible leases?

    (a) We will assign your lease that has a qualifying well (under part 
250, subpart A of this title) to an existing field or designate a new 
field and will notify you and other affected lessees and operating 
rights holders in the field of that assignment.
    (1) Within 15 days of that notification, you or any of the other 
affected lessees or operating rights holders may file a written request 
with the Director of MMS (Director) for reconsideration accompanied by a 
``Statement of Reasons.''
    (2) The Director will respond in writing either affirming or 
reversing the assignment decision. The Director's decision is the final 
action of the Department of the Interior and is not subject to appeal to 
the Interior Board of Land Appeals under part 290 of this title and 43 
CFR part 4.
    (b) We have specified the water depth for each eligible lease in the 
final Notice of OCS Lease Sale. Our determination of water depth for 
each lease is final once we issue the lease. We have specified in the 
Notice the royalty suspension volume applicable to each water depth. The 
minimum royalty suspension volumes for fields in million barrels of oil 
equivalent (MMBOE) are shown in the following table:

------------------------------------------------------------------------
                                             Minimum royalty suspension
               Water depth                             volume
------------------------------------------------------------------------
(1) 200 to 400 meters....................  17.5 MMBOE
(2) 400 to 800 meters....................  52.5 MMBOE
(3) 800 meters or more...................  87.5 MMBOE
------------------------------------------------------------------------

    (c) Before commencing production, you must:
    (1) Notify the MMS Regional Supervisor for Production and 
Development of your intention to start production; and
    (2) Request confirmation of the size of the royalty suspension 
volume that applies to your eligible lease.
    (d) When production (other than test production) first occurs from 
any of the eligible leases in a field, we will determine what royalty 
suspension volume applies to the lease(s) in that

[[Page 539]]

field. We base the determination for eligible lease(s) on the royalty 
suspension volumes specified in paragraph (b) of this section and the 
water depths of eligible leases specified in Sec. 260.117(a).
    (e) Your eligible lease may obtain more than one royalty suspension 
volume. If a new field is discovered on your eligible lease that already 
benefits from the royalty suspension volume from another field, 
production from that new field receives a separate royalty suspension.

[66 FR 11518, Feb. 23, 2001, as amended at 67 FR 57739, Sept. 12, 2002]



Sec. 260.115  How long will a royalty suspension volume for an eligible lease 

be effective?

    A royalty suspension volume for an eligible lease will continue 
through the end of the month in which cumulative production from the 
leases in a field entitled to share the royalty suspension volume 
reaches that volume or the lease period ends.



Sec. 260.116  How do I measure natural gas production on my eligible lease?

    You must measure natural gas production on your eligible lease 
subject to the royalty suspension volume as follows: 5.62 thousand cubic 
feet of natural gas, measured according to part 250, subpart L of this 
title, equals one barrel of oil equivalent.



Sec. 260.117  What other provisions apply to royalty suspension volumes for 

eligible leases?

    In addition to the provisions in Sec. Sec. 260.111 through 260.116, 
the provisions in this section apply to royalty suspension volumes on 
eligible leases.
    (a) If a new field consists of eligible leases in different water-
depth categories, the royalty suspension volume associated with the 
eligible lease in the deepest water applies.
    (b) If your eligible lease is the only eligible lease in a field, 
you do not owe royalty on the production from your lease up to the 
applicable royalty suspension volume.
    (c) If a field consists of more than one eligible lease:
    (1) Payment of royalties on the eligible leases' initial production 
is suspended until cumulative production equals the field's established 
royalty suspension volume;
    (2) Only production from leases entitled to share in the field's 
royalty suspension volume counts as part of this cumulative production; 
and
    (3) The royalty suspension volume for each eligible lease is equal 
to each lease's actual production (or production allocated under an 
approved unit agreement) until the field's royalty suspension volume is 
reached.
    (d) This paragraph applies if we add an eligible lease to a field 
that has an established royalty suspension volume that we approved under 
part 203 of this title. This paragraph also applies to a field that has 
an established royalty suspension volume as a result of production 
starting from one or more eligible leases in the field. In situations 
covered by this paragraph:
    (1) The field's royalty suspension volume will not change, even if 
the added lease is in deeper water;
    (2) If we granted a royalty suspension volume under part 203 of this 
title that is larger than the minimum specified for that water depth, 
the added eligible lease may share in the larger suspension volume;
    (3) The eligible lease may receive a royalty suspension volume only 
to the extent of its production before the cumulative production equals 
the field's previously established royalty suspension volume; and
    (4) Only production from leases entitled to share in the field's 
previously established royalty suspension volume counts as part of this 
cumulative production.
    (e) A pre-Act lease may receive a royalty suspension volume under 
part 203 of this title for a field that already has a royalty suspension 
volume due to eligible leases. If this happens, then:
    (1) The eligible and pre-Act leases share a single royalty 
suspension volume;
    (2) The field's royalty suspension volume is the larger of the 
volume for the eligible leases or the volume MMS grants in response to 
the pre-Act leases' application; and
    (3) The suspension volume for each eligible lease is its actual 
production

[[Page 540]]

from the lease until cumulative production from all leases in the field 
entitled to share in the field-based suspension volume equals the 
suspension volume.
    (f) If we reassign a well on an eligible lease to another field, the 
past production from that well:
    (1) Will count toward the royalty suspension volume, if any, 
specified for the field to which it is reassigned; and
    (2) Will not count toward the royalty suspension volume, if any, for 
the field from which it was reassigned.

                     Royalty Suspension (RS) Leases



Sec. 260.120  How does royalty suspension apply to leases issued in a sale 

held after November 2000?

    We may issue leases with suspension of royalties for a period, 
volume or value of production, as authorized in section 303 of the Act. 
For purposes of this section and Sec. Sec. 260.121 through 260.124:
    (a) Any volumes of production that are not normally royalty-bearing 
under the lease or the regulations (e.g., fuel gas) do not count against 
royalty suspension volumes; and
    (b) Production includes volumes allocated to a lease under an 
approved unit agreement.



Sec. 260.121  When does a lease issued in a sale held after November 2000 get 

a royalty suspension?

    (a) We will specify any royalty suspension for your RS lease in the 
Notice of OCS Lease Sale published in the Federal Register for the sale 
in which you acquire the RS lease and will repeat it in the lease 
document. In addition:
    (1) Your RS lease may produce royalty-free the royalty suspension we 
specify for your lease, even if the field to which we assign it is 
producing.
    (2) The royalty suspension we specify in the Notice of OCS Lease 
Sale for your lease does not apply to any other leases in the field to 
which we assign your RS lease.
    (b) You may apply for a supplemental royalty suspension for a 
project under part 203 of this title, if your lease lies:
    (1) In the Gulf of Mexico,
    (2) In water 200 meters or deeper, and
    (3) Wholly west of 87 degrees, 30 minutes West longitude.
    (c) Your RS lease retains the royalty suspension with which we 
issued it even if we deny your application for more relief.



Sec. 260.122  How long will a royalty suspension volume be effective for a 

lease issued in a sale held after November 2000?

    (a) The royalty suspension volume for your RS lease will continue 
through the end of the month in which cumulative production from your 
lease reaches the applicable royalty suspension volume or the lease 
period ends.
    (b)(1) Notwithstanding any royalty suspension under this subpart, 
you must pay royalty at the lease stipulated rate on:
    (i) Any oil produced for any period stipulated in the lease during 
which the arithmetic average of the daily closing prices on the New York 
Mercantile Exchange (NYMEX) for light sweet crude oil exceeds a 
threshold price stipulated in the lease, or
    (ii) Any natural gas produced for any period stipulated in the lease 
during which the arithmetic average of the daily closing prices on the 
NYMEX for natural gas exceeds a threshold price stipulated in the lease.
    (2) You must pay any royalty due under this paragraph, plus late 
payment interest under Sec. 218.54 of this title, no later than 90 days 
after the end of the period for which royalty is owed.
    (3) Any production on which you must pay royalty under this 
paragraph will count toward the production volume determined under 
Sec. Sec. 260.120 through 260.124.
    (c) If you must pay royalty on any product (either oil or natural 
gas) for any period under paragraph (b), you must continue to pay 
royalty on that product during the next succeeding period of the same 
length until the arithmetic average of the daily closing NYMEX prices 
for that product for that period can be determined. If the arithmetic 
average of the daily closing prices for that product for that period is 
less than the threshold price stipulated in the lease, you are entitled 
to a credit or refund of royalties paid for

[[Page 541]]

that period with interest under applicable law.
    (d) MMS will adjust the threshold oil and gas prices referred to in 
paragraph (b) for any period stipulated in the lease by the percentage, 
if any, by which the implicit price deflator for the gross domestic 
product changed during the preceding period.



Sec. 260.123  How do I measure natural gas production for a lease issued in a 

sale held after November 2000?

    You must measure natural gas production subject to the royalty 
suspension volume for your lease as follows: 5.62 thousand cubic feet of 
natural gas, measured according to part 250, subpart L of this title, 
equals one barrel of oil equivalent.



Sec. 260.124  How will royalty suspension apply if MMS assigns a lease issued 

in a sale held after November 2000 to a field that has an eligible or pre-Act 

lease?

    (a) We will assign your lease that has a qualifying well (under part 
250, subpart A of this title) to an existing field or designate a new 
field and will notify you and other affected lessees and operating 
rights holders in the field of that assignment.
    (1) Within 15 days of the final notification, you or any of the 
other affected lessees or operating rights holders may file a written 
request with the Director for reconsideration, accompanied by a 
Statement of Reasons.
    (2) The Director will respond in writing either affirming or 
reversing the assignment decision. The Director's decision is the final 
action of the Department of the Interior and is not subject to appeal to 
the Interior Board of Land Appeals under part 290 of this title and 43 
CFR part 4.
    (b) If we establish a royalty suspension volume for a field, either 
as a result of an approved application for royalty relief submitted for 
a pre-Act lease under part 203 of this title or as the result of 
production starting from one or more eligible leases in the field, then:
    (1) Royalty-free production from your RS lease shares from and 
counts as part of any royalty suspension volume under Sec. 260.114(d) 
for the field to which we assign your lease; and
    (2) Your RS lease may continue to produce royalty-free up to the 
royalty suspension we specified for your lease, even if the field to 
which we assign your RS lease has produced all of its royalty suspension 
volume.
    (c) Your lease may share in a suspension volume larger than the 
royalty suspension with which we issued it and to the extent we grant a 
larger volume in response to an application by a pre-Act lease submitted 
under part 203 of this title. To share in any larger royalty suspension 
volume, you must file an application described in Sec. Sec. 203.71 and 
203.83. In no case will royalty-free production for your RS lease be 
less than the royalty suspension specified for your lease.

[66 FR 11518, Feb. 23, 2001, as amended at 67 FR 57739, Sept. 12, 2002]

                    Bidding System Selection Criteria



Sec. 260.130  What criteria does MMS use for selecting bidding systems and 

bidding system components?

    In analyzing the application of one of the bidding systems listed in 
Sec. 260.110 to tracts selected for any OCS lease sale, we may, at our 
discretion, consider the following purposes and policies. We recognize 
that each of the purposes and policies may not be specifically 
applicable to the selection process for a particular bidding system or 
tract, or may present a conflict that we will have to resolve in the 
process of bidding system selection. The order of listing does not 
denote a ranking.
    (a) Providing fair return to the Federal Government;
    (b) Increasing competition;
    (c) Ensuring competent and safe operations;
    (d) Avoiding undue speculation;
    (e) Avoiding unnecessary delays in exploration, development, and 
production;
    (f) Discovering and recovering oil and gas;
    (g) Developing new oil and gas resources in an efficient and timely 
manner;
    (h) Limiting the administrative burdens on Government and industry; 
and
    (i) Providing an opportunity to experiment with various bidding 
systems

[[Page 542]]

to enable us to identify those most appropriate for the satisfaction of 
the objectives of the United States in OCS lease sales.

Subpart C [Reserved]



                         Subpart D_Joint Bidding



Sec. 260.301  What is the purpose of this subpart?

    The purpose of this subpart is to encourage participation in OCS oil 
and gas lease sales by limiting the requirement for filing ``Statements 
of Production'' to certain joint bidders.



Sec. 260.302  What definitions apply to this subpart?

    For the purposes of this subpart, all terms used are defined as in 
Sec. 256.40 of this title.



Sec. 260.303  What are the joint bidding requirements?

    (a) You must file a Statement of Production with the Director, 
according to the requirements of Sec. Sec. 256.38 through 256.44 of 
this title if:
    (1) You submit a joint bid for any OCS oil and gas lease during a 6-
month bidding period; and
    (2) You were chargeable for the prior production period with an 
average daily production from all sources in excess of 1.6 million 
barrels of crude oil, natural gas equivalents, and liquefied petroleum 
products.
    (b) The Statement of Production that you file under paragraph (a) of 
this section must state that you are chargeable for the prior production 
period with an average daily production in excess of the quantities 
listed in paragraph (a) of this section.
    (c) If your average daily production in the prior production period 
met or exceeded the quantities specified in paragraph (a) of this 
section, you may not submit a joint bid for any OCS oil and gas lease 
during the applicable 6-month bidding period with any other person 
similarly chargeable. We will disqualify and reject these bids.
    (d) If your average daily production in the prior production period 
met or exceeded the quantities specified in paragraph (a) of this 
section, you may not enter into an agreement prior to a lease sale that 
would result in two or more persons, similarly chargeable, acquiring or 
holding any interest in the tract for which the bid is submitted. We 
will disqualify and reject these bids.



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 543]]

    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 Sec. Sec. 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 ON THE 

OUTER CONTINENTAL SHELF--Table of Contents




                      Subpart A_General Information

Sec.
280.1 What definitions apply to this part?
280.2 What is the purpose of this part?

[[Page 544]]

280.3 What requirements must I follow when I conduct prospecting or 
          research activities?
280.4 What activities are not covered by this part?

          Subpart B_How To Apply for a Permit or File a Notice

280.10 What must I do before I may conduct prospecting activities?
280.11 What must I do before I may conduct scientific research?
280.12 What must I include in my application or notification?
280.13 Where must I send my application or notification?

                  Subpart C_Obligations Under This Part

                      Prohibitions and Requirements

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

                         Interrupted Activities

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

                          Environmental Issues

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

                          Penalties and Appeals

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

                       Subpart D_Data Requirements

                     Geological Data and Information

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

                    Geophysical Data and Information

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

                              Reimbursement

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

                               Protections

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

                    Subpart E_Information Collection

280.80 Paperwork Reduction Act statement--information collection.

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

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



                      Subpart A_General Information



Sec. 280.1  What definitions apply to this part?

    Definitions in this part have the following meaning:
    Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
    Adjacent State means with respect to any activity proposed, 
conducted, or approved under this part, any coastal State(s):
    (l) That is used, or is scheduled to be used, as a support base for 
geological and geophysical (G&G) prospecting or scientific research 
activities; or
    (2) In which there is a reasonable probability of significant effect 
on land or water uses from such activity.
    Analyzed geological information means data collected under a permit 
or a lease that have been analyzed. Some examples of analysis include, 
but are not limited to, identification of lithologic

[[Page 545]]

and fossil content, core analyses, laboratory analyses of physical and 
chemical properties, well logs or charts, results from formation fluid 
tests, and descriptions of mineral occurrences or hazardous conditions.
    Archaeological interest means capable of providing scientific or 
humanistic understandings of past human behavior, cultural adaptation, 
and related topics through the application of scientific or scholarly 
techniques, such as controlled observation, contextual measurement, 
controlled collection, analysis, interpretation, and explanation.
    Archaeological resource means any material remains of human life or 
activities that are at least 50 years of age and are of archaeological 
interest.
    Coastal environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the terrestrial ecosystem 
from the shoreline inward to the boundaries of the coastal zone.
    Coastal zone means the coastal waters (including the lands therein 
and thereunder) and the adjacent shorelands (including the waters 
therein and thereunder) that are strongly influenced by each other and 
in proximity to the shorelands of the several coastal States. The 
coastal zone includes islands, transition and intertidal areas, salt 
marshes, wetlands, and beaches. The coastal zone extends seaward to the 
outer limit of the United States territorial sea and extends inland from 
the shorelines to the extent necessary to control shorelands, the uses 
of which have a direct and significant impact on the coastal waters, and 
the inward boundaries of which may be identified by the several coastal 
States, under the authority in section 305(b)(1) of the Coastal Zone 
Management Act of 1972.
    Coastal Zone Management Act means the Coastal Zone Management Act of 
1972, as amended (16 U.S.C. 1451 et seq.).
    Data means facts and statistics, measurements, or samples that have 
not been analyzed, processed, or interpreted.
    Deep stratigraphic test means drilling that involves the penetration 
into the sea bottom of more than 500 feet (152 meters).
    Director means the Director of the Minerals Management Service, U.S. 
Department of the Interior, or an official authorized to act on the 
Director's behalf.
    Geological data and information means data and information gathered 
through or derived from geological and geochemical techniques, e.g., 
coring and test drilling, well logging, bottom sampling, or other 
physical sampling or chemical testing process.
    Geological and geophysical (G&G) prospecting activities means the 
commercial search for mineral resources other than oil, gas, or sulphur. 
Activities classified as prospecting include, but are not limited to:
    (1) Geological and geophysical marine and airborne surveys where 
magnetic, gravity, seismic reflection, seismic refraction, or the 
gathering through coring or other geological samples are used to detect 
or imply the presence of hard minerals; and
    (2) Any drilling, whether on or off a geological structure.
    Geological and geophysical (G&G) scientific research activities 
means any investigations related to hard minerals that are conducted on 
the OCS for academic or scientific research. These investigations would 
involve gathering and analyzing geological, geochemical, or geophysical 
data and information that are made available to the public for 
inspection and reproduction at the earliest practical time. The term 
does not include commercial G&G exploration or commercial G&G 
prospecting activities.
    Geological sample means a collected portion of the seabed, the 
subseabed, or the overlying waters acquired while conducting prospecting 
or scientific research activities.
    Geophysical data and information means any data or information 
gathered through or derived from geophysical measurement or sensing 
techniques (e.g., gravity, magnetic, or seismic).
    Governor means the Governor of a State or the person or entity 
lawfully designated by or under State law to exercise the powers granted 
to a Governor under the Act.

[[Page 546]]

    Hard minerals means any minerals found on or below the surface of 
the seabed except for oil, gas, or sulphur.
    Interpreted geological information means the knowledge, often in the 
form of schematic cross sections, 3-dimensional representations, and 
maps, developed by determining the geological significance of geological 
data and analyzed and processed geologic information.
    Interpreted geophysical information means knowledge, often in the 
form of seismic cross sections, 3-dimensional representations, and maps, 
developed by determining the geological significance of geophysical data 
and processed geophysical information.
    Lease means, depending upon the requirements of the context, either:
    (1) An agreement issued under section 8 or maintained under section 
6 of the Act that authorizes mineral exploration, development and 
production; or
    (2) The area covered by an agreement specified in paragraph (1) of 
this definition.
    Material remains means physical evidence of human habitation, 
occupation, use, or activity, including the site, location, or context 
in which evidence is situated.
    Minerals means all minerals authorized by an Act of Congress to be 
produced from ``public lands'' as defined in section 103 of the Federal 
Land Policy and Management Act of 1976 (43 U.S.C. 1702). The term 
includes oil, gas, sulphur, geopressured-geothermal and associated 
resources.
    Notice means a written statement of intent to conduct G&G scientific 
research that is:
    (1) Related to hard minerals on the OCS; and
    (2) Not covered under a permit.
    Oil, gas, and sulphur means oil, gas, and sulphur, geopressured-
geothermal and associated resources, including gas hydrates.
    Outer Continental Shelf (OCS) means all submerged lands:
    (1) That lie seaward and outside of the area of lands beneath 
navigable waters as defined in section 2 of the Submerged Lands Act (43 
U.S.C. 1301); and
    (2) Whose subsoil and seabed belong to the United States and are 
subject to its jurisdiction and control.
    Permit means the contract or agreement, other than a lease, issued 
under this part. The permit gives a person the right, under appropriate 
statutes, regulations, and stipulations, to conduct on the OCS:
    (1) Geological prospecting for hard minerals;
    (2) Geophysical prospecting for hard minerals;
    (3) Geological scientific research; or
    (4) Geophysical scientific research.
    Permittee means the person authorized by a permit issued under this 
part to conduct activities on the OCS.
    Person means:
    (1) A citizen or national of the United States;
    (2) An alien lawfully admitted for permanent residence in the United 
States as defined in section 8 U.S.C. 1101(a)(20);
    (3) A private, public, or municipal corporation organized under the 
laws of the United States or of any State or territory thereof, and 
association of such citizens, nationals, resident aliens or private, 
public, or municipal corporations, States, or political subdivisions of 
States; or
    (4) Anyone operating in a manner provided for by treaty or other 
applicable international agreements. The term does not include Federal 
agencies.
    Processed geological or geophysical information means data collected 
under a permit and later processed or reprocessed.
    (1) Processing involves changing the form of data as to facilitate 
interpretation. Some examples of processing operations may include, but 
are not limited to:
    (i) Applying corrections for known perturbing causes;
    (ii) Rearranging or filtering data; and
    (iii) Combining or transforming data elements.
    (2) Reprocessing is the additional processing other than ordinary 
processing used in the general course of evaluation. Reprocessing 
operations may include varying identified parameters for the detailed 
study of a specific problem area.
    Secretary means the Secretary of the Interior or a subordinate 
authorized to act on the Secretary's behalf.

[[Page 547]]

    Shallow test drilling means drilling into the sea bottom to depths 
less than those specified in the definition of a deep stratigraphic 
test.
    Significant archaeological resource means those archaeological 
resources that meet the criteria of significance for eligibility of the 
National Register of Historic Places as defined in 36 CFR 60.4, or its 
successor.
    Third party means any person other than the permittee or a 
representative of the United States, including all persons who obtain 
data or information acquired under a permit from the permittee, or from 
another third party, by sale, trade, license agreement, or other means.
    You means a person who applies for and/or obtains a permit, or files 
a notice to conduct G&G prospecting or scientific research related to 
hard minerals on the OCS.



Sec. 280.2  What is the purpose of this part?

    The purpose of this part is to:
    (a) Allow you to conduct prospecting activities or scientific 
research activities on the OCS in Federal waters related to hard 
minerals on unleased lands or on lands under lease to a third party.
    (b) Ensure that you carry out prospecting activities or scientific 
research activities in a safe and environmentally sound manner so as to 
prevent harm or damage to, or waste of, any natural resources (including 
any hard minerals in areas leased or not leased), any life (including 
fish and other aquatic life), property, or the marine, coastal, or human 
environment.
    (c) Inform you and third parties of your legal and contractual 
obligations.
    (d) Inform you and third parties of:
    (1) The U.S. Government's rights to access G&G data and information 
collected under permit on the OCS;
    (2) Reimbursement we will make for data and information that are 
submitted; and
    (3) The proprietary terms of data and information that we retain.



Sec. 280.3  What requirements must I follow when I conduct prospecting or 

research activities?

    You must conduct G&G prospecting activities or scientific research 
activities under this part according to:
    (a) The Act;
    (b) The regulations in this part;
    (c) Orders of the Director/Regional Director (RD); and
    (d) Other applicable statutes, regulations, and amendments.



Sec. 280.4  What activities are not covered by this part?

    This part does not apply to:
    (a) G&G prospecting activities conducted by, or on behalf of, the 
lessee on a lease on the OCS;
    (b) Federal agencies;
    (c) Postlease activities for mineral resources other than oil, gas, 
and sulphur, which are covered by regulations at 30 CFR part 282; and
    (d) G&G exploration or G&G scientific research activities related to 
oil, gas, and sulphur, including gas hydrates, which are covered by 
regulations at 30 CFR part 251.



          Subpart B_How To Apply for a Permit or File a Notice



Sec. 280.10  What must I do before I may conduct prospecting activities?

    You must have an MMS-approved permit to conduct G&G prospecting 
activities, including deep stratigraphic tests, for hard minerals. If 
you conduct both G&G prospecting activities, you must have a separate 
permit for each.



Sec. 280.11  What must I do before I may conduct scientific research?

    You may conduct G&G scientific research activities related to hard 
minerals on the OCS only after you obtain an MMS-approved permit or file 
a notice.
    (a) Permit. You must obtain a permit if the research activities you 
want to conduct involve:
    (1) Using solid or liquid explosives;
    (2) Drilling a deep stratigraphic test; or
    (3) Developing data and information for proprietary use or sale.

[[Page 548]]

    (b) Notice. If you conduct research activities (including federally-
funded research) not covered by paragraph (a) of this section, you must 
file a notice with the regional director at least 30 days before you 
begin. If you cannot file a 30-day notice, you must provide oral 
notification before you begin and follow up in writing. You must also 
inform MMS in writing when you conclude your work.



Sec. 280.12  What must I include in my application or notification?

    (a) Permits. You must submit to the Regional Director a signed 
original and three copies of the permit application form (Form MMS-134) 
at least 30 days before the startup date for activities in the permit 
area. If unusual circumstances prevent you from meeting this deadline, 
you must immediately contact the Regional Director to arrange an 
acceptable deadline. The form includes names of persons, type, location, 
purpose, and dates of activity, as well as environmental and other 
information. A nonrefundable service fee of $1,900 must accompany your 
application.
    (b) Disapproval of permit application. If we disapprove your 
application for a permit, the RD will explain the reasons for the 
disapproval and what you must do to obtain approval.
    (c) Notices. You must sign and date a notice that includes:
    (1) The name(s) of the person(s) who will conduct the proposed 
research;
    (2) The name(s) of any other person(s) participating in the proposed 
research, including the sponsor;
    (3) The type of research and a brief description of how you will 
conduct it;
    (4) A map, plat, or chart, that shows the location where you will 
conduct research;
    (5) The proposed projected starting and ending dates for your 
research activity;
    (6) The name, registry number, registered owner, and port of 
registry of vessels used in the operation;
    (7) The earliest practical time you expect to make the data and 
information resulting from your research activity available to the 
public;
    (8) Your plan of how you will make the data and information you 
collect available to the public;
    (9) A statement that you and others involved will not sell or 
withhold the data and information resulting from your research; and
    (10) At your option, the nonexclusive use agreement for scientific 
research attachment to form MMS-134. (If you submit this agreement, you 
do not have to submit the material required in paragraphs (c)(7), 
(c)(8), and (c)(9) of this section.)

[67 FR 46858, July 17, 2002, as amended at 71 FR 40914, July 19, 2006]



Sec. 280.13  Where must I send my application or notification?

    You must apply for a permit or file a notice at one of the following 
locations:

------------------------------------------------------------------------
  For the OCS off the * * *                  Apply to * * *
------------------------------------------------------------------------
(1) State of Alaska..........  Regional Supervisor for Resource
                                Evaluation, Minerals Management Service,
                                Alaska OCS Region, 949 East 36th Avenue,
                                Anchorage, AK 99508-4363.
(2) Atlantic Coast, Gulf of    Regional Supervisor for Resource
 Mexico, Puerto Rico, or U.S.   Evaluation, Minerals Management Service,
 territories in the Caribbean   Gulf of Mexico OCS Region, 1201 Elmwood
 Sea.                           Park Boulevard, New Orleans, LA 70123-
                                2394.
(3) States of California,      Regional Supervisor for Resource
 Oregon, Washington, Hawaii,    Evaluation, Minerals Management Service,
 or U.S. territories in the     Pacific OCS Region, 770 Paseo Camarillo,
 Pacific Ocean.                 Camarillo, CA 93010-6064.
------------------------------------------------------------------------


[[Page 549]]



                  Subpart C_Obligations Under This Part

                      Prohibitions and Requirements



Sec. 280.20  What must I not do in conducting Geological and Geophysical 

(G&G) prospecting or scientific research?

    While conducting G&G prospecting or scientific research activities 
under a permit or notice, you must not:
    (a) Interfere with or endanger operations under any lease, right-of-
way, easement, right-of-use, notice, or permit issued or maintained 
under the Act;
    (b) Cause harm or damage to life (including fish and other aquatic 
life), property, or the marine, coastal, or human environment;
    (c) Cause harm or damage to any mineral resources (in areas leased 
or not leased);
    (d) Cause pollution;
    (e) Disturb archaeological resources;
    (f) Create hazardous or unsafe conditions;
    (g) Unreasonably interfere with or cause harm to other uses of the 
area; or
    (h) Claim any oil, gas, sulphur, or other minerals you discover 
while conducting operations under a permit or notice.



Sec. 280.21  What must I do in conducting G&G prospecting or scientific 

research?

    While conducting G&G prospecting or scientific research activities 
under a permit or notice, you must:
    (a) Immediately report to the RD if you:
    (1) Detect hydrocarbon or any other mineral occurrences;
    (2) Detect environmental hazards that imminently threaten life and 
property; or
    (3) Adversely affect the environment, aquatic life, archaeological 
resources, or other uses of the area where you are prospecting or 
conducting scientific research activities.
    (b) Consult and coordinate your G&G activities with other users of 
the area for navigation and safety purposes.
    (c) If you conduct shallow test drilling or deep stratigraphic test 
drilling activities, you must use the best available and safest 
technologies that the RD considers economically feasible.



Sec. 280.22  What must I do when seeking approval for modifications?

    Before you begin modified operations, you must submit a written 
request describing the modifications and receive the RD's oral or 
written approval. If circumstances preclude a written request, you must 
make an oral request and follow up in writing.



Sec. 280.23  How must I cooperate with inspection activities?

    (a) You must allow our representatives to inspect your G&G 
prospecting or any scientific research activities that are being 
conducted under a permit. They will determine whether operations are 
adversely affecting the environment, aquatic life, archaeological 
resources, or other uses of the area.
    (b) MMS will reimburse you for food, quarters, and transportation 
that you provide for our representatives if you send in your 
reimbursement request to the region that issued the permit within 90 
days of the inspection.



Sec. 280.24  What reports must I file?

    (a) You must submit status reports on a schedule specified in the 
permit and include a daily log of operations.
    (b) You must submit a final report of G&G prospecting or scientific 
research activities under a permit within 30 days after you complete 
acquisition activities under the permit. You may combine the final 
report with the last status report and must include each of the 
following:
    (1) A description of the work performed.
    (2) Charts, maps, plats and digital navigation data in a format 
specified by the RD, showing the areas and blocks in which any G&G 
prospecting or permitted scientific research activities were conducted. 
Identify the lines of geophysical traverses and their locations 
including a reference sufficient to identify the data produced during 
each activity.
    (3) The dates on which you conducted the actual prospecting or 
scientific research activities.
    (4) A summary of any:

[[Page 550]]

    (i) Hard mineral, hydrocarbon, or sulphur occurrences encountered;
    (ii) Environmental hazards; and
    (iii) Adverse effects of the G&G prospecting or scientific research 
activities on the environment, aquatic life, archaeological resources, 
or other uses of the area in which the activities were conducted.
    (5) Other descriptions of the activities conducted as specified by 
the RD.

                         Interrupted Activities



Sec. 280.25  When may MMS require me to stop activities under this part?

    (a) We may temporarily stop prospecting or scientific research 
activities under a permit when the RD determines that:
    (1) Activities pose a threat of serious, irreparable, or immediate 
harm. This includes damage to life (including fish and other aquatic 
life), property, and any minerals (in areas leased or not leased), to 
the marine, coastal, or human environment, or to an archaeological 
resource;
    (2) You failed to comply with any applicable law, regulation, order 
or provision of the permit. This would include our required submission 
of reports, well records or logs, and G&G data and information within 
the time specified; or
    (3) Stopping the activities is in the interest of national security 
or defense.
    (b) The RD will advise you either orally or in writing of the 
procedures to temporarily stop activities. We will confirm an oral 
notification in writing and deliver all written notifications by courier 
or certified/registered mail. You must stop all activities under a 
permit as soon as you receive an oral or written notification.



Sec. 280.26  When may I resume activities?

    The RD will advise you when you may start your permit activities 
again.



Sec. 280.27  When may MMS cancel my permit?

    The RD may cancel a permit at any time.
    (a) If we cancel your permit, the RD will advise you by certified or 
registered mail 30 days before the cancellation date and will state the 
reason.
    (b) After we cancel your permit, you are still responsible for 
proper abandonment of any drill site according to the requirements of 30 
CFR 251.7(b)(8). You must comply with all other obligations specified in 
this part or in the permit.



Sec. 280.28  May I relinquish my permit?

    (a) You may relinquish your permit at any time by advising the RD by 
certified or registered mail 30 days in advance.
    (b) After you relinquish your permit, you are still responsible for 
proper abandonment of any drill sites according to the requirements of 
30 CFR 251.7(b)(8). You must also comply with all other obligations 
specified in this part or in the permit.

                          Environmental Issues



Sec. 280.29  Will MMS monitor the environmental effects of my activity?

    We will evaluate the potential of proposed prospecting or scientific 
research activities for adverse impact on the environment to determine 
the need for mitigation measures.



Sec. 280.30  What activities will not require environmental analysis?

    We anticipate that activities of the type listed below typically 
will not cause significant environmental impact and will normally be 
categorically excluded from additional environmental analysis. The types 
of activities include:
    (a) Gravity and magnetometric observations and measurements;
    (b) Bottom and subbottom acoustic profiling or imaging without the 
use of explosives;
    (c) Hard minerals sampling of a limited nature such as shallow test 
drilling;
    (d) Water and biotic sampling, if the sampling does not adversely 
affect shellfish beds, marine mammals, or an endangered species or if 
permitted by the National Marine Fisheries Service or another Federal 
agency;
    (e) Meteorological observations and measurements, including the 
setting of instruments;

[[Page 551]]

    (f) Hydrographic and oceanographic observations and measurements, 
including the setting of instruments;
    (g) Sampling by box core or grab sampler to determine seabed 
geological or geotechnical properties;
    (h) Television and still photographic observation and measurements;
    (i) Shipboard hard mineral assaying and analysis; and
    (j) Placement of positioning systems, including bottom transponders 
and surface and subsurface buoys reported in Notices to Mariners.



Sec. 280.31  Whom will MMS notify about environmental issues?

    (a) In cases where Coastal Zone Management Act consistency review is 
required, the Director will notify the Governor of each adjacent State 
with a copy of the application for a permit immediately upon the 
submission for approval.
    (b) In cases where an environmental assessment is to be prepared, 
the Director will invite the Governor of each adjacent State to review 
and provide comments regarding the proposed activities. The Director's 
invitation to provide comments will allow the Governor a specified 
period of time to comment.
    (c) When a permit is issued, the Director will notify affected 
parties including each affected coastal State, Federal agency, local 
government, and special interest organization that has expressed an 
interest.

                          Penalties and Appeals



Sec. 280.32  What penalties may I be subject to?

    (a) Penalties for noncompliance under a permit. You are subject to 
the penalty provisions of section 24 of the Act (43 U.S.C. 1350) and the 
procedures contained in 30 CFR part 250, subpart N for noncompliance 
with:
    (1) Any provision of the Act;
    (2) Any provisions of a G&G or drilling permit; or
    (3) Any regulation or order issued under the Act.
    (b) Penalties under other laws and regulations. The penalties 
prescribed in this section are in addition to any other penalty imposed 
by any other law or regulation.



Sec. 280.33  How can I appeal a penalty?

    See 30 CFR Sec. 250.1409 and 30 CFR part 290, subpart A, for 
instructions on how to appeal any decision assessing a civil penalty 
under 43 U.S.C. 1350 and 30 CFR part 250, subpart A.



Sec. 280.34  How can I appeal an order or decision?

    See 30 CFR part 290, subpart A, for instructions on how to appeal an 
order or decision.



                       Subpart D_Data Requirements

                     Geological Data and Information



Sec. 280.40  When do I notify MMS that geological data and information are 

available for submission, inspection, and selection?

    (a) You must notify the RD, in writing, when you complete the 
initial analysis, processing, or interpretation of any geological data 
and information. Initial analysis and processing are the stages of 
analysis or processing where the data and information first become 
available for in-house interpretation by the permittee or become 
available commercially to third parties via sale, trade, license 
agreement, or other means.
    (b) The RD may ask if you have further analyzed, processed, or 
interpreted any geological data and information. When asked, you must 
respond to us in writing within 30 days.
    (c) The RD may ask you or a third party to submit the analyzed, 
processed, or interpreted geologic data and information for us to 
inspect or permanently retain. You must submit the data and information 
within 30 days after such a request.



Sec. 280.41  What types of geological data and information must I submit to 

MMS?

    Unless the RD specifies otherwise, you must submit geological data 
and information that include:
    (a) An accurate and complete record of all geological (including 
geochemical) data and information describing each operation of analysis, 
processing, and interpretation;
    (b) Paleontological reports identifying by depth any microscopic 
fossils

[[Page 552]]

collected, including the reference datum to which paleontological sample 
depths are related and, if the RD requests, washed samples, that you 
maintain for paleontological determinations;
    (c) Copies of well logs or charts in a digital format, if available;
    (d) Results and data obtained from formation fluid tests;
    (e) Analyses of core or bottom samples and/or a representative cut 
or split of the core or bottom sample;
    (f) Detailed descriptions of any hydrocarbons or other minerals or 
hazardous conditions encountered during operations, including near 
losses of well control, abnormal geopressures, and losses of 
circulation; and
    (g) Other geological data and information that the RD may specify.



Sec. 280.42  When geological data and information are obtained by a third 

party, what must we both do?

    A third party may obtain geological data and information from a 
permittee, or from another third party, by sale, trade, license 
agreement, or other means. If this happens:
    (a) The third-party recipient of the data and information assumes 
the obligations under this part, except for the notification provisions 
of Sec. 280.40(a) and is subject to the penalty provisions of Sec.  
280.32(a)(1) and 30 CFR part 250, subpart N; and
    (b) A permittee or third party that sells, trades, licenses, or 
otherwise provides data and information to a third party must advise the 
recipient, in writing, that accepting these obligations is a condition 
precedent of the sale, trade, license, or other agreement; and
    (c) Except for license agreements, a permittee or third party that 
sells, trades, or otherwise provides data and information to a third 
party must advise the RD in writing within 30 days of the sale, trade, 
or other agreement, including the identity of the recipient of the data 
and information; or
    (d) For license agreements, a permittee or third party that licenses 
data and information to a third party must, within 30 days of a request 
by the RD, advise the RD, in writing, of the license agreement, 
including the identity of the recipient of the data and information.

                    Geophysical Data and Information



Sec. 280.50  When do I notify MMS that geophysical data and information are 

available for submission, inspection, and selection?

    (a) You must notify the RD in writing when you complete the initial 
processing and interpretation of any geophysical data and information. 
Initial processing is the stage of processing where the data and 
information become available for in-house interpretation by the 
permittee, or become available commercially to third parties via sale, 
trade, license agreement, or other means.
    (b) The RD may ask whether you have further processed or interpreted 
any geophysical data and information. When asked, you must respond to us 
in writing within 30 days.
    (c) The RD may request that the permittee or third party submit 
geophysical data and information before making a final selection for 
retention. Our representatives may inspect and select the data and 
information on your premises, or the RD can request delivery of the data 
and information to the appropriate regional office for review.
    (d) You must submit the geophysical data and information within 30 
days of receiving the request, unless the RD extends the delivery time.
    (e) At any time before final selection, the RD may review and return 
any or all geophysical data and information. We will notify you in 
writing of any data the RD decides to retain.



Sec. 280.51  What types of geophysical data and information must I submit to 

MMS?

    Unless the RD specifies otherwise, you must include:
    (a) An accurate and complete record of each geophysical survey 
conducted under the permit, including digital navigational data and 
final location maps;
    (b) All seismic data collected under a permit presented in a format 
and of a quality suitable for processing;

[[Page 553]]

    (c) Processed geophysical information derived from seismic data with 
extraneous signals and interference removed, presented in a quality 
format suitable for interpretive evaluation, reflecting state-of-the-art 
processing techniques; and
    (d) Other geophysical data, processed geophysical information, and 
interpreted geophysical information including, but not limited to, 
shallow and deep subbottom profiles, bathymetry, sidescan sonar, gravity 
and magnetic surveys, and special studies such as refraction and 
velocity surveys.



Sec. 280.52  When geophysical data and information are obtained by a third 

party, what must we both do?

    A third party may obtain geophysical data, processed geophysical 
information, or interpreted geophysical information from a permittee, or 
from another third party, by sale, trade, license agreement, or other 
means. If this happens:
    (a) The third-party recipient of the data and information assumes 
the obligations under this part, except for the notification provisions 
of Sec. 280.50(a) and is subject to the penalty provisions of Sec.  
280.32(a)(1) and 30 CFR 250, subpart N; and
    (b) A permittee or third party that sells, trades, licenses, or 
otherwise provides data and information to a third party must advise the 
recipient, in writing, that accepting these obligations is a condition 
precedent of the sale, trade, license, or other agreement; and
    (c) Except for license agreements, a permittee or third party that 
sells, trades, or otherwise provides data and information to a third 
party must advise the RD, in writing within 30 days of the sale, trade, 
or other agreements, including the identity of the recipient of the data 
and information; or
    (d) For license agreements, a permittee or third party that licenses 
data and information to a third party must, within 30 days of a request 
by the RD, advise the RD, in writing, of the license agreement, 
including the identity of the recipient of the data and information.

                              Reimbursement



Sec. 280.60  Which of my costs will be reimbursed?

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



Sec. 280.61  Which of my costs will not be reimbursed?

    (a) When you request reimbursement, you must identify reproduction 
and processing costs separately from acquisition costs.
    (b) We will not reimburse you or a third party for data acquisition 
costs or for the costs of analyzing or processing geological information 
or interpreting geological or geophysical information.

                               Protections



Sec. 280.70  What data and information will be protected from public 

disclosure?

    In making data and information available to the public, the RD will 
follow the applicable requirements of:
    (a) The Freedom of Information Act (5 U.S.C. 552);
    (b) The implementing regulations at 43 CFR part 2;
    (c) The Act; and
    (d) The regulations at 30 CFR parts 250 and 252.
    (1) If the RD determines that any data or information is exempt from

[[Page 554]]

disclosure under the Freedom of Information Act, we will not disclose 
the data and information unless either:
    (i) You and all third parties agree to the disclosure; or
    (ii) A provision of 30 CFR parts 250 and 252 allows us to make the 
disclosure.
    (2) We will keep confidential the identity of third-party recipients 
of data and information collected under a permit. We will not release 
the identity unless you and the third parties agree to the disclosure.
    (3) When you detect any significant hydrocarbon occurrences or 
environmental hazards on unleased lands during drilling operations, the 
RD will immediately issue a public announcement. The announcement must 
further the national interest without unduly damaging your competitive 
position.



Sec. 280.71  What is the timetable for release of data and information?

    We will release data and information that you or a third party 
submits and we retain according to paragraphs (a) and (b) of this 
section.
    (a) If the data and information are not related to a deep 
stratigraphic test, we will release them to the public according to 
items (1), (2), and (3) in the following table:

------------------------------------------------------------------------
   If you or a third party      The Regional Director will disclose them
 submits and we retain * * *              to the public * * *
------------------------------------------------------------------------
(1) Geological data and        10 years after issuing the permit.
 information.
(2) Geophysical data.........  50 years after you or a third party
                                submit the data.
(3) Geophysical information..  25 years after you or a third party
                                submit the information
(4) Data and information       25 years after you complete the test,
 related to a deep              unless the provisions of paragraph (b)
 stratigraphic test.            of this section apply.
------------------------------------------------------------------------

    (b) This paragraph applies if you are covered by paragraph (a)(4) of 
this section and a lease sale is held or a noncompetitive agreement is 
negotiated after you complete a test well. We will release the data and 
information related to the deep stratigraphic test at the earlier of the 
following times:
    (1) Twenty-five years after you complete the test; or
    (2) Sixty calendar days after we issue a lease, located partly or 
totally within 50 geographic miles (92.7 kilometers) of the test.



Sec. 280.72  What procedure will MMS follow to disclose acquired data and 

information to a contractor for reproduction, processing, and interpretation?

    (a) When practical, the RD will advise the person who submitted data 
and information under Sec. Sec. 280.40 or 280.50 of the intent to 
provide the data or information to an independent contractor or agent 
for reproduction, processing, and interpretation.
    (b) The person notified will have at least five working days to 
comment on the action.
    (c) When the RD advises the person who submitted the data and 
information, all other owners of the data or information will be 
considered to have been notified.
    (d) The independent contractor or agent must sign a written 
commitment not to sell, trade, license, or disclose data or information 
to anyone without the RD's consent.



Sec. 280.73  Will MMS share data and information with coastal States?

    (a) We can disclose proprietary data, information, and samples 
submitted to us by permittees or third parties that we receive under 
this part to the Governor of any adjacent State that requests it 
according to paragraphs (b), (c), and (d) of this section. The permittee 
or third parties who submitted proprietary data, information, and 
samples will be notified about the disclosure and will have at least 
five working days to comment on the action.
    (b) We will make a disclosure under this section only after the 
Governor and the Secretary have entered into an agreement containing all 
of the following provisions:
    (1) The confidentiality of the information will be maintained.
    (2) In any action taken for failure to protect the confidentiality 
of proprietary information, neither the Federal

[[Page 555]]

Government nor the State may raise as a defense:
    (i) Any claim of sovereign immunity; or
    (ii) Any claim that the employee who revealed the proprietary 
information was acting outside the scope of his/her employment in 
revealing the information.
    (iii) The State agrees to hold the Federal Government harmless for 
any violation by the State or its employees or contractors of the 
agreement to protect the confidentiality of proprietary data and 
information and samples.
    (iv) The materials containing the proprietary data, information, and 
samples will remain the property of the Federal Government.
    (c) The data, information, and samples available for reproduction to 
the State(s) under an agreement must be related to leased lands. Data 
and information on unleased lands may be viewed but not copied or 
reproduced.
    (d) The State must return to us the materials containing the 
proprietary data, information, and samples when we ask for them or when 
the State no longer needs them.
    (e) Information received and knowledge gained by a State official 
under paragraph (d) of this section is subject to confidentiality 
requirements of:
    (1) The Act; and
    (2) The regulations at 30 CFR parts 280, 281, and 282.



                    Subpart E_Information Collection



Sec. 280.80  Paperwork Reduction Act statement--information collection.

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



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.

[[Page 556]]

281.18 Bidding system.
281.19 Lease term.
281.20 Submission of bids.
281.21 Award of leases.
281.22 Lease form.
281.23 Effective date of leases.

                   Subpart C_Financial Considerations

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

               Subpart D_Assignments and Lease Extensions

281.40 Assignment of leases or interests therein.
281.41 Requirements for filing for transfers.
281.42 Effect of assignment on particular lease.
281.43 Effect of suspensions on lease term.

                     Subpart E_Termination of Leases

281.46 Relinquishment of leases or parts of leases.
281.47 Cancellation of leases.

    Authority: 43 U.S.C. 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 557]]

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 558]]



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 under this part limits the 
minerals to which rights are granted, such lease shall include rights to 
minerals produced in direct association with the OCS mineral specified 
in the lease but not the rights to minerals specifically reserved.
    (c) The existence of an OCS mineral, oil and gas, or sulphur lease 
shall not preclude the issuance of a lease(s) for other OCS minerals in 
the same area. However, no OCS mineral lease shall authorize or permit 
the lessee thereunder to unreasonably interfere with or endanger 
operations under an existing OCS mineral, oil and gas, or sulphur lease.



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 559]]

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 560]]

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 561]]

    (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 562]]

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 563]]

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 564]]

    (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 565]]

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 566]]

    (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 567]]

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 568]]

    (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 569]]

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 570]]

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 571]]

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 572]]

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 573]]

    (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 574]]

    (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 575]]

    (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 576]]

    (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 577]]

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 578]]

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 579]]

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 580]]

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 581]]

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 582]]

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 583]]

    (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 584]]

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 
Sec. Sec. 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 585]]

written approval of the Director prior to the use of such new or 
alternative technologies, techniques, procedures, equipment, or 
activities.
    (c) The lessee shall immediately notify the Director when there is a 
death or serious injury; fire, explosion, or other hazardous event which 
threatens damage to life, a mineral deposit, or equipment; spills of 
oil, chemical reagents, or other liquid pollutants which could cause 
pollution; or damage to aquatic life or the environment associated with 
operations on the lease. As soon as practical, the lessee shall file a 
detailed report on the event and action(s) taken to control the 
situation and to mitigate any further damage.
    (d)(1) Lessees shall provide means, at all reasonable hours either 
day or night, for the Director to inspect or investigate the conditions 
of the operation and to determine whether applicable regulations; terms 
and conditions of the lease; and the requirements of the approved 
Delineation, Testing, or Mining Plan are being met.
    (2) A lessee shall, on request by the Director, furnish food, 
quarters, and transportation for MMS representatives to inspect its 
facilities. Upon request, the lessee will be reimbursed by the United 
States for the actual costs which it incurs as a result of its providing 
food, quarters, and transportation for an MMS representative's stay of 
more than 10 hours. Request for reimbursement must be submitted within 
60 days following the cost being incurred.
    (e) Mining and processing vessels, platforms, structures, artificial 
islands, and mobile drilling units which have helicopter landing 
facilities shall be identified with at least one sign using letters and 
figures not less than 12 inches in height. Signs for structures without 
helicopter landing facilities shall be identified with at least one sign 
using letters and figures not less than 3 inches in height. Signs shall 
be affixed at a location that is visible to approaching traffic and 
shall contain the following information which may be abbreviated:
    (1) Name of the lease operator;
    (2) The area designation based on Official OCS Protraction Diagrams;
    (3) The block number in which the facility is located; and
    (4) Vessel, platform, structure, or rig name.
    (f)(1) Drilling.(i) When drilling on lands valuable or potentially 
valuable for oil and gas or geopressured or geothermal resources, 
drilling equipment shall be equipped with blowout prevention and control 
devices acceptable to the Director before penetrating more than 500 feet 
unless a different depth is specified in advance by the Director.
    (ii) In cases where the Director determines that there is sufficient 
liklihood of encountering pressurized hydrocarbons, the Director may 
require that the lessee comply with all or portions of the requirements 
in part 250, subpart D, of this title.
    (iii) Before drilling any hole which may penetrate an aquifer, the 
lessee shall follow the procedures included in the approved plan for the 
penetration and isolation of the aquifer during the drilling operation, 
during use of the hole, and for subsequent abandonment of the hole.
    (iv) Cuttings from holes drilled on the lease shall be disposed of 
and monitored in accordance with the approved plan.
    (v) The use of muds in drilling holes on the lease and their 
subsequent disposition shall be according to the approved plan.
    (2) All drill holes which are susceptible to logging shall be 
logged, and the lessee shall prepare a detailed lithologic log of each 
drill hole. Drill holes which are drilled deeper than 500 feet shall be 
drilled in a manner which permits logging. Copies of logs of cores and 
cuttings and all in-hole surveys such as electronic logs, gamma ray 
logs, neutron density logs, and sonic logs shall be provided to the 
Director.
    (3) Drill holes for exploration, testing, development, or production 
shall be properly plugged and abandoned to the satisfaction of the 
Director in accordance with the approved plan and in such a manner as to 
protect the surface and not endanger any operation; any freshwater 
aquifer; or deposit of oil, gas, or other mineral substance.
    (g) The use of explosives on the lease shall be in accordance with 
the approved plan.

[[Page 586]]

    (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 
Sec. Sec. 250.194, 250.218, 250.249, and 250.303 of this title.

[[Page 587]]

    (b) If the baseline data available are judged by the Director to be 
inadequate to support an environmental evaluation of a proposed 
Delineation, Testing, or Mining Plan, the Director may require the 
lessee to collect additional environmental baseline data prior to the 
approval of the activities proposed.
    (c)(1) The lessee shall monitor activities in a manner that develops 
the data and information necessary to enable the Director to assess the 
impacts of exploration, testing, mining, and processing activities on 
the environment on and off the lease; develop and evaluate methods for 
mitigating adverse environmental effects; validate assessments made in 
previous environmental evaluations; and ensure compliance with lease and 
other requirements for the protection of the environment.
    (2) Monitoring of environmental effects shall include determination 
of the spatial and temporal environmental changes induced by the 
exploration, testing, development, production, and processing activities 
on the flora and fauna of the sea surface, the water column, and/or the 
seafloor.
    (3) The Director may place observers onboard exploration, testing, 
mining, and processing vessels; installations; or structures to ensure 
that the provisions of the lease, the approved plan, and these 
regulations are followed and to evaluate the effectiveness of the 
approved monitoring and mitigation practices and procedures in 
protecting the environment.
    (4) The Director may order or the lessee may request a modification 
of the approved monitoring program prior to the startup of testing 
activities or commercial-scale recovery, and at other appropriate times 
as necessary, to reflect accurately the proposed operations or to 
incorporate the results of recent research or improved monitoring 
techniques.
    (5) When prototype test mining is proposed, the lessee shall include 
a monitoring strategy for assessing the impacts of the testing 
activities and for developing a strategy for monitoring commercial-scale 
recovery and mitigating the impacts of commercial-scale recovery more 
effectively. At a minimum, the proposed monitoring activities shall 
address specific concerns expressed in the lease-sale environmental 
analysis.
    (6) When required, the monitoring plan shall specify:
    (i) The sampling techniques and procedures to be used to acquire the 
needed data and information;
    (ii) The format to be used in analysis and presentation of the data 
and information;
    (iii) The equipment, techniques, and procedures to be used in 
carrying out the monitoring program; and
    (iv) The name and qualifications of person(s) designated to be 
responsible for carrying out the environmental monitoring.
    (d) Lessees shall develop and conduct their operations in a manner 
designed to avoid, minimize, or otherwise mitigate environmental impacts 
and to demonstrate the effectiveness of efforts to that end. Based upon 
results of the monitoring program, the Director may specify particular 
procedures for mitigating environmental impacts.
    (e) In the event that equipment or procedural failure might result 
in significant additional damage to the environment, the lessee shall 
submit a Contingency Plan which specifies the procedures to be followed 
to institute corrective actions in response to such a failure and to 
minimize adverse impacts on the environment. Such procedures shall be 
designed for the site and mining activities described in the approved 
Delineation, Testing, or Mining Plan.

[54 FR 2067, Jan. 18, 1989; 64 FR 9066, Feb. 24, 1999, as amended at 64 
FR 72795, Dec. 28, 1999; 70 FR 51519, Aug. 30, 2005]



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 all operations conducted during each

[[Page 588]]

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 as the lease continues in force. Should

[[Page 589]]

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 590]]

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 591]]



                          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_Minerals Revenue Management Appeal Procedures

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

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

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



        Subpart A_Offshore Minerals Management Appeal Procedures



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 592]]

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_Minerals Revenue Management Appeal Procedures



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 Minerals 
Revenue Management (MRM) and the payment of royalties and other payments 
due under leases subject to this subpart.

[71 FR 51752, Aug. 31, 2006]



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 593]]

instrument is expressly denominated as a ``lease,'' including any:
    (1) Contract;
    (2) Net profit share arrangement;
    (3) Joint venture; or
    (4) Agreement the Secretary approves under the Indian Mineral 
Development Act, 25 U.S.C. 2101 et seq.
    Lessee means any person to whom the United States, or the United 
States on behalf of an Indian tribe or individual Indian mineral owner, 
issues a lease subject to this subpart, or any person to whom all or 
part of the lessee's interest or operating rights in a lease subject to 
this subpart has been assigned.
    Notice of Order means the notice that MMS or a delegated State 
issues to a lessee that informs the lessee that MMS or the delegated 
State has issued an order to the lessee's designee.
    Obligation means:
    (1) A lessee's, designee's or payor's duty to:
    (i) Deliver oil or gas royalty in kind; or
    (ii) Make a lease-related payment, including royalty, minimum 
royalty, rental, bonus, net profit share, proceeds of sale, interest, 
penalty, civil penalty, or assessment; and
    (2) The Secretary's duty to:
    (i) Take oil or gas royalty-in-kind; or
    (ii) Make a lease-related payment, refund, offset, or credit, 
including royalty, minimum royalty, rental, bonus, net profit share, 
proceeds of sale, or interest.
    (3) The obligations identified in paragraphs (1)(i) and (2)(i) of 
this definition are nonmonetary obligations. The obligations identified 
in paragraphs (1)(ii) and (2)(ii), including the requirement to compute 
the amount of such obligations, are monetary obligations.
    Order, for purposes of this subpart only, means any document issued 
by the MMS Director, MMS MRM, or a delegated state that contains 
mandatory[smc2] or ordering language that requires the 
recipient to do any of the following for any lease subject to this 
subpart: report, compute, or pay royalties or other obligations, report 
production, or provide other information.
    (1) Order includes:
    (i) An order to pay or to compute and pay; and
    (ii) An MMS or delegated State decision to deny a lessee's, 
designee's, or payor's written request that asserts an obligation due 
the lessee, designee or payor.
    (2) Order does not include:
    (i) A non-binding request, information, or guidance, such as:
    (A) Advice or guidance on how to report or pay, including a 
valuation determination, unless it contains mandatory or ordering 
language; and
    (B) A policy determination;
    (ii) A subpoena;
    (iii) An order to pay that MMS issues to a refiner or other person 
involved in disposition of royalty taken in kind; or
    (iv) A Notice of Noncompliance or a Notice of Civil Penalty issued 
under 30 U.S.C. 1719 and 30 CFR part 241, or a decision of an 
administrative law judge or of the IBLA following a hearing on the 
record on a Notice of Noncompliance or Notice of Civil Penalty.
    Party means MMS, any person who files a Notice of Appeal, and any 
person who files a Notice of Joinder in an appeal under this subpart.

[64 FR 26257, May 13, 1999, as amended at 71 FR 51752, Aug. 31, 2006]



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.

[[Page 594]]

    (1) Within the same 30-day period, you must file in the office of 
the official issuing the order a statement of reasons or written 
arguments or briefs that include the arguments on the facts or laws that 
you believe justify reversal or modification of the order.
    (2) If you are a designee, when you file your Notice of Appeal you 
must serve your Notice of Appeal on the lessees for the leases in the 
order you appealed.
    (b) You may not request and will not receive an extension of time 
for filing the Notice of Appeal.
    (c) If the office of the official issuing the order does not receive 
the Notice of Appeal within the time provided in paragraph (a) of this 
section, the Notice of Appeal will be considered timely if the office of 
the official issuing the order receives:
    (1) The Notice of Appeal not later than 10 days after the required 
filing date; and
    (2) The officer with whom the Notice of Appeal must be filed 
determines that the Notice of Appeal was transmitted to the proper 
office before the filing deadline in paragraph (a) of this section.
    (d) If the Notice of Appeal is filed after the grace period provided 
in paragraph (c) of this section and was not transmitted to the proper 
office before the filing deadline in paragraph (a) of this section, the 
MMS Director will not consider the Notice of Appeal and the case will be 
closed.
    (e) The officer with whom the Notice of Appeal is filed will send 
the appeal and accompanying papers to the MMS Director.
    (f) The MMS Director will review the record and render a decision in 
the case.
    (g) If an order involves Indian leases, the Deputy Commissioner of 
Indian Affairs will exercise the functions vested in the MMS Director.



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

[[Page 595]]

IBLA under the procedures provided in 43 CFR part 4, subpart E.



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]

[[Page 597]]



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.................         599

[[Page 599]]



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 601]]



        CHAPTER IV--GEOLOGICAL SURVEY, DEPARTMENT OF THE INTERIOR




  --------------------------------------------------------------------
Part                                                                Page
401             State Water Research Institute Program......         603
402             Water-Resources Research Program and the 
                    Water-Resources Technology Development 
                    Program.................................         608

[[Page 603]]



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 604]]

    (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 605]]

    (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.



Sec. Sec. 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 606]]

    (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]



Sec. Sec. 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 607]]

    (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.



Sec. Sec. 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 608]]

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.

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

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



                            Subpart A_General



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 609]]

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.



Sec. Sec. 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 610]]

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 611]]

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 613]]



                              FINDING AIDS




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

  A list of CFR titles, subtitles, chapters, subchapters and parts and 
an alphabetical list of agencies publishing in the CFR are included in 
the CFR Index and Finding Aids volume to the Code of Federal Regulations 
which is published separately and revised annually.

  Material Approved for Incorporation by Reference
  Table of CFR Titles and Chapters
  Alphabetical List of Agencies Appearing in the CFR
  List of CFR Sections Affected

[[Page 615]]

            Material Approved for Incorporation by Reference

                      (Revised as of July 1, 2007)

  The Director of the Federal Register has approved under 5 U.S.C. 
552(a) and 1 CFR Part 51 the incorporation by reference of the following 
publications. This list contains only those incorporations by reference 
effective as of the revision date of this volume. Incorporations by 
reference found within a regulation are effective upon the effective 
date of that regulation. For more information on incorporation by 
reference, see the preliminary pages of this volume.


30 CFR (PARTS 200 to 699)

MINERALS MANAGEMENT SERVICE, DEPARTMENT OF THE INTERIOR
                                                                  30 CFR


American Concrete Institute

  P.O. Box 9094, Farmington Hill, Michigan 48333-
  9094
ACI Standard 318-95, Building Code Requirements         250.198; 250.901
  for Reinforced Concrete, plus Commentary on 
  Building Code Requirements for Reinforced 
  Concrete (ACI 318R-95).
ACI Standard 357-R-84 (Reapproved 1997), Guide for      250.198; 250.901
  the Design and Construction of Fixed Offshore 
  Concrete Structures.


American Institute of Steel Construction, Inc.

  One East Wacker Drive, Suite 700, Chicago, 
  Illinois 60601-1802
AISC 360-05: Standard Specification for Structural      250.198; 250.901
  Steel Buildings, 2005.


American Society of Mechanical Engineers (ASME)

  Three Park Avenue, New York, NY 10016-5990; 
  Order inquiries: 22 Law Drive, P.O. Box 2900, 
  Fairfield, New Jersey 07007; Telephone: 1-800-
  843-2763
ANSI/ASME Boiler and Pressure Vessel Code, Section             250.198; 
  I, Rules for Construction of Power Boilers, 2004       250.803(b)(1), 
  including July 1, 2005 Addenda.                            (b)(1)(i); 
                                                        250.1629(b)(1), 
                                                               (b)(1)(i)
ANSI/ASME Boiler and Pressure Vessel Code, Section             250.198; 
  IV: Rules for Construction of Heating Boilers,         250.803(b)(1), 
  including Appendices 1, 2, 3, 5, and 6 and non-            (b)(1)(i); 
  Mandatory Appendices B, C, D, E, F, H, I, K, L        250.1629(b)(1); 
  and M, and the Guide to Manufacturers Data           250.1629(b)(1)(i)
  Report Forms, 2004 Edition, including July 1, 
  2005 Addenda.
ANSI/ASME Boiler and Pressure Vessel Code, Section             250.198; 
  VIII, Division 1: Rules for Construction of            250.803(b)(1), 
  Pressure Vessels, 2004, including July 2005                (b)(1)(i); 
  Addenda.                                              250.1629(b)(1), 
                                                               (b)(1)(i)
ANSI/ASME Boiler and Pressure Vessel Code, Section             250.198; 
  VIII, Division 2: Alternative Rules, 2004,           250.803(b)(1)and 
  including 2005 Addenda.                                    (b)(1)(i); 
                                                      250.1629(b)(1)and 
                                                               (b)(1)(i)
ANSI/ASME B 16.5-2003, Pipe Flanges and Flanged                250.198; 
  Fittings.                                               250.1002(b)(2)

[[Page 616]]

ANSI/ASME B 31.8-2003, Gas Transmission and         250.198; 250.1002(a)
  Distribution Piping Systems.
ANSI/ASME SPPE-1-1994 and SPPE-1d-1996 Addenda,                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         250.198; 250.490
  Respiratory Protection.


The American Petroleum Institute

  1220 L Street, NW., Washington, DC 20005-4070; 
  Telephone: (202) 682-8000
API 510, Pressure Vessel Inspection Code: In-         250.198; 250.803; 
  Service Inspection, Rating, Repair and                        250.1629
  Alteration (Downstream Segment) Ninth edition, 
  June 2006.
API RP 2A-WSD, Recommended Practice for Planning,              250.198; 
  Designing, and Constructing Fixed Offshore             250.901(a)(4); 
  Platforms--Working Stress Design, Twenty-first     250.908(a); 250.920
  Edition, December 2000, Errata and Supplements 1 
  (December 2002) and 2, (October 2005), API Stock 
  No. G2AWSD.
API RP 2D, Recommended Practice for Operation and        250.108(a)(1); 
  Maintenance of Offshore Cranes, Fifth Edition,                 250.198
  June 2003.
API RP 2FPS, Recommended Practice for Planning,         250.198; 250.901
  Designing, and Constructing Floating Production 
  Systems, First edition, March 2001.
API RP 2RD, Recommended Practice for Design of        250.198; 250.800; 
  Risers for Floating Production Systems (FPSs)        250.901; 250.1002
  and Tension Leg Platforms, First edition, June 
  1998, reaffirmed May 2006.
API RP 2SK, Recommended Practice for Design and       250.198; 250.800; 
  Analysis of Stationkeeping Systems for Floating                250.901
  Structures, Third edition, October 2005.
API RP 2SM, Recommended Practice for Design,            250.198; 250.901
  Manufacture, Installation, and Maintenance of 
  Synthetic Fiber Ropes for Offshore Mooring, 
  First edition, March 2001.
API RP 2T, Recommended Practice for Planning,           250.198; 250.901
  Designing, and Constructing Tension Leg 
  Platforms, Second edition, August 1997.
API RP 14B Recommended Practice for Design,                    250.198; 
  Installation, Repair, and Operation of                 250.801(e)(4); 
  Subsurface Safety Valve Systems, Fifth Edition,       250.804(a)(1)(i)
  October 2005, also available as ISO 10417: 2004 
  (Identical) Petroleum and Natural Gas 
  Industries--Subsurface Safety Valve Systems--
  Design, Installation, Operation and Redress.
API RP 14C Recommended Practice for Analysis,         250.125; 250.198; 
  Design, Installation, and Testing of Basic       250.292; 250.802(b), 
  Surface Safety Systems for Offshore Production    (e)(2); 250.803(a), 
  Platforms, Seventh Edition, March 2001.            (b)(2)(i), (b)(4), 
                                                     (b)(5)(i), (b)(7), 
                                                     (b)(9)(v), (c)(2); 
                                                    250.804(a), (a)(5); 
                                                           250.1002(d); 
                                                        250.1004(b)(9); 
                                                   250.1628(c), (d)(2); 
                                                        250.1629(b)(2), 
                                                             (b)(4)(v); 
                                                             250.1630(a)

[[Page 617]]

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), 
  reaffirmed June 2000.                                           (d)(3)
API RP 14F, Recommended Practice for Design and    250.114(c); 250.198; 
  Installation of Electrical Systems for Fixed and    250.803(b)(9)(v); 
  Floating Offshore Petroleum Facilities for           250.1629(b)(4)(v)
  Unclassified and Class 1, Division 1 and 
  Division 2 Locations, Fourth Edition, June 1999, 
  API Stock No. G14F04.
API RP 14FZ, Recommended Practice for Design and   250.114(c); 250.198; 
  Installation of Electrical Systems for Fixed and    250.803(b)(9)(v); 
  Floating Offshore Petroleum Facilities for           250.1629(b)(4)(v)
  Unclassified and Class 1, Zone 0, Zone 1 and 
  Zone 2 Locations, First Edition, September 2001, 
  API Stock No. G14FZ1.
API RP 14G, Recommended Practice for Fire                      250.198; 
  Prevention and Control on Open Type Offshore           250.803(b)(8), 
  Production Platforms, Third Edition, December 1,           (b)(9)(v); 
  1993 (Reaffirmed June 2000).                          250.1629(b)(3), 
                                                               (b)(4)(v)
API RP 14H, Recommended Practice for the           250.198; 250.802(d); 
  Installation, Maintenance and Repair of Surface          250.804(a)(4)
  Safety Valves and Underwater Safety Valves 
  Offshore, Fourth Edition, July 1, 1994, API 
  Stock No. G14H04.
API RP 14J, Recommended Practice for Design and       250.198; 250.800; 
  Hazards Analysis for Offshore Production                       250.901
  Facilities, Second edition, May 2001, API Order 
  No. G14J02.
API RP 53, Recommended Practice for Blowout           250.198; 250.442; 
  Prevention Equipment Systems for Drilling Wells,               250.446
  Third Edition, reaffirmed September 2004.
API RP 65, Recommended Practice for Cementing           250.198; 250.415
  Shallow Water Flow Zones in Deep Water Wells, 
  FirstEdition, September 2002.
API RP 500, Recommended Practice for               250.114(a); 250.198; 
  Classification of Locations for Electrical                   250.459; 
  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 (Reaffirmed November           250.1628(b)(3); 
  2002).                                             250.1628(d)(4)(i); 
                                                       250.1629(b)(4)(i)
API RP 505, Recommended Practice for               250.114(a); 250.459; 
  Classification of Locations for Electrical          250.802(e)(4)(i); 
  Installations at Petroleum Facilities Classified    250.803(b)(9)(i); 
  as Class 1, Zone 0, Zone 1, and Zone 2, First         250.1628(b)(3); 
  Edition, November 1997 (Reaffirmed November        250.1628(d)(4)(i); 
  2002).                                               250.1629(b)(4)(i)
API Specification 2C, Specification for Offshore        250.108; 250.198
  Pedestal Mounted Cranes, Sixth Edition, 
  Effective date: September 2004.
API Spec 6A, Specification for Wellhead and                    250.198; 
  Christmas Tree Equipment (also issued as ISO           250.806(a)(3); 
  10423:2003), Nineteenth Edition, Effective Date:              250.1002
  February 1, 2005.
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, 
[[Page 618]]on, February 1, 1996 (Reaffirmed 
  January 2003), API Stock No. G06AV1.
API Specification 6D: Specification for Pipeline               250.198; 
  Valves, Twenty-second edition, January 2002             250.1002(b)(1)
  (also available as ISO 14313:1999), MOD, 
  Petroleum and Natural Gas Industries--Pipeline 
  Transportation Systems--Pipeline Valves, 
  Effective Date: July 1, 2002; Proposed National 
  Adoption, includes Annex F, March 1, 2005.
API Specification 14A, Specification for                       250.198; 
  Subsurface Safety Valve Equipment, Tenth                 250.806(a)(3)
  Edition, November 2000; also available as ISO 
  10432:1999, Petroleum and Natural Gas 
  Industries--Downhole Equipment--Subsurface 
  Safety Valve Equipment, Effective date: May 15, 
  2001.
API Specification 17J, Specification for Unbonded     250.198; 250.803; 
  Flexible Pipe, Second edition dated November        250.1002; 250.1007
  1999, including Errata dated May 25, 2001 and 
  Addendum 1 dated June 2003, effective date 
  December 2002.
API Specification Q1, Specification for Quality                250.198; 
  Programs for the Petroleum, Petrochemical and        250.806(a)(2)(ii)
  Natural Gas Industry dated June 15, 2003, 
  including August 2003 errata, Seventh edition, 
  also available as ISO/TS 29001, Effective Date: 
  December 15, 2003.
API Standard 2551, Standard Method for Measurement             250.198; 
  and Calibration of Horizontal Tanks, First              250.1202(l)(4)
  Edition, 1965, reaffirmed March 2002.
API Standard 2552, Measurement and Calibration of              250.198; 
  Spheres and Spheroids, First Edition, 1966,             250.1202(l)(4)
  reaffirmed February 2006.
API Standard 2555, Method for Liquid Calibration               250.198; 
  of Tanks, First Edition, September 1966,                250.1202(l)(4)
  reaffirmed March 2002.
API RP 2556, Recommended Practice for Correcting               250.198; 
  Gauge Tables for Incrustation, Second Edition,          250.1202(l)(4)
  August 1993 (Reaffirmed November 2003), 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, Tank Calibration, Section 2A:             250.198; 
  Measurement and Calibration of Upright                  250.1202(1)(4)
  Cylindrical Tanks by the Manual Tank Strapping 
  Method, First Edition, reaffirmed March 2002.
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 March 2002.
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, Second 
  Edition, August 2005.
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, 
  Second Edition, June 2001.
API MPMS, Chapter 4, Proving Systems, Section 1:               250.198; 
  Introduction, Third Edition, February 2005.           250.1202(a)(3), 
                                                                  (f)(1)
API MPMS, Chapter 4, Section 2: Displacement                   250.198; 
  Provers, Third Edition, September 2003.               250.1202(a)(3), 
                                                                  (f)(1)
API MPMS, Chapter 4, Section 4, Tank Provers,                  250.198; 
  Second Edition, May 1998.                             250.1202(a)(3), 
                                                                  (f)(1)
API MPMS, Chapter 4, Section 5, Master-Meter                   250.198; 
  Provers, Second Edition, May 2000.                    250.1202(a)(3), 
                                                                  (f)(1)

[[Page 619]]

API MPMS, Chapter 4, Section 6, Proving Systems:               250.198; 
  Pulse Interpolation, Second Edition, 1999,         250.1202(a)(3) and 
  reaffirmed 2003.                                                (f)(1)
API MPMS, Chapter 4, Section 7, Proving Systems:               250.198; 
  Field Standard Test Measures, Second Edition,         250.1202(a)(3), 
  December 1998 reaffirmed 2003.                                  (f)(1)
API MPMS, Chapter 5: Metering, Section 1, General              250.198; 
  Considerations for Measurement by Meters,               250.1202(a)(3)
  Measurement Coordination Department, Fourth 
  Edition, September 2005.
API MPMS, Chapter 5, Section 2, Measurement of                 250.198; 
  Liquid Hydrocarbons by Displacement Meters,             250.1202(a)(3)
  Third Edition, September 2005.
API MPMS, Chapter 5, Section 3, Measurement of                 250.198; 
  Liquid Hydrocarbons by Turbine Meters, Fifth            250.1202(a)(3)
  Edition, September 2005,.
API MPMS, Chapter 5, Section 4, Accessory                      250.198; 
  Equipment for Liquid Meters, Fourth Edition,            250.1202(a)(3)
  September 2005.
API MPMS, Chapter 5, Section 5, Fidelity and                   250.198; 
  Security of Flow Measurement Pulsed-Data                250.1202(a)(3)
  Transmission Systems, Second Edition, August 
  2005.
API MPMS, Chapter 6, Metering Assemblies, Section              250.198; 
  1, Lease Automatic Custody Transfer (LACT)              250.1202(a)(3)
  Systems, Second Edition, May 1991, reaffirmed 
  March 2002.
API MPMS, Chapter 6, Section 6, Pipeline Metering              250.198; 
  Systems, Second Edition, May 1991, reaffirmed           250.1202(a)(3)
  March 2002.
API MPMS, Chapter 6, Section 7, Metering Viscous               250.198; 
  Hydrocarbons, Second Edition, May 1991,                 250.1202(a)(3)
  reaffirmed March 2002.
API MPMS, Chapter 7, Temperature Determination--               250.198; 
  Measurement Coordination, First edition, June         250.1202(a)(3), 
  2001.                                                           (l)(4)
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)
  reaffirmed March 2006.
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, reaffirmed June 2005.
API MPMS, Chapter 9, Density Determination,                    250.198; 
  Section 1, Standard Test Method for Density,          250.1202(a)(3); 
  Relative Density (Specific Gravity), or API             250.1202(l)(4)
  Gravity of Crude Petroleum and Liquid Petroleum 
  Products by Hydrometer Method, Second edition, 
  reaffirmed October 2005.
API MPMS Chapter 9, Section 2--Standard Test                   250.198; 
  Method for Density or Relative Density of Light       250.1202(a)(3); 
  Hydrocarbons by Pressure Hydrometer, Second             250.1202(l)(4)
  edition, March 2003.
API MPMS, Chapter 10, Sediment and Water, Section              250.198; 
  1, Standard Test Method for Sediment in Crude         250.1202(a)(3), 
  Oils and Fuel Oils by the Extraction Method,                    (l)(4)
  Second Edition, October 2002.
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 2005.                           (l)(4)
API MPMS, Chapter 10, Section 3, Standard Test                 250.198; 
  Method for Water and Sediment in Crude Oil by         250.1202(a)(3), 
  the Centrifuge Method (Laboratory Procedure),                   (l)(4)
  Second Edition, May 2003.
API MPMS, Chapter 10, Section 4, Determination of              250.198; 
  Water and/or Sediment in Crude Oil by the             250.1202(a)(3), 
  Centrifuge Method (Field Procedure), Third                      (l)(4)
Edition, December 1999.
[[Page 620]]

API MPMS, Chapter 10, Sediment and Water, Section              250.198; 
  9, Standard Test Method for Water in Crude Oils       250.1202(a)(3), 
  by Coulometric Karl Fischer Titration, Second                   (l)(4)
  Edition, reaffirmed 2005.
API MPMS, Chapter 11, Physical Properties Data,                250.198; 
  Addendum to Section 2, Part 2, Compressibility          250.1202(a)(3)
  Factors for Hydrocarbons, Correlation of Vapor 
  Pressure for Commercial Natural Gas Liquids, 
  First Edition, reaffirmed December 2002.
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[deg] F, and Table 6A--Generalized 
  Crude Oils and JP-4 Correction of Volume to 
  60[deg] F Against API Gravity at 60[deg] F, API 
  Standard 2540, First Edition, August 1980, 
  reaffirmed March 1997; API Stock No. H27000.
API MPMS, Chapter 11.2.2, Compressibility Factors              250.198; 
  for Hydrocarbons: 0.350-0.637 Relative Density        250.1202(a)(3), 
  (60[deg] F/60[deg] F) and -50[deg] F to 140[deg]                (g)(4)
  F Metering Temperature, Second Edition, October 
  1986, reaffirmed December 2002.
API MPMS, Chapter 12, Calculation of Petroleum         250.198; 250.1202
  Quantities, Section 2, Calculation of Petroleum 
  Quantities Using Dynamic Measurement Methods and 
  Volumetric Correction Factors, Part 1: 
  Introduction, Second Edition, May 1995 
  (Reaffirmed March 2002).
API MPMS, Chapter 12, Calculation of Petroleum         250.198; 250.1202
  Quantities, Section 2, Calculation of Petroleum 
  Quantities Using Dynamic Measurement Methods and 
  Volumetric Correction Factors, Part 2: 
  Measurement Tickets, Third Edition, June 2003.
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, 
  reaffirmed January 2003.
API MPMS, Chapter 14, Section 3, Part 2,                       250.198; 
  Specification and Installation Requirements,            250.1203(b)(2)
  Fourth Edition, reaffirmed March 2006.
API Chapter 14---Natural Gas Fluids Measurement,               250.198; 
  Section 3--Concentric, Square-Edged Orifice             250.1203(b)(2)
  Meters, Part 3--Natural Gas Applications, Third 
  Edition, reaffirmed January 2003.
API MPMS, Chapter 14.5, Calculation of Gross                   250.198; 
  Heating Value, Relative Density, and                    250.1203(b)(2)
  Compressibility Factor for Natural Gas Mixtures 
  from Compositional Analysis, Second Edition, 
  reaffirmed March 2002.
API MPMS, Chapter 14, Section 6, Continuous                    250.198; 
  Density Measurement, Second Edition, April 1991,        250.1203(b)(2)
  reaffirmed 2006.
API MPMS, Chapter 14, Section 8, Liquefied                     250.198; 
  Petroleum Gas Measurement, Second Edition, July         250.1203(b)(2)
  1997; reaffirmed March 2002.
API MPMS, Chapter 20, Section 1, Allocation                    250.198; 
  Measurement, First Edition, reaffirmed October          250.1202(k)(1)
  2006.
API MPMS, Chapter 21, Flow Measurement Using                   250.198; 
  Electronic Metering Systems, Section 1 -                250.1203(b)(4)
  Electronic Gas Measurement, First Edition, 
  reaffirmed July 2005.


The American Society for Testing and Materials

  100 Barr Harbor Drive, West Conshohocken, PA 
  19428-2959; Telephone: (610) 832-9585, FAX: 
  (610) 832-9555
ASTM Standard C 33-99a, Standard Specification for   250.198; 250.901(a)
  Concrete Aggregates.
ASTM Standard C94/C94M-99, Standard Specification    250.198; 250.901(a)
for Ready-Mixed Concrete.
[[Page 621]]

ASTM Standard C 150-99, Standard Specification for   250.198; 250.901(a)
  Portland Cement.
ASTM Standard C 330-99, Standard Specification for   250.198; 250.901(a)
  Lightweight Aggregates for Structural Concrete.
ASTM Standard C 595-98, Standard Specification for   250.198; 250.901(a)
  Blended Hydraulic Cements.


The American Welding Society

  550 NW LeJeune Road, P.O. Box 351040, Miami, 
  Florida 33135
AWS D1.1-2000, Structural Welding Code--Steel,       250.198; 250.901(a)
  2000.
AWS D1.4-98, Structural Welding Code--Reinforcing    250.198; 250.901(a)
  Steel, 1998.
ANSI/AWS D3.6M, Specification for Underwater         250.198; 250.901(a)
  Welding, 1999.


The National Association of Corrosion Engineers

  First Services Department, 1440 South Creek 
  Drive, Houston, Texas 77218
NACE Standard MR0175-2003, Standard Material         250.198; 250.901(a)
  Requirements: Metals for Sulfide Stress Cracking 
  and Stress Corrosion Cracking Resistance in Sour 
  Oilfield Environments, 2003.
NACE Standard RP 01-76-2003, Standard Recommended    250.198; 250.901(a)
  Practice, Corrosion Control of Steel Fixed 
  Offshore Structures Associated with Petroleum 
  Production.

[[Page 623]]



                    Table of CFR Titles and Chapters




                      (Revised as of July 1, 2007)

                      Title 1--General Provisions

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

                    Title 2--Grants and Agreements

            Subtitle A--Office of Management and Budget Guidance 
                for Grants and Agreements
         I  Office of Management and Budget Governmentwide 
                Guidance for Grants and Agreements (Parts 100-199)
        II  Office of Management and Budget Circulars and Guidance 
                (200-299)
            Subtitle B--Federal Agency Regulations for Grants and 
                Agreements
       III  Department of Health and Human Services (Part 376)
        VI  Department of State (Part 601)
      VIII  Department of Veterans Affairs (Part 801)
        IX  Department of Energy (Part 901)
        XI  Department of Defense (Part 1125)
       XIV  Department of the Interior (Part 1400)
        XV  Environmental Protection Agency (Part 1532)
     XVIII  National Aeronautics and Space Administration (Part 
                1880)
      XXII  Corporation for National and Community Service (Part 
                2200)
       XXV  National Science Foundation (Part 2520)
      XXVI  National Archives and Records Administration (Part 
                2600)
    XXVIII  Department of Justice (Part 2867)
     XXXII  National Endowment for the Arts (Part 3254)
    XXXIII  National Endowment for the Humanities (Part 3369)
      XXXV  Export-Import Bank of the United States (Part 3513)
    XXXVII  Peace Corps (Part 3700)

                        Title 3--The President

         I  Executive Office of the President (Parts 100--199)

[[Page 624]]

                           Title 4--Accounts

         I  Government Accountability Office (Parts 1--99)

                   Title 5--Administrative Personnel

         I  Office of Personnel Management (Parts 1--1199)
        II  Merit Systems Protection Board (Parts 1200--1299)
       III  Office of Management and Budget (Parts 1300--1399)
         V  The International Organizations Employees Loyalty 
                Board (Parts 1500--1599)
        VI  Federal Retirement Thrift Investment Board (Parts 
                1600--1699)
      VIII  Office of Special Counsel (Parts 1800--1899)
        IX  Appalachian Regional Commission (Parts 1900--1999)
        XI  Armed Forces Retirement Home (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)
     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)
        LV  National Endowment for the Arts (Part 6501)
       LVI  National Endowment for the Humanities (Part 6601)
      LVII  General Services Administration (Part 6701)

[[Page 625]]

     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)
      LXIV  Merit Systems Protection Board (Part 7401)
       LXV  Department of Housing and Urban Development (Part 
                7501)
      LXVI  National Archives and Records Administration (Part 
                7601)
     LXVII  Institute of Museum and Library Services (Part 7701)
      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)
     XCVII  Department of Homeland Security Human Resources 
                Management System (Department of Homeland 
                Security--Office of Personnel Management) (Part 
                9701)
      XCIX  Department of Defense Human Resources Management and 
                Labor Relations Systems (Department of Defense--
                Office of Personnel Management) (Part 9901)

                      Title 6--Domestic Security

         I  Department of Homeland Security, Office of the 
                Secretary (Parts 0--99)
         X  Privacy and Civil Liberties Oversight Board (Parts 
                1000)

                         Title 7--Agriculture

            Subtitle A--Office of the Secretary of Agriculture 
                (Parts 0--26)
            Subtitle B--Regulations of the Department of 
                Agriculture
         I  Agricultural Marketing Service (Standards, 
                Inspections, Marketing Practices), Department of 
                Agriculture (Parts 27--209)
        II  Food and Nutrition Service, Department of Agriculture 
                (Parts 210--299)
       III  Animal and Plant Health Inspection Service, Department 
                of Agriculture (Parts 300--399)
        IV  Federal Crop Insurance Corporation, Department of 
                Agriculture (Parts 400--499)
         V  Agricultural Research Service, Department of 
                Agriculture (Parts 500--599)
        VI  Natural Resources Conservation Service, Department of 
                Agriculture (Parts 600--699)
       VII  Farm Service Agency, Department of Agriculture (Parts 
                700--799)

[[Page 626]]

      VIII  Grain Inspection, Packers and Stockyards 
                Administration (Federal Grain Inspection Service), 
                Department of Agriculture (Parts 800--899)
        IX  Agricultural Marketing Service (Marketing Agreements 
                and Orders; Fruits, Vegetables, Nuts), Department 
                of Agriculture (Parts 900--999)
         X  Agricultural Marketing Service (Marketing Agreements 
                and Orders; Milk), Department of Agriculture 
                (Parts 1000--1199)
        XI  Agricultural Marketing Service (Marketing Agreements 
                and Orders; Miscellaneous Commodities), Department 
                of Agriculture (Parts 1200--1299)
       XIV  Commodity Credit Corporation, Department of 
                Agriculture (Parts 1400--1499)
        XV  Foreign Agricultural Service, Department of 
                Agriculture (Parts 1500--1599)
       XVI  Rural Telephone Bank, Department of Agriculture (Parts 
                1600--1699)
      XVII  Rural Utilities Service, Department of Agriculture 
                (Parts 1700--1799)
     XVIII  Rural Housing Service, Rural Business-Cooperative 
                Service, Rural Utilities Service, and Farm Service 
                Agency, Department of Agriculture (Parts 1800--
                2099)
        XX  Local Television Loan Guarantee Board (Parts 2200--
                2299)
      XXVI  Office of Inspector General, Department of Agriculture 
                (Parts 2600--2699)
     XXVII  Office of Information Resources Management, Department 
                of Agriculture (Parts 2700--2799)
    XXVIII  Office of Operations, Department of Agriculture (Parts 
                2800--2899)
      XXIX  Office of Energy Policy and New Uses, Department of 
                Agriculture (Parts 2900--2999)
       XXX  Office of the Chief Financial Officer, Department of 
                Agriculture (Parts 3000--3099)
      XXXI  Office of Environmental Quality, Department of 
                Agriculture (Parts 3100--3199)
     XXXII  Office of Procurement and Property Management, 
                Department of Agriculture (Parts 3200--3299)
    XXXIII  Office of Transportation, Department of Agriculture 
                (Parts 3300--3399)
     XXXIV  Cooperative State Research, Education, and Extension 
                Service, Department of Agriculture (Parts 3400--
                3499)
      XXXV  Rural Housing Service, Department of Agriculture 
                (Parts 3500--3599)
     XXXVI  National Agricultural Statistics Service, Department 
                of Agriculture (Parts 3600--3699)
    XXXVII  Economic Research Service, Department of Agriculture 
                (Parts 3700--3799)
   XXXVIII  World Agricultural Outlook Board, Department of 
                Agriculture (Parts 3800--3899)
       XLI  [Reserved]

[[Page 627]]

      XLII  Rural Business-Cooperative Service and Rural Utilities 
                Service, Department of Agriculture (Parts 4200--
                4299)

                    Title 8--Aliens and Nationality

         I  Department of Homeland Security (Immigration and 
                Naturalization) (Parts 1--499)
         V  Executive Office for Immigration Review, Department of 
                Justice (Parts 1000--1399)

                 Title 9--Animals and Animal Products

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

                           Title 10--Energy

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

[[Page 628]]

        XI  Federal Financial Institutions Examination Council 
                (Parts 1100--1199)
       XIV  Farm Credit System Insurance Corporation (Parts 1400--
                1499)
        XV  Department of the Treasury (Parts 1500--1599)
      XVII  Office of Federal Housing Enterprise Oversight, 
                Department of Housing and Urban Development (Parts 
                1700--1799)
     XVIII  Community Development Financial Institutions Fund, 
                Department of the Treasury (Parts 1800--1899)

               Title 13--Business Credit and Assistance

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

                    Title 14--Aeronautics and Space

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

                 Title 15--Commerce and Foreign Trade

            Subtitle A--Office of the Secretary of Commerce (Parts 
                0--29)
            Subtitle B--Regulations Relating to Commerce and 
                Foreign Trade
         I  Bureau of the Census, Department of Commerce (Parts 
                30--199)
        II  National Institute of Standards and Technology, 
                Department of Commerce (Parts 200--299)
       III  International Trade Administration, Department of 
                Commerce (Parts 300--399)
        IV  Foreign-Trade Zones Board, Department of Commerce 
                (Parts 400--499)
       VII  Bureau of Industry and Security, Department of 
                Commerce (Parts 700--799)
      VIII  Bureau of Economic Analysis, Department of Commerce 
                (Parts 800--899)

[[Page 629]]

        IX  National Oceanic and Atmospheric Administration, 
                Department of Commerce (Parts 900--999)
        XI  Technology Administration, Department of Commerce 
                (Parts 1100--1199)
      XIII  East-West Foreign Trade Board (Parts 1300--1399)
       XIV  Minority Business Development Agency (Parts 1400--
                1499)
            Subtitle C--Regulations Relating to Foreign Trade 
                Agreements
        XX  Office of the United States Trade Representative 
                (Parts 2000--2099)
            Subtitle D--Regulations Relating to Telecommunications 
                and Information
     XXIII  National Telecommunications and Information 
                Administration, Department of Commerce (Parts 
                2300--2399)

                    Title 16--Commercial Practices

         I  Federal Trade Commission (Parts 0--999)
        II  Consumer Product Safety Commission (Parts 1000--1799)

             Title 17--Commodity and Securities Exchanges

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

          Title 18--Conservation of Power and Water Resources

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

                       Title 19--Customs Duties

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

[[Page 630]]

                     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 (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)
       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 631]]

                          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--1699)
         X  Office of Assistant Secretary for Housing--Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Interstate Land Sales 
                Registration Program) (Parts 1700--1799)
       XII  Office of Inspector General, Department of Housing and 
                Urban Development (Parts 2000--2099)
        XX  Office of Assistant Secretary for Housing--Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Parts 3200--3899)
       XXV  Neighborhood Reinvestment Corporation (Parts 4100--
                4199)

[[Page 632]]

                           Title 25--Indians

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

                      Title 26--Internal Revenue

         I  Internal Revenue Service, Department of the Treasury 
                (Parts 1--899)

           Title 27--Alcohol, Tobacco Products and Firearms

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

                   Title 28--Judicial Administration

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

                            Title 29--Labor

            Subtitle A--Office of the Secretary of Labor (Parts 
                0--99)
            Subtitle B--Regulations Relating to Labor
         I  National Labor Relations Board (Parts 100--199)

[[Page 633]]

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

                      Title 30--Mineral Resources

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

                 Title 31--Money and Finance: Treasury

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

[[Page 634]]

        IX  Federal Claims Collection Standards (Department of the 
                Treasury--Department of Justice) (Parts 900--999)

                      Title 32--National Defense

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

               Title 33--Navigation and Navigable Waters

         I  Coast Guard, Department of Homeland Security (Parts 
                1--199)
        II  Corps of Engineers, Department of the Army (Parts 
                200--399)
        IV  Saint Lawrence Seaway Development Corporation, 
                Department of Transportation (Parts 400--499)

                          Title 34--Education

            Subtitle A--Office of the Secretary, Department of 
                Education (Parts 1--99)
            Subtitle B--Regulations of the Offices of the 
                Department of Education
         I  Office for Civil Rights, Department of Education 
                (Parts 100--199)
        II  Office of Elementary and Secondary Education, 
                Department of Education (Parts 200--299)
       III  Office of Special Education and Rehabilitative 
                Services, Department of Education (Parts 300--399)
        IV  Office of Vocational and Adult Education, Department 
                of Education (Parts 400--499)
         V  Office of Bilingual Education and Minority Languages 
                Affairs, Department of Education (Parts 500--599)
        VI  Office of Postsecondary Education, Department of 
                Education (Parts 600--699)

[[Page 635]]

        XI  National Institute for Literacy (Parts 1100--1199)
            Subtitle C--Regulations Relating to Education
       XII  National Council on Disability (Parts 1200--1299)

                          Title 35 [Reserved]

             Title 36--Parks, Forests, and Public Property

         I  National Park Service, Department of the Interior 
                (Parts 1--199)
        II  Forest Service, Department of Agriculture (Parts 200--
                299)
       III  Corps of Engineers, Department of the Army (Parts 
                300--399)
        IV  American Battle Monuments Commission (Parts 400--499)
         V  Smithsonian Institution (Parts 500--599)
       VII  Library of Congress (Parts 700--799)
      VIII  Advisory Council on Historic Preservation (Parts 800--
                899)
        IX  Pennsylvania Avenue Development Corporation (Parts 
                900--999)
         X  Presidio Trust (Parts 1000--1099)
        XI  Architectural and Transportation Barriers Compliance 
                Board (Parts 1100--1199)
       XII  National Archives and Records Administration (Parts 
                1200--1299)
        XV  Oklahoma City National Memorial Trust (Part 1501)
       XVI  Morris K. Udall Scholarship and Excellence in National 
                Environmental Policy Foundation (Parts 1600--1699)

             Title 37--Patents, Trademarks, and Copyrights

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

           Title 38--Pensions, Bonuses, and Veterans' Relief

         I  Department of Veterans Affairs (Parts 0--99)

                       Title 39--Postal Service

         I  United States Postal Service (Parts 1--999)
       III  Postal Rate Commission (Parts 3000--3099)

                  Title 40--Protection of Environment

         I  Environmental Protection Agency (Parts 1--1099)

[[Page 636]]

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

          Title 41--Public Contracts and Property Management

            Subtitle B--Other Provisions Relating to Public 
                Contracts
        50  Public Contracts, Department of Labor (Parts 50-1--50-
                999)
        51  Committee for Purchase From People Who Are Blind or 
                Severely Disabled (Parts 51-1--51-99)
        60  Office of Federal Contract Compliance Programs, Equal 
                Employment Opportunity, Department of Labor (Parts 
                60-1--60-999)
        61  Office of the Assistant Secretary for Veterans' 
                Employment and Training Service, Department of 
                Labor (Parts 61-1--61-999)
            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 303-1--303-99)
       304  Payment of Travel Expenses from a Non-Federal Source 
                (Parts 304-1--304-99)

                        Title 42--Public Health

         I  Public Health Service, Department of Health and Human 
                Services (Parts 1--199)

[[Page 637]]

        IV  Centers for Medicare & Medicaid Services, Department 
                of Health and Human Services (Parts 400--499)
         V  Office of Inspector General-Health Care, Department of 
                Health and Human Services (Parts 1000--1999)

                   Title 43--Public Lands: Interior

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

             Title 44--Emergency Management and Assistance

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

                       Title 45--Public Welfare

            Subtitle A--Department of Health and Human Services 
                (Parts 1--199)
            Subtitle B--Regulations Relating to Public Welfare
        II  Office of Family Assistance (Assistance Programs), 
                Administration for Children and Families, 
                Department of Health and Human Services (Parts 
                200--299)
       III  Office of Child Support Enforcement (Child Support 
                Enforcement Program), Administration for Children 
                and Families, Department of Health and Human 
                Services (Parts 300--399)
        IV  Office of Refugee Resettlement, Administration for 
                Children and Families, Department of Health and 
                Human Services (Parts 400--499)
         V  Foreign Claims Settlement Commission of the United 
                States, Department of Justice (Parts 500--599)
        VI  National Science Foundation (Parts 600--699)
       VII  Commission on Civil Rights (Parts 700--799)
      VIII  Office of Personnel Management (Parts 800--899)
         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)

[[Page 638]]

      XIII  Office of Human Development Services, Department of 
                Health and Human Services (Parts 1300--1399)
       XVI  Legal Services Corporation (Parts 1600--1699)
      XVII  National Commission on Libraries and Information 
                Science (Parts 1700--1799)
     XVIII  Harry S. Truman Scholarship Foundation (Parts 1800--
                1899)
       XXI  Commission on Fine Arts (Parts 2100--2199)
     XXIII  Arctic Research Commission (Part 2301)
      XXIV  James Madison Memorial Fellowship Foundation (Parts 
                2400--2499)
       XXV  Corporation for National and Community Service (Parts 
                2500--2599)

                          Title 46--Shipping

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

                      Title 47--Telecommunication

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

           Title 48--Federal Acquisition Regulations System

         1  Federal Acquisition Regulation (Parts 1--99)
         2  Defense Acquisition Regulations System, Department of 
                Defense (Parts 200--299)
         3  Department of Health and Human Services (Parts 300--
                399)
         4  Department of Agriculture (Parts 400--499)
         5  General Services Administration (Parts 500--599)
         6  Department of State (Parts 600--699)
         7  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)

[[Page 639]]

        16  Office of Personnel Management, Federal Employees 
                Health Benefits Acquisition Regulation (Parts 
                1600--1699)
        17  Office of Personnel Management (Parts 1700--1799)
        18  National Aeronautics and Space Administration (Parts 
                1800--1899)
        19  Broadcasting Board of Governors (Parts 1900--1999)
        20  Nuclear Regulatory Commission (Parts 2000--2099)
        21  Office of Personnel Management, Federal Employees' 
                Group Life Insurance Federal Acquisition 
                Regulation (Parts 2100--2199)
        23  Social Security Administration (Parts 2300--2399)
        24  Department of Housing and Urban Development (Parts 
                2400--2499)
        25  National Science Foundation (Parts 2500--2599)
        28  Department of Justice (Parts 2800--2899)
        29  Department of Labor (Parts 2900--2999)
        30  Department of Homeland Security, Homeland Security 
                Acquisition Regulation (HSAR) (Parts 3000--3099)
        34  Department of Education Acquisition Regulation (Parts 
                3400--3499)
        35  [Reserved]
        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 (Parts 
                5400--5499)
        57  African Development Foundation (Parts 5700--5799)
        61  General Services Administration Board of Contract 
                Appeals (Parts 6100--6199)
        63  Department of Transportation Board of Contract Appeals 
                (Parts 6300--6399)
        99  Cost Accounting Standards Board, Office of Federal 
                Procurement Policy, Office of Management and 
                Budget (Parts 9900--9999)

                       Title 49--Transportation

            Subtitle A--Office of the Secretary of Transportation 
                (Parts 1--99)
            Subtitle B--Other Regulations Relating to 
                Transportation
         I  Pipeline and Hazardous Materials Safety 
                Administration, Department of Transportation 
                (Parts 100--199)
        II  Federal Railroad Administration, Department of 
                Transportation (Parts 200--299)
       III  Federal Motor Carrier Safety Administration, 
                Department of Transportation (Parts 300--399)

[[Page 640]]

        IV  Coast Guard, Department of Homeland Security (Parts 
                400--499)
         V  National Highway Traffic Safety Administration, 
                Department of Transportation (Parts 500--599)
        VI  Federal Transit Administration, Department of 
                Transportation (Parts 600--699)
       VII  National Railroad Passenger Corporation (AMTRAK) 
                (Parts 700--799)
      VIII  National Transportation Safety Board (Parts 800--999)
         X  Surface Transportation Board, Department of 
                Transportation (Parts 1000--1399)
        XI  Research and Innovative Technology Administration, 
                Department of Transportation [Reserved]
       XII  Transportation Security Administration, Department of 
                Homeland Security (Parts 1500--1699)

                   Title 50--Wildlife and Fisheries

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

                      CFR Index and Finding Aids

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

[[Page 641]]





           Alphabetical List of Agencies Appearing in the CFR




                      (Revised as of July 1, 2007)

                                                  CFR Title, Subtitle or 
                     Agency                               Chapter

Administrative Committee of the Federal Register  1, I
Advanced Research Projects Agency                 32, I
Advisory Council on Historic Preservation         36, VIII
African Development Foundation                    22, XV
  Federal Acquisition Regulation                  48, 57
Agency for International Development, 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
Air Transportation Stabilization Board            14, VI
Alcohol and Tobacco Tax and Trade Bureau          27, I
Alcohol, Tobacco, Firearms, and Explosives,       27, II
     Bureau of
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

[[Page 642]]

Architectural and Transportation Barriers         36, XI
     Compliance Board
Arctic Research Commission                        45, XXIII
Armed Forces Retirement Home                      5, XI
Army Department                                   32, V
  Engineers, Corps of                             33, II; 36, III
  Federal Acquisition Regulation                  48, 51
Benefits Review Board                             20, VII
Bilingual Education and Minority Languages        34, V
     Affairs, Office of
Blind or Severely Disabled, Committee for         41, 51
     Purchase From People Who Are
Broadcasting Board of Governors                   22, V
  Federal Acquisition Regulation                  48, 19
Census Bureau                                     15, I
Centers for Medicare & Medicaid Services          42, IV
Central Intelligence Agency                       32, XIX
Chief Financial Officer, Office of                7, XXX
Child Support Enforcement, Office of              45, III
Children and Families, Administration for         45, II, III, IV, X
Civil Rights, Commission on                       45, VII
Civil Rights, Office for                          34, I
Coast Guard                                       33, I; 46, I; 49, IV
Coast Guard (Great Lakes Pilotage)                46, III
Commerce Department                               44, IV
  Census Bureau                                   15, I
  Economic Affairs, Under Secretary               37, V
  Economic Analysis, Bureau of                    15, VIII
  Economic Development Administration             13, III
  Emergency Management and Assistance             44, IV
  Federal Acquisition Regulation                  48, 13
  Fishery Conservation and Management             50, VI
  Foreign-Trade Zones Board                       15, IV
  Industry and Security, Bureau of                15, VII
  International Trade Administration              15, III; 19, III
  National Institute of Standards and Technology  15, II
  National Marine Fisheries Service               50, II, IV, VI
  National Oceanic and Atmospheric                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, United States      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
Copyright Royalty Board                           37, III
Corporation for National and Community Service    45, XII, XXV
Cost Accounting Standards Board                   48, 99
Council on Environmental Quality                  40, V
Court Services and Offender Supervision Agency    28, VIII
     for the District of Columbia
Customs and Border Protection Bureau              19, I
Defense Contract Audit Agency                     32, I
Defense Department                                2, XI; 5, XXVI; 32, 
                                                  Subtitle A; 40, VII

[[Page 643]]

  Advanced Research Projects Agency               32, I
  Air Force Department                            32, VII
  Army Department                                 32, V; 33, II; 36, III, 
                                                  48, 51
  Defense Acquisition Regulations System          48, II
  Defense Intelligence Agency                     32, I
  Defense Logistics Agency                        32, I, XII; 48, 54
  Engineers, Corps of                             33, II; 36, III
  National Imagery and Mapping Agency             32, I
  Navy Department                                 32, VI; 48, 52
  Secretary of Defense, Office of                 32, I
Defense Contract Audit Agency                     32, I
Defense Intelligence Agency                       32, I
Defense Logistics Agency                          32, XII; 48, 54
Defense Nuclear Facilities Safety Board           10, XVII
Delaware River Basin Commission                   18, III
District of Columbia, Court Services and          28, VIII
     Offender Supervision Agency for the
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
Employee Benefits Security Administration         29, XXV
Employees' Compensation Appeals Board             20, IV
Employees Loyalty Board                           5, V
Employment and Training Administration            20, V
Employment Standards Administration               20, VI
Endangered Species Committee                      50, IV
Energy, Department of                             2, IX; 5, XXIII; 10, II, 
                                                  III, X
  Federal Acquisition Regulation                  48, 9
  Federal Energy Regulatory Commission            5, XXIV; 18, I
  Property Management Regulations                 41, 109
Energy, Office of                                 7, XXIX
Engineers, Corps of                               33, II; 36, III
Engraving and Printing, Bureau of                 31, VI
Environmental Protection Agency                   2, XV; 5, LIV; 40, I, IV, 
                                                  VII
  Federal Acquisition Regulation                  48, 15
  Property Management Regulations                 41, 115
Environmental Quality, Office of                  7, XXXI
Equal Employment Opportunity Commission           5, LXII; 29, XIV
Equal Opportunity, Office of Assistant Secretary  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                5, III, LXXVII; 14, VI; 
                                                  48, 99
  National Drug Control Policy, Office of         21, III
  National Security Council                       32, XXI; 47, 2

[[Page 644]]

  Presidential Documents                          3
  Science and Technology Policy, Office of        32, XXIV; 47, II
  Trade Representative, Office of the United      15, XX
       States
Export-Import Bank of the United States           2, XXXV; 5, LII; 12, IV
Family Assistance, Office of                      45, II
Farm Credit Administration                        5, XXXI; 12, VI
Farm Credit System Insurance Corporation          5, XXX; 12, XIV
Farm Service Agency                               7, VII, XVIII
Federal Acquisition Regulation                    48, 1
Federal Aviation Administration                   14, I
  Commercial Space Transportation                 14, III
Federal Claims Collection Standards               31, IX
Federal Communications Commission                 5, XXIX; 47, I
Federal Contract Compliance Programs, Office of   41, 60
Federal Crop Insurance Corporation                7, IV
Federal Deposit Insurance Corporation             5, XXII; 12, III
Federal Election Commission                       11, I
Federal Emergency Management Agency               44, I
  Federal 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 Services Administration                   5, LVII; 41, 105
  Contract Appeals, Board of                      48, 61

[[Page 645]]

  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
  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 Accountability Office                  4, I
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          2, III; 5, XLV; 45, 
                                                  Subtitle A
  Centers for Medicare & Medicaid Services        42, IV
  Child Support Enforcement, Office of            45, III
  Children and Families, Administration for       45, II, III, IV, X
  Community Services, Office of                   45, X
  Defense Acquisition Regulations System          48, 2
  Family Assistance, Office of                    45, II
  Federal Acquisition Regulation                  48, 3
  Food and Drug Administration                    21, I
  Human Development Services, Office of           45, XIII
  Indian Health Service                           25, V; 42, I
  Inspector General (Health Care), Office of      42, V
  Public Health Service                           42, I
  Refugee Resettlement, Office of                 45, IV
Homeland Security, Department of                  6, I
  Coast Guard                                     33, I; 46, I; 49, IV
  Coast Guard (Great Lakes Pilotage)              46, III
  Customs and Border Protection Bureau            19, I
  Federal Emergency Management Agency             44, I
  Immigration and Customs Enforcement Bureau      19, IV
  Immigration and Naturalization                  8, I
  Transportation Security Administration          49, XII
Housing and Urban Development, Department of      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
  Housing, Office of, and Multifamily Housing     24, IV
       Assistance Restructuring, Office of
  Inspector General, Office of                    24, XII
  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
Housing, Office of, and Multifamily Housing       24, IV
     Assistance Restructuring, Office of
Human Development Services, Office of             45, XIII
Immigration and Customs Enforcement Bureau        19, IV
Immigration and Naturalization                    8, I
Immigration Review, Executive Office for          8, V
Independent Counsel, Office of                    28, VII
Indian Affairs, Bureau of                         25, I, V
Indian Affairs, Office of the Assistant           25, VI
     Secretary
Indian Arts and Crafts Board                      25, II
Indian Health Service                             25, V; 42, I
Industry and Security, Bureau of                  15, VII

[[Page 646]]

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
Interior Department                               2, XIV
  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
  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                                2, XXVIII; 5, XXVIII; 28, 
                                                  I, XI; 40, IV
  Alcohol, Tobacco, Firearms, and Explosives,     27, II
       Bureau of
  Drug Enforcement Administration                 21, II
  Federal Acquisition Regulation                  48, 28
  Federal Claims Collection Standards             31, IX
  Federal Prison Industries, Inc.                 28, III
  Foreign Claims Settlement Commission of the     45, V
       United States
  Immigration Review, Executive Office for        8, V
  Offices of Independent Counsel                  28, VI
  Prisons, Bureau of                              28, V
  Property Management Regulations                 41, 128
Labor Department                                  5, XLII
  Benefits Review Board                           20, VII
  Employee Benefits Security Administration       29, XXV
  Employees' Compensation Appeals Board           20, IV
  Employment and Training Administration          20, V
  Employment Standards Administration             20, VI
  Federal Acquisition Regulation                  48, 29
  Federal Contract Compliance Programs, Office    41, 60
       of
  Federal Procurement Regulations System          41, 50
  Labor-Management Standards, Office of           29, II, IV

[[Page 647]]

  Mine Safety and Health Administration           30, I
  Occupational Safety and Health Administration   29, XVII
  Public Contracts                                41, 50
  Secretary of Labor, Office of                   29, Subtitle A
  Veterans' Employment and Training Service,      41, 61; 20, IX
       Office of 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
  Copyright Royalty Board                         37, III
Local Television Loan Guarantee Board             7, XX
Management and Budget, Office of                  5, III, LXXVII; 14, VI; 
                                                  48, 99
Marine Mammal Commission                          50, V
Maritime Administration                           46, II
Merit Systems Protection Board                    5, II; 5, LXIV
Micronesian Status Negotiations, Office for       32, XXVII
Mine Safety and Health Administration             30, I
Minerals Management Service                       30, II
Minority Business Development Agency              15, XIV
Miscellaneous Agencies                            1, IV
Monetary Offices                                  31, I
Morris K. Udall Scholarship and Excellence in     36, XVI
     National Environmental Policy Foundation
National Aeronautics and Space Administration     2, XVIII; 5, LIX; 14, V
  Federal Acquisition Regulation                  48, 18
National Agricultural Library                     7, XLI
National Agricultural Statistics Service          7, XXXVI
National and Community Service, Corporation for   2, XXII; 45, XII, XXV
National Archives and Records Administration      2, XXVI; 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 Crime Prevention and Privacy Compact     28, IX
     Council
National Drug Control Policy, Office of           21, III
National Endowment for the Arts                   2, XXXII
National Endowment for the Humanities             2, XXXIII
National Foundation on the Arts and the           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                       2, XXV; 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
[[Page 648]]

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 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
Patent and Trademark Office, United States        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                                       2, XXXVII; 22, III
Pennsylvania Avenue Development Corporation       36, IX
Pension Benefit Guaranty Corporation              29, XL
Personnel Management, Office of                   5, I, XXXV; 45, VIII
  Federal Acquisition Regulation                  48, 17
  Federal Employees Group Life Insurance Federal  48, 21
       Acquisition Regulation
  Federal Employees Health Benefits Acquisition   48, 16
       Regulation
Pipeline and Hazardous Materials Safety           49, I
     Administration
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
Privacy and Civil Liberties Oversight Board       6, X
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 Innovative Technology                49, XI
     Administration
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

[[Page 649]]

Special Education and Rehabilitative Services,    34, III
     Office of
State Department                                  2, VI; 22, I; 28, XI
  Federal Acquisition Regulation                  48, 6
Surface Mining and Reclamation Appeals, Board of  30, III
Surface Mining Reclamation and Enforcement,       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
  Commercial Space Transportation                 14, III
  Contract Appeals, Board of                      48, 63
  Emergency Management and Assistance             44, IV
  Federal Acquisition Regulation                  48, 12
  Federal Aviation Administration                 14, I
  Federal Highway Administration                  23, I, II
  Federal Motor Carrier Safety Administration     49, III
  Federal Railroad Administration                 49, II
  Federal Transit Administration                  49, VI
  Maritime Administration                         46, II
  National Highway Traffic Safety Administration  23, II, III; 49, V
  Pipeline and Hazardous Materials Safety         49, I
       Administration
  Saint Lawrence Seaway Development Corporation   33, IV
  Secretary of Transportation, Office of          14, II; 49, Subtitle A
  Surface Transportation Board                    49, X
  Transportation Statistics Bureau                49, XI
Transportation, Office of                         7, XXXIII
Transportation Security Administration            49, XII
Transportation Statistics Bureau                  49, XI
Travel Allowances, Temporary Duty (TDY)           41, 301
Treasury Department                               5, XXI; 12, XV; 17, IV; 
                                                  31, IX
  Alcohol and Tobacco Tax and Trade Bureau        27, I
  Community Development Financial Institutions    12, XVIII
       Fund
  Comptroller of the Currency                     12, I
  Customs and Border Protection Bureau            19, I
  Engraving and Printing, Bureau of               31, VI
  Federal Acquisition Regulation                  48, 10
  Federal 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                       2, VIII; 38, I
  Federal Acquisition Regulation                  48, 8
Veterans' Employment and Training Service,        41, 61; 20, IX
     Office of the 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 651]]



List of CFR Sections Affected



All changes in this volume of the Code of Federal Regulations that were 
made by documents published in the Federal Register since January 1, 
2001, are enumerated in the following list. Entries indicate the nature 
of the changes effected. Page numbers refer to Federal Register pages. 
The user should consult the entries for chapters and parts as well as 
sections for revisions.
For the period before January 1, 2001, see the ``List of Sections 
Affected, 1949-1963, 1964-1972, 1973-1985, and 1986-2000,'' published in 
11 separate volumes.

                                  2001

30 CFR
                                                                   66 FR
                                                                    Page
Chapter II
206.251 Amended....................................................45769
206.254 (a) removed; (b) designation removed and amended...........45769
206.257 (d)(3) amended.............................................45769
206.259 (a)(1), (b)(1), (c)(1)(i), (2)(i), (d)(1), (e)(1) and (2) 
        amended....................................................45769
206.262 (a)(1), (b)(1), (c)(1)(i), (2)(i), (d)(1), (e)(1) and (2) 
        amended....................................................45769
206.263 Removed....................................................45769
206.453 (a) removed; (b) designation removed and amended...........45769
206.456 (d)(3) amended.............................................45769
206.458 (c)(1)(i), (2)(i), (4), (d)(1), (e)(1) and (2) amended.....45769
206.461 (c)(1)(i), (2)(i), (4), (d)(1), (e)(1) and (2) amended.....45769
206.462 Removed....................................................45769
208.4 (b)(4) removed...............................................28657
210.10 Nomenclature change; (a) and (d) revised; (b)(2) and (3) 
        amended; (b)(6), (c)(4), (11) and (12) removed; (c)(5) 
        through (10) and (13) through through (20) redesignated as 
        new (c)(4) through (9) and (10) through (17); (b)(6), (7), 
        (8) and new (c)(18) through (21) added.....................45769
210.200--210.204 (Subpart E) Removed; new 210.200--210.206 
        (Subpart E) added..........................................45771
210.201 (c)(3)(i) corrected........................................50827
216.2 Amended......................................................45773
216.6 Amended......................................................45773
216.20 Amended.....................................................45773
216.40 (d) removed; (e), (f) and (g) redesignated as (d), (e) and 
        (f)........................................................45773
216.200--216.204 (Subpart E) removed...............................45773
218 Authority citation revised.....................................45773
218.40 (c) revised.................................................45773
218.51 (d)(2), (3) and (e) amended.................................45773
218.151 Heading, (a) and (b) revised; introductory text added; (c) 
        and (d) removed; (e) redesignated as new (c)...............11518
218.201 Revised....................................................45773
218.203 (a) and (b) amended........................................45773
    (b) corrected..................................................50827
256.14 Removed.....................................................32904
256.40 Introductory text revised...................................11518
256.52 (b)(1) revised; (d), (e), (g) introductory text, (1) and 
        (2) amended................................................60150
256.58 Revised.....................................................60150
260 Revised........................................................11518

                                  2002

30 CFR
                                                                   67 FR
                                                                    Page
Chapter II
201.100 Heading amended............................................19111
203.0 Amended.......................................................1872
203.2 Revised.......................................................1872
203.4 Revised.......................................................1873
203.60 Revised......................................................1875
203.62 Introductory text and (c) revised............................1875

[[Page 652]]

203.63 Introductory text, (a), (b) and (c) redesignated as (a), 
        (1), (2) and (3); new (b) added.............................1875
203.64 Heading revised; introductory text amended...................1875
203.65 (b) revised..................................................1875
203.66 Revised......................................................1875
203.67 Revised......................................................1876
203.68 (b) revised..................................................1876
203.69 Introductory text and (b) through (e) revised; (f) added.....1876
203.70 Revised......................................................1876
203.71 Introductory text, (a), (b) and (c) revised..................1877
203.74 (b) and (c) redesignated as (c) and (d); introductory text, 
        new (c) and (d) revised; new (b) added......................1878
203.76 (a), (b) and (c) revised.....................................1878
203.77 Revised......................................................1878
203.78 Introductory text, (a)(1), (b)(1) and (f) revised............1878
203.80 Added........................................................1879
203.81 (a) and (c) revised..........................................1879
203.83 (c) revised..................................................1879
203.86 (b)(6), (7), (d)(6) and (7) amended; (b)(8) and (d)(8) 
        added; (c)(4) revised.......................................1879
203.87 (a)(1) and (d) revised.......................................1880
203.89 (a) revised..................................................1880
203.91 Amended......................................................1880
206.52 (e)(2) amended..............................................19111
206.103 (b)(2)(iii) amended........................................19111
206.152 (e)(3) amended.............................................19111
206.153 (e)(3) amended.............................................19111
206.250 (c) amended................................................19111
206.352 (e)(3) amended.............................................19111
206.355 (e)(3) amended.............................................19111
206.356 (d)(3) amended.............................................19111
212 Authority citation revised.....................................19111
212.51 (a) amended.................................................19111
212.351 (a) and (c) amended........................................19111
216.6 Amended......................................................19111
216.15 (a) and (b) amended.........................................19111
216.16 (a) and (b) amended.........................................19111
216.21 Amended.....................................................19111
216.30 Amended.....................................................19112
217.200 Amended....................................................19112
218.51 (g)(1) and (h)(2) amended...................................19112
218.53 (b) amended.................................................19112
218.102 (b) amended................................................19112
218.150 (c) amended................................................19112
218.151 (c) amended................................................19112
218.155 (a) and (d)(3) amended.....................................19112
218.202 (b) amended................................................19112
218.302 (b) amended................................................19112
219.102 Amended....................................................19112
220.011 (c)(1) amended.............................................19112
227.103 Amended....................................................19112
227.110 (b) amended................................................19112
227.401 (f) amended................................................19112
227.501 (c) amended................................................19112
228.6 Amended......................................................19112
230 Removed........................................................19112
241 Authority citation revised.....................................19112
241.54 Amended.....................................................19112
241.56 (b) amended.................................................19113
241.62 Amended.....................................................19113
241.64 (b) amended.................................................19113
243 Heading revised................................................19113
243.3 Amended......................................................19113
250.102 (b) table amended; eff. 7-16-02............................35405
250.175 Existing text designated as (a); (b) added.................44360
250.198 (d) table and (e) table amended............................51759
250.199 (e) table amended; eff. 7-16-02............................35405
250.700--250.704 (Subpart G) Removed; eff. 7-16-02.................35405
250.802 (b) and (e)(2) revised.....................................51759
250.803 (a), (b)(4) introductory text, (5)(i), (7), (9)(v) and 
        (c)(2) introductory text revised; (b)(2)(i), (10) and (d) 
        amended....................................................51759
250.804 (a)(3) introductory text revised; (a)(4) through (11) 
        redesignated as (a)(5) through (12); new (a)(4) added; (a) 
        introductory text, new (a)(5) and (10) amended.............51760
250.913 Removed; eff. 7-16-02......................................35405
250.1001 Amended; eff. 7-16-02.....................................35405
250.1002 (d) amended...............................................51760
250.1004 (b)(9) amended............................................51760
250.1006 Revised; eff. 7-16-02.....................................35405
250.1007 (c) removed; eff. 7-16-02.................................35406
250.1014 Amended; eff. 7-16-02.....................................35406
250.1604 (c) and (d) amended.......................................51760
250.1628 (c) and (d)(2) revised....................................51760
250.1629 (b)(2) and (4)(v) revised.................................51760
250.1630 (a) introductory text and (2) introductory text revised; 
        (a)(3), (4) and (5) redesignated as (a)(4), (5) and (6); 
        new (a)(3) added...........................................51761
250.1700--250.1754 (Subpart Q) Added; eff. 7-16-02.................35406

[[Page 653]]

    250.1700 (c) corrected.........................................66047
250.1704 Table correctly added.....................................44265
    (f) correctly designated as (g); new (f) correctly added; 
table corrected; new (g) correctly revised.........................66047
250.1712 Introductory text corrected; (e) and (f)(14) correctly 
        revised....................................................66048
250.1715 Table correctly added.....................................44265
    (a)(1) through (4) correctly revised; (a)(10) correctly added 
                                                                   66048
250.1717 Introductory text correctly revised.......................66049
250.1721 Undesignated center heading, heading and introductory 
        text corrected; (a) and (g) introductory text amended......66049
250.1722 Introductory text, (c) and (g) introductory text 
        corrected; (a) and (d) introductory text amended...........66049
250.1723 Introductory text corrected; (b) amended..................66049
250.1726 Introductory text correctly revised.......................66049
250.1740 (a) correctly removed; (b) correctly redesignated as (a); 
        new (b) correctly added; (a) introductory text and (c) 
        introductory text correctly revised; (c)(3) corrected......66049
250.1741 (g) table correctly added.................................44266
    (b) correctly revised; (g) table corrected.....................66049
250.1742 Table correctly added.....................................44266
250.1743 (a) amended; (b) corrected................................66049
256.56 (a)(1) amended; eff. 7-16-02................................35412
256.62 (e)(2) amended; eff. 7-16-02................................35412
260.114 (d) revised................................................57739
260.124 (b)(1) revised.............................................57739
280 Revised........................................................46858
Chapter VI
Chapter VI Removed.................................................30803

                                  2003

30 CFR
                                                                   68 FR
                                                                    Page
Chapter II
250.102 (b)(1) revised..............................................8422
250.105 Amended.....................................................8422
250.108 Revised.....................................................7426
250.114 (c) revised................................................43298
250.160 (f) through (i) added......................................69311
250.198 (e) table corrected...........................................46
    (e) table amended...........................7427, 8422, 19355, 43298
250.199 (e) table amended...........................................8422
250.203 (b)(5)(i), (ii) and (p) amended.............................8422
250.204 (b)(2)(i), (ii) and (t) amended.............................8422
250.400 Revised.....................................................8423
250.401 Revised.....................................................8423
250.402 Revised.....................................................8423
250.403 Revised.....................................................8423
250.404 Revised.....................................................8423
250.405 Revised.....................................................8423
250.406 Revised.....................................................8423
250.407 Revised.....................................................8423
250.408 Revised.....................................................8423
250.409 Revised.....................................................8423
250.410 Revised.....................................................8423
250.411 Revised.....................................................8423
250.412 Revised.....................................................8423
250.413 Revised.....................................................8423
250.414 Revised.....................................................8423
250.415 Revised.....................................................8423
250.416 Revised.....................................................8423
250.417 Redesignated as 250.490; new 250.417 added..................8423
250.418 Added.......................................................8423
250.420 Added.......................................................8423
250.421 Added.......................................................8423
250.422 Added.......................................................8423
250.423 Added.......................................................8423
250.424 Added.......................................................8423
250.425 Added.......................................................8423
250.426 Added.......................................................8423
250.427 Added.......................................................8423
250.428 Added.......................................................8423
250.430 Added.......................................................8423
250.431 Added.......................................................8423
250.432 Added.......................................................8423
250.433 Added.......................................................8423
250.434 Added.......................................................8423
250.440 Added.......................................................8423
250.441 Added.......................................................8423
250.442 Added.......................................................8423
250.443 Added.......................................................8423
250.444 Added.......................................................8423
250.445 Added.......................................................8423
250.446 Added.......................................................8423
250.447 Added.......................................................8423
250.448 Added.......................................................8423
250.449 Added.......................................................8423

[[Page 654]]

250.450 Added.......................................................8423
250.451 Added.......................................................8423
250.455 Added.......................................................8423
250.456 Added.......................................................8423
    (i) corrected..................................................14274
250.457 Added.......................................................8423
250.458 Added.......................................................8423
250.459 Added.......................................................8423
250.460 Added.......................................................8423
250.461 Added.......................................................8423
250.462 Added.......................................................8423
250.463 Added.......................................................8423
250.465 Added.......................................................8423
250.466 Added.......................................................8423
250.467 Added.......................................................8423
250.468 Added.......................................................8423
250.469 Added.......................................................8423
250.490 Redesignated from 250.417; undesignated center heading 
        added.......................................................8423
    (g)(4)(iv), (j)(13)(ii) and (p)(2) revised......................8434
250.504 Amended.....................................................8434
250.513 (a) and (b)(4) amended......................................8434
250.515 (b) revised.................................................8434
250.604 Amended.....................................................8435
250.613 (b)(3) amended..............................................8435
250.615 (b) revised.................................................8435
250.803 (b)(9)(v) revised..........................................43298
    (b)(7) revised.................................................65172
250.804 (a)(5) and (6) corrected......................................46
250.807 Amended.....................................................8435
250.900 (g) revised................................................19355
250.912 (a) amended................................................19355
    (a) amended....................................................41078
    Correctly amended..............................................41861
250.1009 (a)(1), (2), (b)(1) introductory text, (i), (ii), (2) 
        introductory text, (i), (ii), (iii), (3), (4), (c) 
        introductory text, (1) through (6), (7)(i), (ii) 
        introductory text, (A), (B), (8), (9), (d) and (e) 
        redesignated as (a), (b), 250.1011 (a) introductory text, 
        (1), (2), (b) introductory text, (1), (2), (3), (c), (d), 
        250.1010 introductory text, (a), 250.1012, 250.1010 (b) 
        through (e), (f)(1), (2) introductory text, (i), (ii), 
        (g), (h), 250.1013 and 250.1014............................69311
250.1010 Redesignated as 250.1015; new 250.1010 introductory text, 
        (a) through (e), (f)(1), (2) introductory text, (i), (ii), 
        (g) and (h) redesignated from 250.1009 (c) introductory 
        text, (1), (3) through (6), (7)(i), (ii) introductory 
        text, (A), (B), (8) and (9)................................69312
250.1011 Redesignated as 250.1016; new 250.1011 (a) introductory 
        text, (1), (2), (b) introductory text, (1), (2), (3), (c) 
        and (d) redesignated from 250.1009(b)(1) introductory 
        text, (i)(ii), (2) introductory text, (i), (ii), (iii), 
        (3) and (4)................................................69311
    Heading for new 250.1011 revised...............................69312
250.1012 Redesignated as 250.1017; new 250.1012 redesignated from 
        250.1009(c)(2).............................................69311
    New 250.1012 revised...........................................69312
250.1013 Redesignated as 250.1018; new 250.1013 redesignated from 
        250.1009(d)................................................69311
    Heading for new 250.1013 revised...............................69312
250.1014 Redesignated as 250.1019; new 250.1014 redesignated from 
        250.1009(e)................................................69311
    Heading for new 250.1014 revised...............................69312
250.1015 Redesignated from 250.1010................................69311
    Heading revised................................................69312
250.1016 Redesignated from 250.1011................................69311
    Heading revised................................................69312
250.1017 Redesignated from 250.1012................................69311
    Heading revised................................................69312
250.1018 Redesignated from 250.1013................................69311
    Heading revised................................................69313
250.1019 Redesignated from 250.1014; heading revised...............69312
250.1105 (f)(1)(i) amended..........................................8435
250.1403 Revised...................................................61624
250.1604 (b) amended................................................8435
250.1612 Amended....................................................8435
250.1614 (b) amended................................................8435
250.1629 (b)(4)(v) revised.........................................43298

[[Page 655]]

                                  2004

30 CFR
                                                                   69 FR
                                                                    Page
Chapter II
203.0 Amended................................................3509, 24053
    Regulation at 69 FR 3509 eff. date corrected to 5-3-04.........24052
    Regulation at 69 FR 24053 eff. date corrected to 5-3-04........25500
203.4 Introductory text revised.....................................3509
203.5 Added.........................................................3509
    Regulation at 69 FR 3509 eff. date corrected to 5-3-04.........24052
203.40 Section and undesignated center heading added................3510
    Regulation at 69 FR 3510 eff. date corrected to 5-3-04.........24052
203.41 Added........................................................3510
    Regulation at 69 FR 3510 eff. date corrected to 5-3-04.........24052
    (b) and (d) amended............................................24053
    Regulation at 69 FR 24053 eff. date corrected to 5-3-04........25500
203.42 Added........................................................3510
    Regulation at 69 FR 3510 eff. date corrected to 5-3-04.........24052
    (a)(1) and (b) introductory text revised.......................24054
    Regulation at 69 FR 24054 eff. date corrected to 5-3-04........25500
203.43 Added........................................................3510
    Regulation at 69 FR 3510 eff. date corrected to 5-3-04.........24052
    (d) and (e) introductory text revised..........................24054
    Regulation at 69 FR 24054 eff. date corrected to 5-3-04........25500
203.44 Added........................................................3510
    Regulation at 69 FR 3510 eff. date corrected to 5-3-04.........24052
    (b) amended; (e) introductory text revised.....................24054
    Regulation at 69 FR 24054 eff. date corrected to 5-3-04........25500
203.45 Added........................................................3510
    Regulation at 69 FR 3510 eff. date corrected to 5-3-04.........24052
203.46 Added........................................................3510
    Regulation at 69 FR 3510 eff. date corrected to 5-3-04.........24052
    (c) revised....................................................24054
    Regulation at 69 FR 24054 eff. date corrected to 5-3-04........25500
203.47 Added........................................................3510
    Regulation at 69 FR 3510 eff. date corrected to 5-3-04.........24052
203.48 Added........................................................3510
    Regulation at 69 FR 3510 eff. date corrected to 5-3-04.........24052
204 Added..........................................................55088
    Notice of decision by States...................................68805
206.101 Amended; eff. 7-6-04.......................................24975
    Regulation at 69 FR 24975 eff. date corrected to 8-1-04........29432
206.103 (b), (c), (d), (e) introductory text, (1)(ii) and (iii) 
        revised; eff. 7-6-04.......................................24976
    Regulation at 69 FR 24976 eff. date corrected to 8-1-04........29432
206.104 Heading, (a) introductory text, (3), (c) and (d) revised; 
        eff. 7-6-04................................................24976
    Regulation at 69 FR 24976 eff. date corrected to 8-1-04........29432
206.109 (b) revised; eff. 7-6-04...................................24976
    Regulation at 69 FR 24976 eff. date corrected to 8-1-04........29432
206.110 (a) revised; (b) through (e) redesignated as (d) through 
        (g); new (b) and (c) added; eff. 7-6-04....................24977
    Regulation at 69 FR 24977 eff. date corrected to 8-1-04........29432
206.111 Heading, (a), (b) introductory text, (h)(5) and (i)(2) 
        revised; (b)(6) and (7) added; eff. 7-6-04.................24977
    Regulation at 69 FR 24977 eff. date corrected to 8-1-04........29432
206.112 Revised; eff. 7-6-04.......................................24978
    Regulation at 69 FR 24978 eff. date corrected to 8-1-04........29432
206.118 Removed; eff. 7-6-04.......................................24979
    Regulation at 69 FR 24979 eff. date corrected to 8-1-04........29432
206.119 (c) revised; eff. 7-6-04...................................24979
    Regulation at 69 FR 24979 eff. date corrected to 8-1-04........29432
206.121 Removed; eff. 7-6-04.......................................24979
    Regulation at 69 FR 24979 eff. date corrected to 8-1-04........29432
250.160 (i) revised................................................29433
250.198 Nomenclature change........................................18803
250.1012 (e) revised...............................................29433

                                  2005

30 CFR
                                                                   70 FR
                                                                    Page
Chapter II
203.40 Introductory text and (a) revised...........................22252
204 Policy statement...............................................72381
206.150 (b) revised................................................11877
206.151 Amended....................................................11878

[[Page 656]]

206.157 (b)(2)(v), (5), (c), (f) introductory text, (1), (7) and 
        (g)(5) revised; (f)(10), (g)(6), (7) and (8) added; (g)(4) 
        amended....................................................11878
216.53 (e) and (f) added...........................................56852
218.50 (d) and (e) added...........................................56853
250 Authority citation revised.....................................49875
    Regulation at 70 FR 49875 eff. date delayed....................56119
250.102 (b) table amended..........................................51500
    Regulation at 70 FR 51500 eff. date delayed....................56853
250.105 Amended.............................................41573, 51500
    Regulation at 70 FR 51500 eff. date delayed....................56853
250.125 Undesignated center heading and section added..............49875
    Regulation at 70 FR 49875 eff. date delayed....................56119
250.143 (d) added..................................................49876
    Regulation at 70 FR 49876 eff. date delayed....................56119
250.171 Revised....................................................49876
    Regulation at 70 FR 49876 eff. date delayed....................56119
250.175 (c) added..................................................74663
250.198 (e) table amended....................................7403, 41573
250.199 (e) table amended...................................41574, 51500
    Regulation at 70 FR 51500 eff. date delayed....................56853
250.200--250.299 (Subpart B) Revised...............................51501
    Regulation at 70 FR 51501 eff. date delayed....................56853
250.303 (b)(2) and (d) amended.....................................51518
    Regulation at 70 FR 51518 eff. date delayed....................56853
250.304 (a)(6) and (b) amended.....................................51519
    Regulation at 70 FR 51519 eff. date delayed....................56853
250.800 Existing text designated as (a); (b) added.................41574
250.803 (b)(1) introductory text revised............................7403
    (a) revised; (b)(2)(iii) added.................................41575
250.900--250.921 (Subpart I) Revised...............................41575
250.1002 (b)(4) and (5) added......................................41583
250.1007 (a)(4) revised............................................41583
250.1015 (a) revised...............................................49876
    Regulation at 70 FR 49876 eff. date delayed....................56119
    (e) added......................................................61893
250.1018 (b) revised...............................................49876
    Regulation at 70 FR 49876 eff. date delayed....................56119
    (c) added......................................................61893
250.1101 (f) added.................................................49876
    Regulation at 70 FR 49876 eff. date delayed....................56119
250.1106 (d) added.................................................49876
    Regulation at 70 FR 49876 eff. date delayed....................56119
250.1303 (d) added.................................................49876
    Regulation at 70 FR 49876 eff. date delayed....................56119
250.1605 (d) amended...............................................51519
    Regulation at 70 FR 51519 eff. date delayed....................56853
250.1629 (b)(1) introductory text revised...........................7403
256 Authority citation revised.....................................49876
256.63 Added.......................................................49876
    Regulation at 70 FR 49876 eff. date delayed....................56119
256.64 (a)(8) revised..............................................49877
    Regulation at 70 FR 49877 eff. date delayed....................56119
    (a)(9) added...................................................61893
282.28 (a) amended.................................................51519
    Regulation at 70 FR 51519 eff. date delayed....................56853

                                  2006

30 CFR
                                                                   71 FR
                                                                    Page
Chapter II
201--243 (Subchapter A) Heading revised............................51751
218.500--218.580 (Subpart H) Added.................................51751
241.51 (c) removed; (b) revised....................................51752
241.61 Revised.....................................................51752
250 Nomenclature change.....................................46399, 46400
250.105 Amended....................................................23862
250.125 (a) table and (b) revised; (c) added.......................40909
250.126 Added......................................................40911
250.186 Redesignated from 250.190; eff. 7-17-06....................19644
250.187 Added; eff. 7-17-06........................................19644
250.188 Added; eff. 7-17-06........................................19644
250.189 Added; eff. 7-17-06........................................19644
250.190 Redesignated as 250.186; new 250.190 added; eff. 7-17-06 
                                                                   19644
250.191 Revised; eff. 7-17-06......................................19645
250.194 Heading and (a) introductory text revised..................23862
250.195 Redesignated as 250.196; new 250.195 added.................23862

[[Page 657]]

250.196 (b)(1) removed; (b)(2) through (10) redesignated as (b)(1) 
        through (9); heading, introductory text, (b) introductory 
        text and new (9) revised...................................16039
    Redesignated as 250.197; new 250.196 redesignated from 250.195
                                                                   23862
250.197 Redesignated from 250.196; (a) and (b)(7) revised; (b) 
        table amended..............................................23862
250.198 (e) table amended..........................................40911
250.199 (e) revised................................................23863
250.211 (d) added..................................................40911
250.235 Second (a) correctly designated as (c).....................12438
250.241 (e) added..................................................40911
250.292 (n) and (o) revised; (p) added.............................40911
250.296 (a) amended................................................40911
250.410 Introductory text and (d) revised..........................40911
250.465 (b)(1) revised.............................................40911
250.490 (l) revised; eff. 7-17-06..................................19645
250.513 (d) amended; eff. 7-17-06..................................19646
    (a) amended; (b) introductory text, (3) and (4) revised; 
(b)(5) added.......................................................40911
250.601 Amended....................................................11313
250.613 (a) amended; (b) introductory text, (2) and (3) revised; 
        (b)(4) added...............................................40912
250.615 (e) revised................................................11313
    (e)(1) table corrected.........................................29710
250.616 (d) and (e) redesignated as (f) and (g); new (d) and (e) 
        added; (a) and new (f) revised.............................11313
250.802 (e)(7) added...............................................40912
250.900 (b)(2) corrected...........................................16859
250.910 (b)(2)(i) corrected........................................28080
250.905 Introductory text revised; table amended; (k) added........40912
250.1000 (b) revised...............................................40912
250.1008 (e) revised...............................................40912
250.1102 (a)(9), (b)(8) and (9) amended; eff. 7-17-06..............19646
250.1202 (a)(1) revised............................................40912
250.1203 (b)(1) revised............................................40912
250.1204 (a)(1) revised............................................40913
250.1402 Amended...................................................23864
250.1617 (d) amended; eff. 7-17-06.................................19646
    (a) revised....................................................40913
250.1618 Heading and (a) revised...................................40913
250.1704 (g) revised...............................................40913
250.1727 Introductory text revised.................................40913
250.1751 (a) introductory text revised.............................40913
250.1752 (a) introductory text revised.............................40913
251 Authority citation revised.....................................40913
251.5 (a) revised..................................................40913
251.14 (b) introductory text and (1) table revised; (b)(3) added 
                                                                   16039
    (b)(1) table corrected.........................................62050
254 Nomenclature change............................................46400
280 Authority citation revised.....................................40914
280.12 (a) revised.................................................40914
290 Authority citation revised.....................................51752
290.100--290.111 (Subpart B) Heading revised.......................51752
290.100 Revised....................................................51752
290.102 Amended....................................................51752
290.111 Removed....................................................51752

                                  2007

    (Regulations published from January 1, 2007 through July 1, 2007)

30 CFR
                                                                   72 FR
                                                                    Page
Chapter II
Chapter II
202.351 Revised....................................................24458
202.353 Revised....................................................24458
203.44 (a) amended.................................................25198
206.350--206.366 (Subpart H) Revised...............................24459
210.352 Removed; new 210.352 redesignated from 210.353.............24467
210.353 Redesignated as 210.352; redesignated from 210.354.........24467
210.354 Redesignated as 210.353; redesignated from 210.355 and 
        revised....................................................24467
210.355 Redesignated as 210.354....................................24467
217.300--217.302 (Subpart G) Added.................................24468
218 Heading revised................................................24468
218.303 Added......................................................24468
218.304 Added......................................................24468
218.305 Added......................................................24468
218.306 Added......................................................24468
218.307 Added......................................................24468
250.102 (b) table revised..........................................25198
250.108 (c) revised................................................12092

[[Page 658]]

250.125 (a) table revised..........................................25199
250.143 (a) amended................................................25200
250.160 (f) and (g) amended........................................25200
250.165 (a) and (b) amended........................................25200
250.169 (a) amended................................................25200
250.175 (b)(3) amended.............................................25200
250.186 (b)(2) amended.............................................25200
250.194 (c) amended................................................25200
250.197 (a)(8) and (b)(7) amended..................................25200
250.198 (e) table amended;..........................................8902
    (e) table revised..............................................12092
    (d) table revised..............................................25200
250.199 (b) and (e) table amended..................................25200
250.201 (a)(3) amended.............................................25200
250.210 (a) and (b) amended........................................25200
250.216 (a) revised................................................18584
250.221 (b) redesignated as (c); new (b) added.....................18584
250.223 Revised....................................................18585
250.227 (a)(3) and (c)(1) revised..................................18585
250.232 (a)(2) amended.............................................25200
250.247 (a) revised................................................18585
250.252 (b) redesignated as (c); new (b) added.....................18585
250.254 Revised....................................................18585
250.261 (a)(3) and (c)(1) revised..................................18585
250.270 (a)(1)(i) revised..........................................18585
    (a)(1)(i) amended..............................................25200
250.281 (a)(3) amended.............................................25200
250.282 Introductory text revised..................................18585
250.285 (c) amended................................................25201
250.408 Amended....................................................25201
250.410 (d)(2) amended.............................................25201
250.415 (e) added...................................................8903
250.417 (c)(1) amended.............................................25201
250.466 Introductory text amended..................................25201
250.490 (p)(2) revised.............................................12096
    (o)(3) amended.................................................25201
250.513 (a), (c) and (d) revised...................................25201
250.613 (d) amended................................................25201
250.801 (e)(4) revised.............................................12096
    (h)(1) amended.................................................25201
250.802 (d) amended................................................12096
    (e)(3) and (4)(i) amended......................................25201
250.803 (b)(1) amended.............................................12096
250.806 (a)(2)(ii) revised.........................................12096
250.901 (a)(3) revised.............................................12096
250.1001 Amended...................................................25201
250.1002 (a) and (b)(2) amended....................................12096
    (c)(2) amended.................................................25201
250.1003 (b)(1) amended............................................25201
250.1004 (b)(2) amended............................................25201
250.1005 (b) amended...............................................25201
250.1007 (a)(4) amended............................................25201
250.1010 (c) and (h) amended.......................................25201
250.1011 (b)(1) revised; (b)(2) amended............................25201
250.1016 (c)(1) amended............................................25201
250.1019 Amended...................................................25201
250.1102 (a)(1) amended............................................25201
250.1103 (a) amended...............................................25201
250.1202 (f)(1) amended............................................25201
250.1403 Revised....................................................8899
250.1602 (b) amended...............................................25201
250.1619 (b) amended...............................................25201
250.1629 (b)(1) introductory text amended..........................12096
251.7 (b) introductory text revised; (b)(6) amended................25201
251.14 (b) introductory text amended...............................25202
253 Authority citation revised......................................8899
253.51 (a) revised..................................................8899
260.102 Amended....................................................25202


                                  [all]