[Title 30 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2010 Edition]
[From the U.S. Government Printing Office]



[[Page 1]]

          

          30


          Parts 200 to 699

                         Revised as of July 1, 2010


          Mineral Resources
          



________________________

          Containing a codification of documents of general 
          applicability and future effect

          As of July 1, 2010
          With Ancillaries
                    Published by
                    Office of the Federal Register
                    National Archives and Records
                    Administration
                    A Special Edition of the Federal Register

[[Page ii]]

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                            Table of Contents



                                                                    Page
  Explanation.................................................       v

  Title 30:
          Chapter II--Minerals Management Service, Department 
          of the Interior                                            3
          Chapter III--Board of Surface Mining and Reclamation 
          Appeals, Department of the Interior                      715
          Chapter IV--Geological Survey, Department of the 
          Interior                                                 719
  Finding Aids:
      Table of CFR Titles and Chapters........................     733
      Alphabetical List of Agencies Appearing in the CFR......     753
      List of CFR Sections Affected...........................     763

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

                     Cite this Code: CFR
                     To cite the regulations in 
                       this volume use title, 
                       part and section number. 
                       Thus, 30 CFR 201.100 
                       refers to title 30, part 
                       201, section 100.

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

[[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 
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HOW TO USE THE CODE OF FEDERAL REGULATIONS

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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 
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OBSOLETE PROVISIONS

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that volume.

[[Page vii]]

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    Raymond A. Mosley,
    Director,
    Office of the Federal Register.
    July 1, 2010.







[[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--199, 
parts 200--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, 2010.

    For this volume, Cheryl E. Sirofchuck was Chief Editor. The Code of 
Federal Regulations publication program is under the direction of 
Michael L. White, assisted by Ann Worley.

[[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
200

[Reserved]

201             General.....................................           5
202             Royalties...................................           5
203             Relief or reduction in royalty rates........          14
204             Alternatives for marginal properties........          54
206             Product valuation...........................          60
207             Sales agreements or contracts governing the 
                    disposal of lease products..............         174
208             Sale of Federal royalty oil.................         175
210             Forms and reports...........................         183
212             Records and files maintenance...............         196
215

Accounting and auditing standards [Reserved]

217             Audits and inspections......................         198
218             Collection of monies and provision for 
                    geothermal credits and incentives.......         200
219             Distribution and disbursement of royalties, 
                    rentals, and bonuses....................         215
220             Accounting procedures for determining net 
                    profit share payment for Outer 
                    Continental Shelf oil and gas leases....         220
227             Delegation to States........................         233
228             Cooperative activities with States and 
                    Indian tribes...........................         245
229             Delegation to States........................         249
230

Recoupments and refunds [Reserved]

232

Interest payments [Reserved]

233

Escrow and investments [Reserved]

234

Bonding--payment liability [Reserved]

241             Penalties...................................         256
242

Orders [Reserved]

[[Page 4]]

243             Suspensions pending appeal and bonding--
                    minerals revenue management.............         261
                         SUBCHAPTER B--OFFSHORE
250             Oil and gas and sulphur operations in the 
                    Outer Continental Shelf.................         267
251             Geological and geophysical (G&G) 
                    explorations of the Outer Continental 
                    Shelf...................................         478
252             Outer Continental Shelf (OCS) oil and gas 
                    information program.....................         492
253             Oil spill financial responsibility for 
                    offshore facilities.....................         498
254             Oil-spill response requirements for 
                    facilities located seaward of the coast 
                    line....................................         511
256             Leasing of sulphur or oil and gas in the 
                    Outer Continental Shelf.................         523
259             Mineral leasing: Definitions................         554
260             Outer Continental Shelf oil and gas leasing.         554
270             Nondiscrimination in the Outer Continental 
                    Shelf...................................         561
280             Prospecting for minerals other than oil, 
                    gas, and sulphur on the Outer 
                    Continental Shelf.......................         562
281             Leasing of minerals other than oil, gas, and 
                    sulphur in the Outer Continental Shelf..         574
282             Operations in the Outer Continental Shelf 
                    for minerals other than oil, gas, and 
                    sulphur.................................         587
285             Renewable energy alternate uses of existing 
                    facilities on the Outer Continental 
                    Shelf...................................         609
                          SUBCHAPTER C--APPEALS
290             Appeals procedures..........................         705
291             Open and nondiscriminatory access to oil and 
                    gas pipelines under the Outer 
                    Continental Shelf Lands Act.............         709

[[Page 5]]



                SUBCHAPTER A_MINERALS REVENUE MANAGEMENT
                           PART 200 [RESERVED]



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

               Subpart B_OCS Oil, Gas, and Sulfur General

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

203.30 Which leases are eligible for royalty relief as a result of 
          drilling a phase 2 or phase 3 ultra-deep well?
203.31 If I have a qualified phase 2 or qualified phase 3 ultra-deep 
          well, what royalty relief would that well earn for my lease?
203.32 What other requirements or restrictions apply to royalty relief 
          for a qualified phase 2 or phase 3 ultra-deep well?
203.33 To which production do I apply the RSV earned by qualified phase 
          2 and phase 3 ultra-deep wells on my lease or in my unit?
203.34 To which production may an RSV earned by qualified phase 2 and 
          phase 3 ultra-deep wells on my lease not be applied?
203.35 What administrative steps must I take to use the RSV earned by a 
          qualified phase 2 or phase 3 ultra-deep well?
203.36 Do I keep royalty relief if prices rise significantly?

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

203.40 Which leases are eligible for royalty relief as a result of 
          drilling a deep well or a phase 1 ultra-deep well?
203.41 If I have a qualified deep well or a qualified phase 1 ultra-deep 
          well, what royalty relief would my lease earn?
203.42 What conditions and limitations apply to royalty relief for deep 
          wells and phase 1 ultra-deep wells?
203.43 To which production do I apply the RSV earned from qualified deep 
          wells or qualified phase 1 ultra-deep wells on my lease?
203.44 What administrative steps must I take to use the royalty 
          suspension volume?
203.45 If I drill a certified unsuccessful well, what royalty relief 
          will my lease earn?
203.46 To which production do I apply the royalty suspension supplements 
          from drilling one or two certified unsuccessful wells on my 
          lease?
203.47 What administrative steps do I take to obtain and use the royalty 
          suspension supplement?
203.48 Do I keep royalty relief if prices rise significantly?
203.49 May I substitute the deep gas drilling provisions in Sec. 203.0 
          and Sec. Sec. 203.40 through 203.47 for the deep gas royalty 
          relief provided in my lease terms?

[[Page 15]]

                  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 Pre-Act Deep Water Leases and for Development and 
                           Expansion Projects

203.60 Who may apply for royalty relief on a case-by-case basis in deep 
          water in the Gulf of Mexico or offshore of Alaska?
203.61 How do I assess my chances for getting relief?
203.62 How do I apply for relief?
203.63 Does my application have to include all leases in the field?
203.64 How many applications may I file on a field or a development 
          project?
203.65 How long will MMS take to evaluate my application?
203.66 What happens if MMS does not act in the time allowed?
203.67 What economic criteria must I meet to get royalty relief on an 
          authorized field or project?
203.68 What pre-application costs will MMS consider in determining 
          economic viability?
203.69 If my application is approved, what royalty relief will I 
          receive?
203.70 What information must I provide after MMS approves relief?
203.71 How does MMS allocate a field's suspension volume between my 
          lease and other leases on my field?
203.72 Can my lease receive more than one suspension volume?
203.73 How do suspension volumes apply to natural gas?
203.74 When will MMS reconsider its determination?
203.75 What risk do I run if I request a redetermination?
203.76 When might MMS withdraw or reduce the approved size of my relief?
203.77 May I voluntarily give up relief if conditions change?
203.78 Do I keep relief approved by MMS under Sec. Sec. 203.60-203.77 
          for my lease, unit or project if prices rise significantly?
203.79 How do I appeal MMS's decisions related to royalty relief for a 
          deepwater lease or a development or expansion project?
203.80 When can I get royalty relief if I am not eligible for royalty 
          relief under other sections in the subpart?

                            Required Reports

203.81 What supplemental reports do royalty-relief applications require?
203.82 What is 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 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; 42 U.S.C. 15903-
15906; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C. 
1801 et seq.



                      Subpart A_General Provisions

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



Sec. 203.0  What definitions apply to this part?

    Authorized field means a field:

[[Page 16]]

    (1) Located in a water depth of at least 200 meters and in the Gulf 
of Mexico (GOM) west of 87 degrees, 30 minutes West longitude;
    (2) That includes one or more pre-Act leases; and
    (3) From which no current pre-Act lease produced, other than test 
production, before November 28, 1995.
    Certified unsuccessful well means an original well or a sidetrack 
with a sidetrack measured depth (i.e., length) of at least 10,000 feet, 
on your lease that:
    (1) You begin drilling on or after March 26, 2003, and before May 3, 
2009, on a lease that is located in water partly or entirely less than 
200 meters deep and that is not a non-converted lease, or on or after 
May 18, 2007, and before May 3, 2013, on a lease that is located in 
water entirely more than 200 meters and entirely less than 400 meters 
deep;
    (2) You begin drilling before your lease produces gas or oil from a 
well with a perforated interval the top of which is at least 18,000 feet 
true vertical depth subsea (TVD SS), (i.e., below the datum at mean sea 
level);
    (3) You drill to at least 18,000 feet TVD SS with a target reservoir 
on your lease, identified from seismic and related data, deeper than 
that depth;
    (4) Fails to meet the producibility requirements of 30 CFR part 250, 
subpart A, and does not produce gas or oil, or meets those producibility 
requirements and MMS agrees it is not commercially producible; and
    (5) For which you have provided the notices and information required 
under Sec. 203.47.
    Complete application means an original and two copies of the six 
reports consisting of the data specified in 30 CFR 203.81, 203.83 and 
203.85 through 203.89, along with one set of digital information, which 
MMS has reviewed and found complete.
    Deep well means either an original well or a sidetrack with a 
perforated interval the top of which is at least 15,000 feet TVD SS and 
less than 20,000 feet TVD SS. A deep well subsequently re-perforated at 
less than 15,000 feet TVD SS in the same reservoir is still a deep well.
    Determination means the binding decision by 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 have had no 
production (other than test production) before the current application 
for royalty relief and are either:
    (1) Located in a planning area offshore Alaska; or
    (2) Located in the GOM in a water depth of at least 200 meters and 
wholly west of 87 degrees, 30 minutes West longitude, and were issued in 
a sale held after November 28, 2000.
    Draft application means the preliminary set of information and 
assumptions you submit to seek a nonbinding assessment on whether a 
field could be expected to qualify for royalty relief.
    Eligible lease means a lease that:
    (1) Is issued as part of an OCS lease sale held after November 28, 
1995, and before November 28, 2000;
    (2) Is located in the Gulf of Mexico in water depths of 200 meters 
or deeper;
    (3) Lies wholly west of 87 degrees, 30 minutes West longitude; and
    (4) Is offered subject to a royalty suspension volume.
    Expansion project means a project that meets the following 
requirements:
    (1) You must propose the project in a Development and Production 
Plan, a Development Operations Coordination Document (DOCD), or a 
Supplement to a DOCD, approved by the Secretary of the Interior after 
November 28, 1995.
    (2) The project must be located on either:
    (i) A pre-Act lease in the GOM, or a lease in the GOM issued in a 
sale held after November 28, 2000, located wholly west of 87 degrees, 30 
minutes West longitude; or
    (ii) A lease in a planning area offshore Alaska.
    (3) On a pre-Act lease in the GOM, the project:
    (i) Must significantly increase the ultimate recovery of resources 
from one or more reservoirs that have not previously produced (extending 
recovery from reservoirs already in production does not constitute a 
significant increase); and

[[Page 17]]

    (ii) Must involve a substantial capital investment (e.g., fixed-leg 
platform, subsea template and manifold, tension-leg platform, multiple 
well project, etc.).
    (4) For a lease issued in a planning area offshore Alaska, or in the 
GOM after November 28, 2000, the project must involve a new well drilled 
into a reservoir that has not previously produced.
    (5) On a lease in the GOM, the project must not include a reservoir 
the production from which an RSV under Sec. Sec. 203.30 through 203.36 
or Sec. Sec. 203.40 through 203.48 would be applied.
    Fabrication (or start of construction) means evidence of an 
irreversible commitment to a concept and scale of development. Evidence 
includes copies of a binding contract between you (as applicant) and a 
fabrication yard, a letter from a fabricator certifying that continuous 
construction has begun, and a receipt for the customary down payment.
    Field means an area consisting of a single reservoir or multiple 
reservoirs all grouped on, or related to, the same general geological 
structural feature or stratigraphic trapping condition. Two or more 
reservoirs may be in a field, separated vertically by intervening 
impervious strata or laterally by local geologic barriers, or both.
    Lease means a lease or unit.
    New production means any production from a current pre-Act lease 
from which no royalties are due on production, other than test 
production, before November 28, 1995. Also, it means any additional 
production resulting from new lease-development activities on a lease 
issued in a sale after November 28, 2000, or a current pre-Act lease 
under a 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.
    Non-converted lease means a lease located partly or entirely in 
water less than 200 meters deep issued in a lease sale held after 
January 1, 2001, and before January 1, 2004, whose original lease terms 
provided for an RSV for deep gas production and the lessee has not 
exercised the option under Sec. 203.49 to replace the lease terms for 
royalty relief with those in Sec. 203.0 and Sec. Sec. 203.40 through 
203.48.
    Original well means a well that is drilled without utilizing an 
existing wellbore. An original well includes all sidetracks drilled from 
the original wellbore either before the drilling rig moves off the well 
location or after a temporary rig move that MMS agrees was forced by a 
weather or safety threat and drilling resumes within 1 year. A bypass 
from an original well (e.g., drilling around material blocking the hole 
or to straighten crooked holes) is part of the original well.
    Participating area means that part of the unit area that 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.
    Phase 1 ultra-deep well means an ultra-deep well on a lease that is 
located in water partly or entirely less than 200 meters deep for which 
drilling began before May 18, 2007, and that begins production before 
May 3, 2009, or that meets the requirements to be a certified 
unsuccessful well.
    Phase 2 ultra-deep well means an ultra-deep well for which drilling 
began on or after May 18, 2007; and that either meets the requirements 
to be a certified unsuccessful well or that begins production:
    (1) Before the date which is 5 years after the lease issuance date 
on a non-converted lease; or
    (2) Before May 3, 2009, on all other leases located in water partly 
or entirely less than 200 meters deep; or
    (3) Before May 3, 2013, on a lease that is located in water entirely 
more than 200 meters and entirely less than 400 meters deep.

[[Page 18]]

    Phase 3 ultra-deep well means an ultra-deep well for which drilling 
began on or after May 18, 2007, and that begins production:
    (1) On or after the date which is 5 years after the lease issuance 
date on a non-converted lease; or
    (2) On or after May 3, 2009, on all other leases located in water 
partly or entirely less than 200 meters deep; or
    (3) On or after May 3, 2013, on a lease that is located in water 
entirely more than 200 meters and entirely less than 400 meters deep.
    Pre-Act lease means a lease that:
    (1) Results from a sale held before November 28, 1995;
    (2) Is located in the GOM in water depths of 200 meters or deeper; 
and
    (3) Lies wholly west of 87 degrees, 30 minutes West longitude.
    Production means all oil, gas, and other relevant products you save, 
remove, or sell from a tract or those quantities allocated to your tract 
under a unitization formula, as measured for the purposes of determining 
the amount of royalty payable to the United States.
    Project means any activity that requires at least a permit to drill.
    Qualified deep well means:
    (1) On a lease that is located in water partly or entirely less than 
200 meters deep that is not a non-converted lease, a deep well for which 
drilling began on or after March 26, 2003, that produces natural gas 
(other than test production), including gas associated with oil 
production, before May 3, 2009, and for which you have met the 
requirements prescribed in Sec. 203.44;
    (2) On a non-converted lease, a deep well that produces natural gas 
(other than test production) before the date which is 5 years after the 
lease issuance date from a reservoir that has not produced from a deep 
well on any lease; or
    (3) On a lease that is located in water entirely more than 200 
meters but entirely less than 400 meters deep, a deep well for which 
drilling began on or after May 18, 2007, that produces natural gas 
(other than test production), including gas associated with oil 
production before May 3, 2013, and for which you have met the 
requirements prescribed in Sec. 203.44.
    Qualified ultra-deep well means:
    (1) On a lease that is located in water partly or entirely less than 
200 meters deep that is not a non-converted lease, an ultra-deep well 
for which drilling began on or after March 26, 2003, that produces 
natural gas (other than test production), including gas associated with 
oil production, and for which you have met the requirements prescribed 
in Sec. 203.35 or Sec. 203.44, as applicable; or
    (2) On a lease that is located in water entirely more than 200 
meters and entirely less than 400 meters deep, or on a non-converted 
lease, an ultra-deep well for which drilling began on or after May 18, 
2007, that produces natural gas (other than test production), including 
gas associated with oil production, and for which you have met the 
requirements prescribed in Sec. 203.35.
    Qualified well means either a qualified deep well or a qualified 
ultra-deep well.
    Redetermination means our reconsideration of our determination on 
royalty relief because you request it after:
    (1) We have rejected your application;
    (2) We have granted relief but you want a larger suspension volume;
    (3) We withdraw approval; or
    (4) You renounce royalty relief.
    Renounce means action you take to give up relief after we have 
granted it and before you start production.
    Reservoir means an underground accumulation of oil or natural gas, 
or both, characterized by a single pressure system and segregated from 
other such accumulations.
    Royalty suspension (RS) lease means a lease that:
    (1) Is issued as part of an OCS lease sale held after November 28, 
2000;
    (2) Is in locations or planning areas specified in a particular 
Notice of OCS Lease Sale offering that lease; and
    (3) Is offered subject to a royalty suspension specified in a Notice 
of OCS Lease Sale published in the Federal Register.
    Royalty suspension supplement (RSS) means a royalty suspension 
volume resulting from drilling a certified unsuccessful well that is 
applied to future

[[Page 19]]

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 (RSV) means a volume of production from a 
lease that is not subject to royalty under the provisions of this part.
    Sidetrack means, for the purpose of this subpart, a well resulting 
from drilling an additional hole to a new objective bottom-hole location 
by leaving a previously drilled hole. A sidetrack also includes drilling 
a well from a platform slot reclaimed from a previously drilled well or 
re-entering and deepening a previously drilled well. A bypass from a 
sidetrack (e.g., drilling around material blocking the hole, or to 
straighten crooked holes) is part of the sidetrack.
    Sidetrack measured depth means the actual distance or length in feet 
a sidetrack is drilled beginning where it exits a previously drilled 
hole to the bottom hole of the sidetrack, that is, to its total depth.
    Sunk costs for an authorized field means the after-tax eligible 
costs that you (not third parties) incur for exploration, development, 
and production from the spud date of the first discovery on the field to 
the date we receive your complete application for royalty relief. The 
discovery well must be qualified as producible under part 250, subpart A 
of this title. Sunk costs include the rig mobilization and material 
costs for the discovery well that you incurred before its spud date.
    Sunk costs for an expansion or development project means the after-
tax eligible costs that you (not third parties) incur for only the first 
well that encounters hydrocarbons in the reservoir(s) included in the 
application and that meets the producibility requirements under part 
250, subpart A of this chapter on each lease participating in the 
application. Sunk costs include rig mobilization and material costs for 
the discovery wells that you incurred before their spud dates.
    Ultra-deep well means either an original well or a sidetrack 
completed with a perforated interval the top of which is at least 20,000 
feet TVD SS. An ultra-deep well subsequently re-perforated less than 
20,000 feet TVD SS in the same reservoir is still an ultra-deep well.
    Withdraw means action we take on a field that has qualified for 
relief if you have not met one or more of the performance conditions.

[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; 73 FR 69504, Nov. 
18, 2008]



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 and the Energy Policy Act of 2005, Public Law 109-058 authorizes 
us to grant royalty relief in four situations.
    (a) Under 43 U.S.C. 1337(a)(3)(A), we may reduce or eliminate any 
royalty or a net profit share specified for an OCS lease to promote 
increased production.
    (b) Under 43 U.S.C. 1337(a)(3)(B), we may reduce, modify, or 
eliminate any royalty or net profit share to promote development, 
increase production, or encourage production of marginal resources on 
certain leases or categories of leases. This authority is restricted to 
leases in the GOM that are west of 87 degrees, 30 minutes West 
longitude, and in the planning areas offshore Alaska.
    (c) Under 43 U.S.C. 1337(a)(3)(C), we may suspend royalties for 
designated volumes of new production from any lease if:
    (1) Your lease is in deep water (water at least 200 meters deep);
    (2) Your lease is in designated areas of the GOM (west of 87 
degrees, 30 minutes West longitude);
    (3) Your lease was acquired in a lease sale held before the DWRRA 
(before November 28, 1995);
    (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.

[[Page 20]]

    (d) Under 42 U.S.C. 15904-15905, we may suspend royalties for 
designated volumes of gas production from deep and ultra-deep wells on a 
lease if:
    (1) Your lease is in shallow water (water less than 400 meters deep) 
and you produce from an ultra-deep well (top of the perforated interval 
is at least 20,000 feet TVD SS) or your lease is in waters entirely more 
than 200 meters and entirely less than 400 meters deep and you produce 
from a deep well (top of the perforated interval is at least 15,000 feet 
TVD SS);
    (2) Your lease is in the designated area of the GOM (wholly west of 
87 degrees, 30 minutes west longitude); and
    (3) Your lease is not eligible for deep water royalty relief.

[63 FR 2616, Jan. 16, 1998, as amended at 73 FR 69506, Nov. 18, 2008]



Sec. 203.2  How can I obtain royalty relief?

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

------------------------------------------------------------------------
                                                       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   Propose an          A royalty
 deep water area (i.e., 200        expansion project   suspension for a
 meters or greater) and acquired   and can             minimum
 in a lease sale held before       demonstrate your    production volume
 November 28, 1995, or after       project is          plus any
 November 28, 2000.                uneconomic          additional
                                   without royalty     production large
                                   relief.             enough to make
                                                       the project
                                                       economic (see
                                                       Sec. Sec.
                                                       203.60 through
                                                       203.79).
(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   Propose a           A royalty
 deep water area and acquired in   development         suspension for a
 a lease sale held after           project and can     minimum
 November 28, 2000.                demonstrate that    production volume
                                   the suspension      plus any
                                   volume, if any,     additional volume
                                   for your lease is   needed to make
                                   not enough to       your project
                                   make development    economic (see
                                   economic.           Sec. Sec.
                                                       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, offshore Alaska     of-life or deep     size, duration,
 or in certain areas of the GOM,   water royalty       or form that
 would enable development.         relief, but show    makes your lease
                                   us you meet         or project
                                   certain             economic (see
                                   eligibility         Sec.  203.80).
                                   conditions.
(f) Located in a designated GOM   Drill a deep well   A royalty
 shallow water area and acquired   on a lease that     suspension for a
 in a lease sale held before       is not eligible     volume of gas
 January 1, 2001, or after         for deep water      produced from
 January 1, 2004, or have          royalty relief      successful deep
 exercised an option to            and you have not    and ultra-deep
 substitute for royalty relief     previously          wells, or, for
 in your lease terms.              produced oil or     certain
                                   gas from a deep     unsuccessful deep
                                   well or an ultra-   and ultra-deep
                                   deep well.          wells, a smaller
                                                       royalty
                                                       suspension for a
                                                       volume of gas or
                                                       oil produced by
                                                       all wells on your
                                                       lease (see Sec.
                                                       Sec.  203.40
                                                       through 203.49).
(g) Located in a designated GOM   Drill and produce   A royalty
 shallow water area.               gas from an ultra-  suspension for a
                                   deep well on a      volume of gas
                                   lease that is not   produced from
                                   eligible for deep   successful ultra-
                                   water royalty       deep and deep
                                   relief and you      wells on your
                                   have not            lease (see Sec.
                                   previously          Sec.  203.30
                                   produced oil or     through 203.36).
                                   gas from an ultra-
                                   deep well.
(h) Located in planning areas     Propose an          A royalty
 offshore Alaska.                  expansion project   suspension for a
                                   or propose a        minimum
                                   development         production volume
                                   project and can     plus any
                                   demonstrate that    additional volume
                                   the project is      needed to make
                                   uneconomic          your project
                                   without relief or   economic (see
                                   that the            Sec. Sec.
                                   suspension          203.60, 203.62,
                                   volume, if any,     203.67 through
                                   for your lease is   203.70, Sec.
                                   not enough to       Sec.  203.73 and
                                   make development    203.76 through
                                   economic.           203.79).
------------------------------------------------------------------------


[67 FR 1872, Jan. 15, 2002, as amended at 73 FR 69506, Nov. 18, 2008]



Sec. 203.3  Do I have to pay a fee to request royalty relief?

    When you submit an application or ask for a preview assessment, you 
must include a fee to reimburse us for our costs of processing your 
application or assessment. Federal policy and law require us to recover 
the cost of services

[[Page 21]]

that confer special benefits to identifiable non-Federal recipients. The 
Independent Offices Appropriation Act (31 U.S.C. 9701), Office of 
Management and Budget Circular A-25, and the Omnibus Appropriations Bill 
(Pub. L. 104-134, 110 Stat. 1321, April 26, 1996) authorize us to 
collect these fees.
    (a) We will specify the necessary fees for each of the types of 
royalty relief applications and possible 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.
    (b) You must file all payments electronically through the Pay.gov 
Web site and you must include a copy of the Pay.gov confirmation receipt 
page with your application or assessment. The Pay.gov Web site may be 
accessed through a link on the MMS Offshore Web site at: http://
www.mms.gov/offshore/ homepage or directly through Pay.gov at: https://
www.pay.gov/paygov/.

[73 FR 49946, Aug. 25, 2008]



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.

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

[[Page 22]]

 
(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 23]]



----------------------------------------------------------------------------------------------------------------
                                                                                       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?

    (a) The Office of Management and Budget (OMB) has approved the 
information collection requirements in this part under 44 U.S.C. 3501 et 
seq., and assigned OMB Control Number 1010-0071. The title of this 
information collection is ``30 CFR part 203, Relief or Reduction in 
Royalty Rates.''
    (b) The MMS collects this information to make decisions on the 
economic viability of leases requesting a suspension or elimination of 
royalty or net profit share. Responses are required to obtain a benefit 
or are mandatory according to 43 U.S.C. 1331 et seq. The MMS will 
protect information considered proprietary under applicable law and 
under regulations at 30 CFR 203.63, ``How do I assess my chances for 
getting relief?'' and 250.197, ``Data and information to be made 
available to the public or for limited inspection.''
    (c) An agency may not conduct or sponsor, and a person is not 
required to respond to a collection of information unless it displays a 
currently valid OMB control number.
    (d) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Minerals 
Management Service, Mail Stop 5438, 1849 C Street, NW., Washington, DC 
20240.

[74 FR 46907, Sept. 14, 2009]



               Subpart B_OCS Oil, Gas, and Sulfur General

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

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

    Source: 73 FR 69506, Nov. 18, 2008, unless otherwise noted.



Sec. 203.30  Which leases are eligible for royalty relief as a result of drilling a phase 2 or phase 3 ultra-deep well?

    Your lease may receive a royalty suspension volume (RSV) under 
Sec. Sec. 203.31 through 203.36 if the lease meets all the requirements 
of this section.
    (a) The lease is located in the GOM wholly west of 87 degrees, 30 
minutes West longitude in water depths entirely less than 400 meters 
deep.
    (b) The lease has not produced gas or oil from a deep well or an 
ultra-deep well, except as provided in Sec. 203.31(b).
    (c) If the lease is located entirely in more than 200 meters and 
entirely less than 400 meters of water, it must either:
    (1) Have been issued before November 28, 1995, and not been granted 
deep water royalty relief under 43 U.S.C. 1337(a)(3)(C), added by 
section 302 of the Deep Water Royalty Relief Act; or
    (2) Have been issued after November 28, 2000, and not been granted 
deep water royalty relief under Sec. Sec. 203.60 through 203.79.

[[Page 24]]



Sec. 203.31  If I have a qualified phase 2 or qualified phase 3 ultra-deep well, what royalty relief would that well earn for my lease?

    (a) Subject to the administrative requirements of Sec. 203.35 and 
the price conditions in Sec. 203.36, your qualified well earns your 
lease an RSV shown in the following table in billions of cubic feet 
(BCF) or in thousands of cubic feet (MCF) as prescribed in Sec. 203.33:

------------------------------------------------------------------------
 If you have a qualified phase 2 or
 qualified phase 3 ultra-deep well     Then your lease earns an RSV on
              that is:                  this volume of gas production:
------------------------------------------------------------------------
(1) An original well,                35 BCF.
(2) A sidetrack with a sidetrack     35 BCF.
 measured depth of at least 20,000
 feet,
(3) An ultra-deep short sidetrack    4 BCF plus 600 MCF times sidetrack
 that is a phase 2 ultra-deep well,   measured depth (rounded to the
                                      nearest 100 feet) but no more than
                                      25 BCF.
(4) An ultra-deep short sidetrack    0 BCF.
 that is a phase 3 ultra-deep well,
------------------------------------------------------------------------

    (b)(1) This paragraph applies if your lease:
    (i) Has produced gas or oil from a deep well with a perforated 
interval the top of which is less than 18,000 feet TVD SS;
    (ii) Was issued in a lease sale held between January 1, 2004, and 
December 31, 2005; and
    (iii) The terms of your lease expressly incorporate the provisions 
of Sec. Sec. 203.41 through 203.47 as they existed at the time the 
lease was issued.
    (2) Subject to the administrative requirements of Sec. 203.35 and 
the price conditions in Sec. 203.36, your qualified well earns your 
lease an RSV shown in the following table in BCF or MCF as prescribed in 
Sec. 203.33:

------------------------------------------------------------------------
  If you have a qualified phase 2      Then your lease earns an RSV on
    ultra-deep well that is . .         this volume of gas production:
------------------------------------------------------------------------
(i) An original well or a sidetrack  10 BCF.
 with a sidetrack measured depth of
 at least 20,000 feet TVD SS,
(ii) An ultra-deep short sidetrack,  4 BCF plus 600 MCF times sidetrack
                                      measured depth (rounded to the
                                      nearest 100 feet) but no more than
                                      10 BCF.
------------------------------------------------------------------------

    (c) Lessees may request a refund of or recoup royalties paid on 
production from qualified phase 2 or phase 3 ultra-deep wells that:
    (1) Occurs before December 18, 2008 and
    (2) Is subject to application of an RSV under either Sec. 203.31 or 
Sec. 203.41.
    (d) The following examples illustrate how this section applies. 
These examples assume that your lease is located in the GOM west of 87 
degrees, 30 minutes West longitude and in water less than 400 meters 
deep (see Sec. 203.30(a)), has no existing deep or ultra-deep wells and 
that the price thresholds prescribed in Sec. 203.36 have not been 
exceeded.

    Example 1: In 2008, you drill and begin producing from an ultra-deep 
well with a perforated interval the top of which is 25,000 feet TVD SS, 
and your lease has had no prior production from a deep or ultra-deep 
well. Assuming your lease has no deepwater royalty relief (see Sec. 
203.30(c)), your lease is eligible (according to Sec. 203.30(b)) to 
earn an RSV under Sec. 203.31 because it has not yet produced from a 
deep well. Your lease earns an RSV of 35 BCF under this section when 
this well begins producing. According to Sec. 203.31(a), your 25,000 
foot well qualifies your lease for this RSV because the well was drilled 
after the relief authorized here became effective (when the proposed 
version of this rule was published on May 18, 2007) and produced from an 
interval that meets the criteria for an ultra-deep well (i.e., is a 
phase 2 ultra-deep well as defined in Sec. 203.0). Then in 2014, you 
drill and produce from another ultra-deep well with a perforated 
interval the top of which is 29,000 feet TVD SS. Your lease earns no 
additional RSV under this section when this second ultra-deep well 
produces, because your lease no longer meets the condition in Sec. 
203.30(b)) of no production from a deep well. However, any remaining RSV 
earned by the first ultra-deep well on your lease would be applied to 
production from both the first and the second ultra-deep wells as 
prescribed in

[[Page 25]]

Sec. 203.33(a)(2), or Sec. 203.33(b)(2) if your lease is part of a 
unit.
    Example 2: In 2005, you spudded and began producing from an ultra-
deep well with a perforated interval the top of which is 23,000 feet TVD 
SS. Your lease earns no RSV under this section from this phase 1 ultra-
deep well (as defined in Sec. 203.0) because you spudded the well 
before the publication date (May 18, 2007) of the proposed rule when 
royalty relief under Sec. 203.31(a) became effective. However, this 
ultra-deep well may earn an RSV of 25 BCF for your lease under Sec. 
203.41 (that became effective May 3, 2004), if the lease is located in 
water depths partly or entirely less than 200 meters and has not 
previously produced from a deep well (Sec. 203.30(b)).
    Example 3: In 2000, you began producing from a deep well with a 
perforated interval the top of which is 16,000 feet TVD SS and your 
lease is located in water 100 meters deep. Then in 2008, you drill and 
produce from a new ultra-deep well with a perforated interval the top of 
which is 24,000 feet TVD SS. Your lease earns no RSV under either this 
section or Sec. 203.41 because the 16,000-foot well was drilled before 
we offered any way to earn an RSV for producing from a deep well (see 
dates in the definition of qualified well in Sec. 203.0) and because 
the existence of the 16,000-foot well means the lease is not eligible 
(see Sec. 203.30(b)) to earn an RSV for the 24,000-foot well. Because 
the lease existed in the year 2000, it cannot be eligible for the 
exception to this eligibility condition provided in Sec. 203.31(b).
    Example 4: In 2008, you spud and produce from an ultra-deep well 
with a perforated interval the top of which is 22,000 feet TVD SS, your 
lease is located in water 300 meters deep, and your lease has had no 
previous production from a deep or ultra-deep well. Your lease earns an 
RSV of 35 BCF under this section when this well begins producing because 
your lease meets the conditions in Sec. 203.30 and the well fits the 
definition of a phase 2 ultra-deep well (in Sec. 203.0). Then in 2010, 
you spud and produce from a deep well with a perforated interval the top 
of which is 16,000 feet TVD SS. Your 16,000-foot well earns no RSV 
because it is on a lease that already has a producing well at least 
18,000 feet subsea (see Sec. 203.42(a)), but any remaining RSV earned 
by the ultra-deep well would also be applied to production from the deep 
well as prescribed in Sec. 203.33(a)(2), or Sec. 203.33(b)(2) if your 
lease is part of a unit and Sec. 203.43(a)(2), or Sec. 203.43(b)(2) if 
your lease is part of a unit. However, if the 16,000-foot deep well does 
not begin production until 2016 (or if your lease were located in water 
less than 200 meters deep), then the 16,000-foot well would not be a 
qualified deep well because this well does not begin production within 
the interval specified in the definition of a qualified well in Sec. 
203.0, and the RSV earned by the ultra-deep well would not be applied to 
production from this (unqualified) deep well.
    Example 5: In 2008, you spud a deep well with a perforated interval 
the top of which is 17,000 feet TVD SS that becomes a qualified well and 
earns an RSV of 15 BCF under Sec. 203.41 when it begins producing. Then 
in 2011, you spud an ultra-deep well with a perforated interval the top 
of which is 26,000 feet TVD SS. Your 26,000-foot well becomes a 
qualified ultra-deep well because it meets the date and depth conditions 
in this definition under Sec. 203.0 when it begins producing, but your 
lease earns no additional RSV under this section or Sec. 203.41 because 
it is on a lease that already has production from a deep well (see Sec. 
203.30(b)). Both the qualified deep well and the qualified ultra-deep 
well would share your lease's total RSV of 15 BCF in the manner 
prescribed in Sec. Sec. 203.33 and 203.43.
    Example 6: In 2008, you spud a qualified ultra-deep well that is a 
sidetrack with a sidetrack measured depth of 21,000 feet and a 
perforated interval the top of which is 25,000 feet TVD SS. This well 
meets the definition of an ultra-deep well but is too long to be 
classified an ultra-deep short sidetrack in Sec. 203.0. If your lease 
is located in 150 meters of water and has not previously produced from a 
deep well, your lease earns an RSV of 35 BCF because it was drilled 
after the effective date for earning this RSV. Further, this RSV applies 
to gas production from this and any future qualified deep and qualified 
ultra-deep wells on your lease, as prescribed in Sec. 203.33. The 
absence of an expiration date for earning an RSV on an ultra-deep well 
means this long sidetrack well becomes a qualified well whenever it 
starts production. If your sidetrack has a sidetrack measured depth of 
14,000 feet and begins production in March 2009, it earns an RSV of 12.4 
BCF under this section because it meets the definitions of a phase 2 
ultra-deep well (production begins before the expiration date for the 
pre-existing relief in its water depth category) and an ultra-deep short 
sidetrack in Sec. 203.0. However, if it does not begin production until 
2010, it earns no RSV because it is too short as a phase 3 ultra-deep 
well to be a qualified ultra-deep well.
    Example 7: Your lease was issued in June 2004 and expressly 
incorporates the provisions of Sec. Sec. 203.41 through 203.47 as they 
existed at that time. In January 2005, you spud a deep well (well no. 1) 
with a perforated interval the top of which is 16,800 feet TVD SS that 
becomes a qualified well and earns an RSV of 15 BCF under Sec. 203.41 
when it begins producing. Then in February 2008, you spud an ultra-deep 
well (well no. 2) with a perforated interval the top of which is 22,300 
feet that begins producing in November 2008, after well no. 1 has 
started production. Well no. 2 earns your lease an additional RSV of 10 
BCF under paragraph (b) of this section

[[Page 26]]

because it begins production in time to be classified as a phase 2 
ultra-deep well. If, on the other hand, well no. 2 had begun producing 
in June 2009, it would earn no additional RSV for the lease because it 
would be classified as a phase 3 ultra-deep well and thus is not 
entitled to the exception under paragraph (b) of this section.



Sec. 203.32  What other requirements or restrictions apply to royalty relief for a qualified phase 2 or phase 3 ultra-deep well?

    (a) If a qualified ultra-deep well on your lease is within a 
unitized portion of your lease, the RSV earned by that well under this 
section applies only to your lease and not to other leases within the 
unit or to the unit as a whole.
    (b) If your qualified ultra-deep well is a directional well (either 
an original well or a sidetrack) drilled across a lease line, then 
either:
    (1) The lease with the perforated interval that initially produces 
earns the RSV or
    (2) If the perforated interval crosses a lease line, the lease where 
the surface of the well is located earns the RSV.
    (c) Any RSV earned under Sec. 203.31 is in addition to any royalty 
suspension supplement (RSS) for your lease under Sec. 203.45 that 
results from a different wellbore.
    (d) If your lease earns an RSV under Sec. 203.31 and later produces 
from a deep well that is not a qualified well, the RSV is not forfeited 
or terminated, but you may not apply the RSV earned under Sec. 203.31 
to production from the non-qualified well.
    (e) You owe minimum royalties or rentals in accordance with your 
lease terms notwithstanding any RSVs allowed under paragraphs (a) and 
(b) of Sec. 203.31.
    (f) Unused RSVs transfer to a successor lessee and expire with the 
lease.



Sec. 203.33  To which production do I apply the RSV earned by qualified phase 2 and phase 3 ultra-deep wells on my lease or in my unit?

    (a) You must apply the RSV allowed in Sec. 203.31(a) and (b) to gas 
volumes produced from qualified wells on or after May 18, 2007, reported 
on the Oil and Gas Operations Report, Part A (OGOR-A) for your lease 
under Sec. 216.53. All gas production from qualified wells reported on 
the OGOR-A, including production not subject to royalty, counts toward 
the total lease RSV earned by both deep or ultra-deep wells on the 
lease.
    (b) This paragraph applies to any lease with a qualified phase 2 or 
phase 3 ultra-deep well that is not within an MMS-approved unit. Subject 
to the price conditions of Sec. 203.36, you must apply the RSV 
prescribed in Sec. 203.31 as required under the following paragraphs 
(b)(1) and (b)(2) of this section.
    (1) You must apply the RSV to the earliest gas production occurring 
on and after the later of May 18, 2007, or the date the first qualified 
phase 2 or phase 3 ultra-deep well that earns your lease the RSV begins 
production (other than test production).
    (2) You must apply the RSV to only gas production from qualified 
wells on your lease, regardless of their depth, for which you have met 
the requirements in Sec. 203.35 or Sec. 203.44.
    (c) This paragraph applies to any lease with a qualified phase 2 or 
phase 3 ultra-deep well where all or part of the lease is within an MMS-
approved unit. Under the unit agreement, a share of the production from 
all the qualified wells in the unit participating area would be 
allocated to your lease each month according to the participating area 
percentages. Subject to the price conditions of Sec. 203.36, you must 
apply the RSV prescribed in Sec. 203.31 as follows:
    (1) You must apply the RSV to the earliest gas production occurring 
on and after the later of May 18, 2007, or the date that the first 
qualified phase 2 or phase 3 ultra-deep well that earns your lease the 
RSV begins production (other than test production).
    (2) You must apply the RSV to only gas production:
    (i) From qualified wells on the non-unitized area of your lease, 
regardless of their depth, for which you have met the requirements in 
Sec. 203.35 or Sec. 203.44; and
    (ii) Allocated to your lease under an MMS-approved unit agreement 
from qualified wells on unitized areas of your lease and on other leases 
in participating areas of the unit, regardless of their depth, for which 
the requirements in Sec. 203.35 or Sec. 203.44 have been

[[Page 27]]

met. The allocated share under paragraph (a)(2)(ii) of this section does 
not increase the RSV for your lease.

    Example: The east half of your lease A is unitized with all of lease 
B. There is one qualified phase 2 ultra-deep well on the non-unitized 
portion of lease A that earns lease A an RSV of 35 BCF under Sec. 
203.31, one qualified deep well on the unitized portion of lease A 
(drilled after the ultra-deep well on the non-unitized portion of that 
lease) and a qualified phase 2 ultra-deep well on lease B that earns 
lease B a 35 BCF RSV under Sec. 203.31. The participating area 
percentages allocate 40 percent of production from both of the unit 
qualified wells to lease A and 60 percent to lease B. If the non-
unitized qualified phase 2 ultra-deep well on lease A produces 12 BCF, 
and the unitized qualified well on lease A produces 18 BCF, and the 
qualified well on lease B produces 37 BCF, then the production volume 
from and allocated to lease A to which the lease A RSV applies is 34 BCF 
[12 + (18 + 37)(0.40)]. The production volume allocated to lease B to 
which the lease B RSV applies is 33 BCF [(18 + 37)(0.60)]. None of the 
volumes produced from a well that is not within a unit participating 
area may be allocated to other leases in the unit.

    (d) You must begin paying royalties when the cumulative production 
of gas from all qualified wells on your lease, or allocated to your 
lease under paragraph (b) of this section, reaches the applicable RSV 
allowed under Sec. 203.31 or Sec. 203.41. For the month in which 
cumulative production reaches this RSV, you owe royalties on the portion 
of gas production from or allocated to your lease that exceeds the RSV 
remaining at the beginning of that month.



Sec. 203.34  To which production may an RSV earned by qualified phase 2 and phase 3 ultra-deep wells on my lease not be applied?

    You may not apply an RSV earned under Sec. 203.31:
    (a) To production from completions less than 15,000 feet TVD SS, 
except in cases where the qualified well is re-perforated in the same 
reservoir previously perforated deeper than 15,000 feet TVD SS;
    (b) To production from a deep well or ultra-deep well on any other 
lease, except as provided in paragraph (c) of Sec. 203.33;
    (c) To any liquid hydrocarbon (oil and condensate) volumes; or
    (d) To production from a deep well or ultra-deep well that commenced 
drilling before:
    (1) March 26, 2003, on a lease that is located entirely or partly in 
water less than 200 meters deep; or
    (2) May 18, 2007, on a lease that is located entirely in water more 
than 200 meters deep.



Sec. 203.35  What administrative steps must I take to use the RSV earned by a qualified phase 2 or phase 3 ultra-deep well?

    To use an RSV earned under Sec. 203.31:
    (a) You must notify the MMS Regional Supervisor for Production and 
Development in writing of your intent to begin drilling operations on 
all your ultra-deep wells.
    (b) Before beginning production, you must meet any production 
measurement requirements that the MMS Regional Supervisor for Production 
and Development has determined are necessary under 30 CFR part 250, 
subpart L.
    (c)(1) Within 30 days of the beginning of production from any wells 
that would become qualified phase 2 or phase 3 ultra-deep wells by 
satisfying the requirements of this section:
    (i) Provide written notification to the MMS Regional Supervisor for 
Production and Development that production has begun; and
    (ii) Request confirmation of the size of the RSV earned by your 
lease.
    (2) If you produced from a qualified phase 2 or phase 3 ultra-deep 
well before December 18, 2008, you must provide the information in 
paragraph (c)(1) of this section no later than January 20, 2009.
    (d) If you cannot produce from a well that otherwise meets the 
criteria for a qualified phase 2 ultra-deep well that is an ultra-deep 
short sidetrack before May 3, 2009, on a lease that is located entirely 
or partly in water less than 200 meters deep, or before May 3, 2013, on 
a lease that is located entirely in water more than 200 meters but less 
than 400 meters deep, the 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

[[Page 28]]

well involved, if it meets all the following criteria.
    (1) The delay occurred after drilling reached the total depth in 
your well.
    (2) Production (other than test production) was expected to begin 
from the well before May 3, 2009, on a lease that is located entirely or 
partly in water less than 200 meters deep or before May 3, 2013, on a 
lease that is located entirely in water more than 200 meters but less 
than 400 meters deep. You must provide a credible activity schedule with 
supporting documentation.
    (3) The delay in beginning production is for reasons beyond your 
control, such as adverse weather and accidents which MMS deems were 
unavoidable.



Sec. 203.36  Do I keep royalty relief if prices rise significantly?

    (a) You must pay royalties on all gas production to which an RSV 
otherwise would be applied under Sec. 203.33 for any calendar year in 
which the average daily closing New York Mercantile Exchange (NYMEX) 
natural gas price exceeds the applicable threshold price shown in the 
following table.

----------------------------------------------------------------------------------------------------------------
 A price threshold in year 2007 dollars of .
                     . .                                               Applies to . . .
----------------------------------------------------------------------------------------------------------------
 (1) $10.15 per MMBtu.......................  (i) The first 25 BCF of RSV earned under Sec.  203.31(a) by a
                                               phase 2 ultra-deep well on a lease that is located in water
                                               partly or entirely less than 200 meters deep issued before
                                               December 18, 2008; and
                                              (ii) Any RSV earned under Sec.  203.31(b) by a phase 2 ultra-deep
                                               well.
 (2) $4.55 per MMBtu........................  (i) Any RSV earned under Sec.  203.31(a) by a phase 3 ultra-deep
                                               well unless the lease terms prescribe a different price
                                               threshold;
                                              (ii) The last 10 BCF of the 35 BCF of RSV earned under Sec.
                                               203.31(a) by a phase 2 ultra-deep well on a lease that is located
                                               in water partly or entirely less than 200 meters deep issued
                                               before December 18, 2008 and that is not a non-converted lease;
                                              (iii) The last 15 BCF of the 35 BCF of RSV earned under Sec.
                                               203.31(a) by a phase 2 ultra-deep well on a non-converted lease;
                                              (iv) Any RSV earned under Sec.  203.31(a) by a phase 2 ultra-deep
                                               well on a lease in water partly or entirely less than 200 meters
                                               deep issued on or after December 18, 2008 unless the lease terms
                                               prescribe a different price threshold; and
                                              (v) Any RSV earned under Sec.  203.31(a) by a phase 2 ultra-deep
                                               well on a lease in water entirely more than 200 meters deep and
                                               entirely less than 400 meters deep.
 (3) $4.08 per MMBtu........................  (i) The first 20 BCF of RSV earned by a well that is located on a
                                               non-converted lease issued in OCS Lease Sale 178.
 (4) $5.83 per MMBtu........................  (i) The first 20 BCF of RSV earned by a well that is located on a
                                               non-converted lease issued in OCS Lease Sales 180, 182, 184, 185,
                                               or 187.
----------------------------------------------------------------------------------------------------------------

    (b) For purposes of paragraph (a) of this section, determine the 
threshold price for any calendar year after 2007 by:
    (1) Determining the percentage of change during the year in the 
Department of Commerce's implicit price deflator for the gross domestic 
product; and
    (2) Adjusting the threshold price for the previous year by that 
percentage.
    (c) The following examples illustrate how this section applies.

    Example 1: Assume that a lessee drills and begins producing from a 
qualified phase 2 ultra-deep well in 2008 on a lease issued in 2004 in 
less than 200 meters of water that earns the lease an RSV of 35 BCF. 
Further, assume the well produces a total of 18 BCF by the end of 2009 
and in both of those years, the average daily NYMEX closing natural gas 
price is less than $10.15 (adjusted for inflation after 2007). The 
lessee does not pay royalty on the 18 BCF because the gas price 
threshold under paragraph (a)(1) of this section applies to the first 25 
BCF of this RSV earned by this phase 2 ultra-deep well. In 2010, the 
well produces another 13 BCF. In that year, the average daily closing 
NYMEX natural gas price is greater than $4.55 per MMBtu (adjusted for 
inflation after 2007), but less than $10.15 per MMBtu (adjusted for 
inflation after 2007). The first 7 BCF produced in 2010 will exhaust the 
first 25 BCF (that is subject to the $10.15 threshold) of the 35 BCF RSV 
that the well earned. The lessee must pay royalty on the remaining 6 BCF 
produced in 2010, because it is subject to the $4.55 per MMBtu threshold 
under paragraph (a)(2)(ii) of this section which was exceeded.
    Example 2: Assume that a lessee:
    (1) Drills and produces from well no.1, a qualified deep well in 
2008 to a depth of 15,500 feet TVD SS that earns a 15 BCF RSV for the 
lease under Sec. 203.41, which would be subject to a price threshold of 
$10.15 per MMBtu (adjusted for inflation after 2007), meaning the lease 
is partly or entirely in less than 200 meters of water;

[[Page 29]]

    (2) Later in 2008 drills and produces from well no. 2, a second 
qualified deep well to a depth of 17,000 feet TVD SS that earns no 
additional RSV (see Sec. 203.41(c)(1)); and
    (3) In 2015, drills and produces from well no. 3, a qualified phase 
3 ultra-deep well that earns no additional RSV since the lease already 
has an RSV established by prior deep well production. Further assume 
that in 2015, the average daily closing NYMEX natural gas price exceeds 
$4.55 per MMBtu (adjusted for inflation after 2007) but does not exceed 
$10.15 per MMBtu (adjusted for inflation after 2007). In 2015, any 
remaining RSV earned by well no. 1 (which would have been applied to 
production from well nos. 1 and 2 in the intervening years), would be 
applied to production from all three qualified wells. Because the price 
threshold applicable to that RSV was not exceeded, the production from 
all three qualified wells would be royalty-free until the 15 BCF RSV 
earned by well no. 1 is exhausted.
    Example 3: Assume the same initial facts regarding the three wells 
as in Example 2. Further assume that well no. 1 stopped producing in 
2011 after it had produced 8 BCF, and that well no. 2 stopped producing 
in 2012 after it had produced 5 BCF. Two BCF of the RSV earned by well 
no. 1 remain. That RSV would be applied to production from well no. 3 
until it is exhausted, and the lessee therefore would not pay royalty on 
those 2 BCF produced in 2015, because the $10.15 per MMBtu (adjusted for 
inflation after 2007) price threshold is not exceeded. The determination 
of which price threshold applies to deep gas production depends on when 
the first qualified well earned the RSV for the lease, not on which 
wells use the RSV.
    Example 4: Assume that in February 2010 a lessee completes and 
begins producing from an ultra-deep well (at a depth of 21,500 feet TVD 
SS) on a lease located in 325 meters of water with no prior production 
from any deep well and no deep water royalty relief. The ultra-deep well 
would be a phase 2 ultra-deep well (see definition in Sec. 203.0), and 
would earn the lease an RSV of 35 BCF under Sec. Sec. 203.30 and 
203.31. Further assume that the average daily closing NYMEX natural gas 
price exceeds $4.55 per MMBtu (adjusted for inflation after 2007) but 
does not exceed $10.15 per MMBtu (adjusted for inflation after 2007) 
during 2010. Because the lease is located in more than 200 but less than 
400 meters of water, the $4.55 per MMBtu price threshold applies to the 
whole RSV (see paragraph (a)(2)(v) of this section), and the lessee will 
owe royalty on all gas produced from the ultra-deep well in 2010.

    (d) You must pay any royalty due under this section no later than 
March 31 of the year following the calendar year for which you owe 
royalty. If you do not pay by that date, you must pay late payment 
interest under Sec. 218.54 from April 1 until the date of payment.
    (e) Production volumes on which you must pay royalty under this 
section count as part of your RSV.

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

    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 a deep well or a phase 1 ultra-deep well?

    Your lease may receive an RSV under Sec. Sec. 203.41 through 
203.44, and may receive an RSS under Sec. Sec. 203.45 through 203.47, 
if it meets all the requirements of this section.
    (a) The lease is located in the GOM wholly west of 87 degrees, 30 
minutes West longitude in water depths entirely less than 400 meters 
deep.
    (b) The lease has not produced gas or oil from a well with a 
perforated interval the top of which is 18,000 feet TVD SS or deeper 
that commenced drilling either:
    (1) Before March 26, 2003, on a lease that is located partly or 
entirely in water less than 200 meters deep; or
    (2) Before May 18, 2007, on a lease that is located in water 
entirely more than 200 meters and entirely less than 400 meters deep.
    (c) In the case of a lease located partly or entirely in water less 
than 200 meters deep, the lease was issued in a lease sale held either:
    (1) Before January 1, 2001;
    (2) On or after January 1, 2001, and before January 1, 2004, and, in 
cases where the original lease terms provided for an RSV for deep gas 
production, the lessee has exercised the option provided for in Sec. 
203.49; or
    (3) On or after January 1, 2004, and the lease terms provide for 
royalty relief under Sec. Sec. 203.41 through 203.47 of this part. 
(Note: Because the original Sec. 203.41 has been divided into new 
Sec. Sec. 203.41 and 203.42 and subsequent sections have been 
redesignated as Sec. Sec. 203.43 through 203.48, royalty relief in 
lease terms for leases issued on or after January 1, 2004, should be 
read as referring to Sec. Sec. 203.41 through 203.48.)

[[Page 30]]

    (d) If the lease is located entirely in more than 200 meters and 
less than 400 meters of water, it must either:
    (1) Have been issued before November 28, 1995, and not been granted 
deep water royalty relief under 43 U.S.C. 1337(a)(3)(C), added by 
section 302 of the Deep Water Royalty Relief Act; or
    (2) Have been issued after November 28, 2000, and not been granted 
deep water royalty relief under Sec. Sec. 203.60 through 203.79.

[73 FR 69510, Nov. 18, 2008]



Sec. 203.41  If I have a qualified deep well or a qualified phase 1 ultra-deep well, what royalty relief would my lease earn?

    (a) To qualify for a suspension volume under paragraphs (b) or (c) 
of this section, your lease must meet the requirements in Sec. 203.40 
and the requirements in the following table.

------------------------------------------------------------------------
                               And if it later . .   Then your lease . .
 If your lease has not . . .            .                     .
------------------------------------------------------------------------
(1) produced gas or oil from  has a qualified deep  earns an RSV
 any deep well or ultra-deep   well or qualified     specified in
 well,                         phase 1 ultra-deep    paragraph (b) of
                               well,.                this section.
(2) produced gas or oil from  has a qualified deep  earns an RSV
 a well with a perforated      well with a           specified in
 interval whose top is         perforated interval   paragraph (c) of
 18,000 feet TVD SS or         whose top is 18,000   this section.
 deeper,                       feet TVD SS or
                               deeper or a
                               qualified phase 1
                               ultra-deep well,.
------------------------------------------------------------------------

    (b) If your lease meets the requirements in paragraph (a)(1) of this 
section, it earns the RSV prescribed in the following table:

------------------------------------------------------------------------
 If you have a qualified deep well
 or a qualified phase 1 ultra-deep     Then your lease earns an RSV on
           well that is:                this volume of gas production:
------------------------------------------------------------------------
(1) An original well with a          15 BCF.
 perforated 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 sidetrack
 interval the top of which is from    measured depth (rounded to the
 15,000 to less than 18,000 feet      nearest 100 feet) but no more than
 TVD SS,                              15 BCF.
(3) An original well with a          25 BCF.
 perforated interval the top of
 which is at least 18,000 feet TVD
 SS,
(4) A sidetrack with a perforated    4 BCF plus 600 MCF times sidetrack
 interval the top of which is at      measured depth (rounded to the
 least 18,000 feet TVD SS,            nearest 100 feet) but no more than
                                      25 BCF.
------------------------------------------------------------------------

    (c) If your lease meets the requirements in paragraph (a)(2) of this 
section, it earns the RSV prescribed in the following table. The RSV 
specified in this paragraph is in addition to any RSV your lease already 
may have earned from a qualified deep well with a perforated interval 
whose top is from 15,000 feet to less than 18,000 feet TVD SS.

----------------------------------------------------------------------------------------------------------------
    If you have a qualified deep well or a
qualified phase 1 ultra-deep well that is . .        Then you earn an RSV on this amount of gas production:
                      .
----------------------------------------------------------------------------------------------------------------
(1) An original well or a sidetrack with a     0 BCF.
 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 interval     4 BCF plus 600 MCF times sidetrack measured depth (rounded to the
 the top of which is 18,000 feet TVD SS or      nearest 100 feet) but no more than 10 BCF.
 deeper,
----------------------------------------------------------------------------------------------------------------

    (d) Lessees may request a refund of or recoup royalties paid on 
production from qualified wells on a lease that is located in water 
entirely deeper than 200 meters but entirely less than 400 meters deep 
that:
    (1) Occurs before December 18, 2008; and
    (2) Is subject to application of an RSV under either Sec. 203.31 or 
Sec. 203.41.
    (e) The following examples illustrate how this section applies, 
assuming your lease meets the location, prior

[[Page 31]]

production, and lease issuance conditions in Sec. 203.40 and paragraph 
(a) of this section:

    Example 1: If you have a qualified deep well that is an original 
well with a perforated interval the top of which is 16,000 feet TVD SS, 
your lease earns an RSV of 15 BCF under paragraph (b)(1) of this 
section. This RSV must be applied to gas production from all qualified 
wells on your lease, as prescribed in Sec. Sec. 203.43 and 203.48. 
However, if the top of the perforated interval is 18,500 feet TVD SS, 
the RSV is 25 BCF according to paragraph (b)(3) of this section.
    Example 2: If you have a qualified deep well that is a sidetrack, 
with a perforated interval the top of which is 16,000 feet TVD SS and a 
sidetrack measured depth of 6,789 feet, we round the measured depth to 
6,800 feet and your lease earns an RSV of 8.08 BCF under paragraph 
(b)(2) of this section. This RSV would be applied to gas production from 
all qualified wells on your lease, as prescribed in Sec. Sec. 203.43 
and 203.48.
    Example 3: If you have a qualified deep well that is a sidetrack, 
with a perforated interval the top of which is 16,000 feet TVD SS and a 
sidetrack measured depth of 19,500 feet, your lease earns an RSV of 15 
BCF. This RSV would be applied to gas production from all qualified 
wells on your lease, as prescribed in Sec. Sec. 203.43 and 203.48, even 
though 4 BCF plus 600 MCF per foot of sidetrack measured depth equals 
15.7 BCF because paragraph (b)(2) of this section limits the RSV for a 
sidetrack at the amount an original well to the same depth would earn.
    Example 4: If you have drilled and produced a deep well with a 
perforated interval the top of which is 16,000 feet TVD SS before March 
26, 2003 (and the well therefore is not a qualified well and has earned 
no RSV under this section), and later drill:
    (i) A deep well with a perforated interval the top of which is 
17,000 feet TVD SS, your lease earns no RSV (see paragraph (c)(1) of 
this section);
    (ii) A qualified deep well that is an original well with a 
perforated interval the top of which is 19,000 feet TVD SS, your lease 
earns an RSV of 10 BCF under paragraph (c)(2) of this section. This RSV 
would be applied to gas production from qualified wells on your lease, 
as prescribed in Sec. Sec. 203.43 and 203.48; or
    (iii) A qualified deep well that is a sidetrack with a perforated 
interval the top of which is 19,000 feet TVD SS, that has a sidetrack 
measured depth of 7,000 feet, your lease earns an RSV of 8.2 BCF under 
paragraph (c)(3) of this section. This RSV would be applied to gas 
production from qualified wells on your lease, as prescribed in 
Sec. Sec. 203.43 and 203.48.
    Example 5: If you have a qualified deep well that is an original 
well with a perforated interval the top of which is 16,000 feet TVD SS, 
and later drill a second qualified well that is an original well with a 
perforated interval the top of which is 19,000 feet TVD SS, we increase 
the total RSV for your lease from 15 BCF to 25 BCF under paragraph 
(c)(2) of this section. We will apply that RSV to gas production from 
all qualified wells on your lease, as prescribed in Sec. Sec. 203.43 
and 203.48. If the second well has a perforated interval the top of 
which is 22,000 feet TVD SS (instead of 19,000 feet), the total RSV for 
your lease would increase to 25 BCF only in 2 situations: (1) If the 
second well was a phase 1 ultra-deep well, i.e., if drilling began 
before May 18, 2007, or (2) the exception in Sec. 203.31(b) applies. In 
both situations, your lease must be partly or entirely in less than 200 
meters of water and production must begin on this well before May 3, 
2009. If drilling of the second well began on or after May 18, 2007, the 
second well would be qualified as a phase 2 or phase 3 ultra-deep well 
and, unless the exception in Sec. 203.31(b) applies, would not earn any 
additional RSV (as prescribed in Sec. 203.30), so the total RSV for 
your lease would remain at 15 BCF.
    Example 6: If you have a qualified deep well that is a sidetrack, 
with a perforated interval the top of which is 16,000 feet TVD SS and a 
sidetrack measured depth of 4,000 feet, and later drill a second 
qualified well that is a sidetrack, with a perforated interval the top 
of which is 19,000 feet TVD SS and a sidetrack measured depth of 8,000 
feet, we increase the total RSV for your lease from 6.4 BCF [4 + (600 * 
4,000)/1,000,000] to 15.2 BCF {6.4 + [4 + (600 * 8,000)/
1,000,000)]{time}  under paragraphs (b)(2) and (c)(3) of this section. 
We would apply that RSV to gas production from all qualified wells on 
your lease, as prescribed in Sec. Sec. 203.43 and 203.48. The 
difference of 8.8 BCF represents the RSV earned by the second sidetrack 
that has a perforated interval the top of which is deeper than 18,000 
feet TVD SS.

[73 FR 69510, Nov. 18, 2008]



Sec. 203.42  What conditions and limitations apply to royalty relief for deep wells and phase 1 ultra-deep wells?

    The conditions and limitations in the following table apply to 
royalty relief under Sec. 203.41.

[[Page 32]]



------------------------------------------------------------------------
               If . . .                            Then . . .
------------------------------------------------------------------------
(a) Your lease has produced gas or     your lease cannot earn an RSV
 oil from a well with a perforated      under Sec.  203.41 as a result
 interval the top of which is 18,000    of drilling any subsequent deep
 feet TVD SS or deeper,                 wells or phase 1 ultra-deep
                                        wells.
(b) You determine RSV under Sec.      that determination establishes
 203.41 for the first qualified deep    the total RSV available for that
 well or qualified phase 1 ultra-deep   drilling depth interval on your
 well on your lease (whether an         lease (i.e., either 15,000-
 original well or a sidetrack)          18,000 feet TVD SS, or 18,000
 because you drilled and produced it    feet TVD SS and deeper),
 within the time intervals set forth    regardless of the number of
 in the definitions for qualified       subsequent qualified wells you
 wells,                                 drill to that depth interval.
(c) A qualified deep well or           the RSV earned by that well under
 qualified phase 1 ultra-deep well on   Sec.  203.41 applies only to
 your lease is within a unitized        production from qualified wells
 portion of your lease,                 on or allocated to your lease
                                        and not to other leases within
                                        the unit.
(d) Your qualified deep well or        the lease with the perforated
 qualified phase 1 ultra-deep well is   interval that initially produces
 a directional well (either an          earns the RSV. However, if the
 original well or a sidetrack)          perforated interval crosses a
 drilled across a lease line,           lease line, the lease where the
                                        surface of the well is located
                                        earns the RSV.
(e) You earn an RSV under Sec.        that RSV is in addition to any
 203.41,                                RSS for your lease under Sec.
                                        203.45 that results from a
                                        different wellbore.
(f) Your lease earns an RSV under      the RSV is not forfeited or
 Sec.  203.41 and later produces       terminated, but you may not
 from a well that is not a qualified    apply the RSV under Sec.
 well,                                  203.41 to production from the
                                        non-qualified well.
(g) You qualify for an RSV under       you still owe minimum royalties
 paragraphs (b) or (c) of Sec.         or rentals in accordance with
 203.41,                                your lease terms.
(h) You transfer your lease,           unused RSVs transfer to a
                                        successor lessee and expire with
                                        the lease.
------------------------------------------------------------------------

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

[73 FR 69512, Nov. 18, 2008]



Sec. 203.43  To which production do I apply the RSV earned from qualified deep wells or qualified phase 1 ultra-deep wells on my lease?

    (a) You must apply the RSV prescribed in Sec. 203.41(b) and (c) to 
gas volumes produced from qualified wells on or after May 3, 2004, 
reported on the OGOR-A for your lease under Sec. 216.53, as and to the 
extent prescribed in Sec. Sec. 203.43 and 203.48.
    (1) Except as provided in paragraph (a)(2) of this section, all gas 
production from qualified wells reported on the OGOR-A, including 
production that is not subject to royalty, counts toward the lease RSV.
    (2) Production to which an RSS applies under Sec. Sec. 203.45 and 
203.46 does not count toward the lease RSV.
    (b) This paragraph applies to any lease with a qualified deep well 
or qualified phase 1 ultra-deep well when no part of the lease is within 
an MMS-approved unit. Subject to the price conditions in Sec. 203.48, 
you must apply the RSV prescribed in Sec. 203.41 as required under the 
following paragraphs (b)(1) and (b)(2) of this section.
    (1) You must apply the RSV to the earliest gas production occurring 
on and after the later of:
    (i) May 3, 2004, for an RSV earned by a qualified deep well or 
qualified phase 1 ultra-deep well on a lease that is located entirely or 
partly in water less than 200 meters deep;
    (ii) May 18, 2007, for an RSV earned by a qualified deep well on a 
lease that is located entirely in water more than 200 meters deep; or
    (iii) The date that the first qualified well that earns your lease 
the RSV begins production (other than test production).
    (2) You must apply the RSV to only gas production from qualified 
wells on your lease, regardless of their depth, for which you have met 
the requirements in Sec. 203.35 or Sec. 203.44.

    Example 1: On a lease in water less than 200 meters deep, you began 
drilling an original deep well with a perforated interval the top of 
which is 18,200 feet TVD SS in September 2003, that became a qualified 
deep well in July 2004, when it began producing and using the RSV that 
it earned. You subsequently drill another original deep well with a 
perforated interval the top of which is 16,600 feet TVD SS, which 
becomes a qualified deep well when production begins in August 2008.

[[Page 33]]

The first well earned an RSV of 25 BCF (see Sec. 203.41(a)(1) and 
(b)(3)). You must apply any remaining RSV each month beginning in August 
2008 to production from both wells until the 25 BCF RSV is fully 
utilized according to paragraph (b)(2) of this section. If the second 
well had begun production in August 2009, it would not be a qualified 
deep well because it started production after expiration in May 2009 of 
the ability to qualify for royalty relief in this water depth, and could 
not share any of the remaining RSV (see definition of a qualified deep 
well in Sec. 203.0).
    Example 2: On a lease in water between 200 and 400 meters deep, you 
begin drilling an original deep well with a perforated interval the top 
of which is 17,100 feet TVD SS in November 2010 that becomes a qualified 
deep well in June 2011 when it begins producing and using the RSV. You 
subsequently drill another original deep well with a perforated interval 
the top of which is 15,300 feet TVD SS which becomes a qualified deep 
well by beginning production in October 2011 (see definition of a 
qualified deep well in Sec. 203.0). Only the first well earns an RSV 
equal to 15 BCF (see Sec. 203.41(a) and (b)). You must apply any 
remaining RSV each month beginning in October 2011 to production from 
both qualified deep wells until the 15 BCF RSV is fully utilized 
according to paragraph (b)(2) of this section.

    (c) This paragraph applies to any lease with a qualified deep well 
or qualified phase 1 ultra-deep well when all or part of the lease is 
within an MMS-approved unit. Under the unit agreement, a share of the 
production from all the qualified wells in the unit participating area 
would be allocated to your lease each month according to the 
participating area percentages. Subject to the price conditions in Sec. 
203.48, you must apply the RSV prescribed under Sec. 203.41 as required 
under the following paragraphs (c)(1) through (c)(3) of this section.
    (1) You must apply the RSV to the earliest gas production occurring 
on and after the later of:
    (i) May 3, 2004, for an RSV earned by a qualified well or qualified 
phase 1 ultra-deep well on a lease that is located entirely or partly in 
water less than 200 meters deep;
    (ii) May 18, 2007, for an RSV earned by a qualified deep well on a 
lease that is located entirely in water more than 200 meters deep; or
    (iii) The date that the first qualified well that earns your lease 
the RSV begins production (other than test production).
    (2) You must apply the RSV to only gas production:
    (i) From all qualified wells on the non-unitized area of your lease, 
regardless of their depth, for which you have met the requirements in 
Sec. 203.35 or Sec. 203.44; and,
    (ii) Allocated to your lease under an MMS-approved unit agreement 
from qualified wells on unitized areas of your lease and on unitized 
areas of other leases in the unit, regardless of their depth, for which 
the requirements in Sec. 203.35 or Sec. 203.44 have been met.
    (3) The allocated share under paragraph (c)(2)(ii) of this section 
does not increase the RSV for your lease. None of the volumes produced 
from a well that is not within a unit participating area may be 
allocated to other leases in the unit.

    Example: The east half of your lease A is unitized with all of lease 
B. There is one qualified 19,000-foot TVD SS deep well on the non-
unitized portion of lease A, one qualified 18,500-foot TVD SS deep well 
on the unitized portion of lease A, and a qualified 19,400-foot TVD SS 
deep well on lease B. The participating area percentages allocate 32 
percent of production from both of the unit qualified deep wells to 
lease A and 68 percent to lease B. If the non-unitized qualified deep 
well on lease A produces 12 BCF and the unitized qualified deep well on 
lease A produces 15 BCF, and the qualified deep well on lease B produces 
10 BCF, then the production volume from and allocated to lease A to 
which the lease an RSV applies is 20 BCF [12 + (15 + 10) * (0.32)]. The 
production volume allocated to lease B to which the lease B RSV applies 
is 17 BCF [(15 + 10) * (0.68)].

    (d) You must begin paying royalties when the cumulative production 
of gas from all qualified wells on your lease, or allocated to your 
lease under paragraph (c) of this section, reaches the applicable RSV 
allowed under Sec. 203.31 or Sec. 203.41. For the month in which 
cumulative production reaches this RSV, you owe royalties on the portion 
of gas production that exceeds the RSV remaining at the beginning of 
that month.
    (e) You may not apply the RSV allowed under Sec. 203.41 to:
    (1) Production from completions less than 15,000 feet TVD SS, except 
in cases where the qualified deep well is

[[Page 34]]

re-perforated in the same reservoir previously perforated deeper than 
15,000 feet TVD SS;
    (2) Production from a deep well or phase 1 ultra-deep well on any 
other lease, except as provided in paragraph (c) of this section;
    (3) Any liquid hydrocarbon (oil and condensate) volumes; or
    (4) Production from a deep well or phase 1 ultra-deep well that 
commenced drilling before:
    (i) March 26, 2003, on a lease that is located entirely or partly in 
water less than 200 meters deep, or
    (ii) May 18, 2007, on a lease that is located entirely in water more 
than 200 meters deep.

[73 FR 69512, Nov. 18, 2008]



Sec. 203.44  What administrative steps must I take to use the royalty suspension volume?

    (a) You must notify the MMS Regional Supervisor for Production and 
Development in writing of your intent to begin drilling operations on 
all deep wells and phase 1 ultra-deep wells; and
    (b) Within 30 days of the beginning of production from all wells 
that would become qualified wells by satisfying the requirements of this 
section, you must:
    (1) Provide written notification to the 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) You must provide the information in paragraph (b) of this 
section by January 20, 2009 if you produced before December 18, 2008 
from a qualified deep well or qualified phase 1 ultra-deep well on a 
lease that is located entirely in water more than 200 meters and less 
than 400 meters deep.
    (e) The MMS Regional Supervisor for Production and Development may 
extend the deadline for beginning production for up to one year for a 
well that cannot begin production before the applicable date prescribed 
in the definition of ``qualified deep well'' in Sec. 203.0 if it meets 
all of the following criteria.
    (1) The well otherwise meets the criteria in the definition of a 
qualified deep well in Sec. 203.0.
    (2) The delay in production occurred after reaching total depth in 
the well.
    (3) Production (other than test production) was expected to begin 
from the well before the applicable deadline in the definition of a 
qualified deep well in Sec. 203.0. You must provide a credible activity 
schedule with supporting documentation.
    (4) The delay in beginning production is for reasons beyond your 
control, such as adverse weather and accidents which MMS deems were 
unavoidable.

[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004. 
Redesignated and amended at 73 FR 69512, 69513, Nov. 18, 2008]



Sec. 203.45  If I drill a certified unsuccessful well, what royalty relief will my lease earn?

    Your lease may earn a royalty suspension supplement. Subject to 
paragraph (d) of this section, the royalty suspension supplement is in 
addition to any royalty suspension volume your lease may earn under 
Sec. 203.41.
    (a) If you drill a certified unsuccessful well and you satisfy the 
administrative requirements of Sec. 203.47, subject to the price 
conditions in Sec. 203.48, your lease earns an RSS shown in the 
following table. The RSS is shown in billions of cubic feet of gas 
equivalent (BCFE) or in thousands of cubic feet of gas equivalent (MCFE) 
and is applicable to oil and gas production as prescribed in Sec. 
204.46.

----------------------------------------------------------------------------------------------------------------
  If you have a certified unsuccessful well        Then your lease earns an RSS on this volume of oil and gas
                   that is:                       production as prescribed in this section and Sec.  203.46:
----------------------------------------------------------------------------------------------------------------
(1) An original well and your lease has not    5 BCFE.
 produced gas or oil from a deep well or an
 ultra-deep well,

[[Page 35]]

 
(2) A sidetrack (with a sidetrack measured     0.8 BCFE plus 120 MCFE times sidetrack measured depth (rounded to
 depth of at least 10,000 feet) and your        the nearest 100 feet) but no more than 5 BCFE.
 lease has not produced gas or oil from a
 deep well or an ultra-deep well,
(3) An original well or a sidetrack (with a    2 BCFE.
 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) This paragraph applies to oil and gas volumes you report on the 
OGOR-A for your lease under Sec. 216.53.
    (1) You must apply the RSS prescribed in paragraph (a) of this 
section, in accordance with the requirements in Sec. 203.46, to all oil 
and gas produced from the lease:
    (i) On or after December 18, 2008, if your lease is located in water 
more than 200 meters but less than 400 meters deep; or
    (ii) On or after May 3, 2004, if your lease is located in water 
partly or entirely less than 200 meters deep.
    (2) Production to which an RSV applies under Sec. Sec. 203.31 
through 203.33 and Sec. Sec. 203.41 through 203.43 does not count 
toward the lease RSS. All other production, including production that is 
not subject to royalty, counts toward the lease RSS.

    Example 1: If you drill a certified unsuccessful well that is an 
original well to a target 19,000 feet TVD SS, your lease earns an RSS of 
5 BCFE that would be applied to gas and oil production if your lease has 
not previously produced from a deep well or an ultra-deep well, or you 
earn an RSS of 2 BCFE of gas and oil production if your lease has 
previously produced from a deep well with a perforated interval from 
15,000 to less than 18,000 feet TVD SS, as prescribed in Sec. 203.46.
    Example 2: If you drill a certified unsuccessful well that is a 
sidetrack that reaches a target 19,000 feet TVD SS, that has a sidetrack 
measured depth of 12,545 feet, and your lease has not produced gas or 
oil from any deep well or ultra-deep well, MMS rounds the sidetrack 
measured depth to 12,500 feet and your lease earns an RSS of 2.3 BCFE of 
gas and oil production as prescribed in 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 an RSS as a certified 
unsuccessful well later produces from a perforated interval the top of 
which is 15,000 feet TVD or deeper and becomes a qualified well, it will 
be subject to the following conditions:
    (1) Beginning on the date production starts, you must stop applying 
the royalty suspension supplement earned by that wellbore to your lease 
production.
    (2) If the completion of this qualified well is on your lease or, in 
the case of a directional well, is on another lease, then you must 
subtract from the royalty suspension volume earned by that qualified 
well the royalty suspension supplement amounts earned by that wellbore 
that have already been applied either on your lease or any other lease. 
The difference represents the royalty suspension volume earned by the 
qualified well.
    (f) If the same wellbore that earned a royalty suspension supplement 
later has a sidetrack drilled from that wellbore, you are not required 
to subtract any royalty suspension supplement earned by that wellbore 
from the royalty suspension volume that may be earned by the sidetrack.
    (g) You owe minimum royalties or rentals in accordance with your 
lease terms notwithstanding any royalty

[[Page 36]]

suspension supplements under this section.

[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004; 72 
FR 25198, May 4, 2007; 73 FR 15890, Mar. 26, 2008. Redesignated and 
amended at 73 FR 69512, 69513, Nov. 18, 2008; 74 FR 46907, Sept. 14, 
2009]



Sec. 203.46  To which production do I apply the royalty suspension supplements from drilling one or two certified unsuccessful wells on my lease?

    (a) Subject to the requirements of Sec. Sec. 203.40, 203.43, 
203.45, 203.47, and 203.48, you must apply an RSS in Sec. 203.45 to the 
earliest oil and gas production:
    (1) Occurring on and after the day you file the information under 
Sec. 204.47(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. You use only 2 BCFE of the royalty 
suspension supplement before the oil wells deplete. You must use up the 
15 BCF of royalty suspension volume before you use the remaining 3 BCFE 
of the royalty suspension supplement for gas produced from the qualified 
well.

    (c) If you have no current production on which to apply the RSS 
allowed under Sec. 203.45, your RSS 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 RSS allowed under Sec. 203.45 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 RSS for your lease to production from the other leases in 
the unit.
    (f) You must begin or resume paying royalties when cumulative gas 
and oil production from, or allocated under 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.

[69 FR 3510, Jan. 26, 2004. Redesignated and amended at 73 FR 69512, 
69514, Nov. 18, 2008]



Sec. 203.47  What administrative steps do I take to obtain and use the royalty suspension supplement?

    (a) Before you start drilling a well on your lease targeted to a 
reservoir at least 18,000 feet TVD SS, you must notify, in writing, the 
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.

[[Page 37]]

    (c) If you commenced drilling a well that otherwise meets the 
criteria for a certified unsuccessful well on a lease located entirely 
in more than 200 meters and entirely less than 400 meters of water on or 
after May 18, 2007, and finished it before December 18, 2008, you must 
provide the information in paragraph (b) of this section no later than 
February 17, 2009.

[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004. 
Redesignated and amended at 69512, 69514, Nov. 18, 2008]



Sec. 203.48  Do I keep royalty relief if prices rise significantly?

    (a) You must pay royalties on all gas and oil production for which 
an RSV or an RSS otherwise would be allowed under Sec. Sec. 203.40 
through 203.47 for any calendar year when the average daily closing 
NYMEX natural gas price exceeds the applicable threshold price shown in 
the following table.

----------------------------------------------------------------------------------------------------------------
                                                                                      the applicable threshold
  For a lease located in water . . .                And issued . . .                       price is . . .
----------------------------------------------------------------------------------------------------------------
(1) Partly or entirely less than 200   before December 18, 2008,.................  $10.15 per MMBtu, adjusted
 meters deep,                                                                       annually after calendar year
                                                                                    2007 for inflation.
(2) Partly or entirely less than 200   after December 18, 2008,                    $4.55 per MMBtu, adjusted
 meters deep,                                                                       annually after calendar year
                                                                                    2007 for inflation unless
                                                                                    the lease terms prescribe a
                                                                                    different price threshold.
(3) Entirely more than 200 meters and  on any date,                                $4.55 per MMBtu, adjusted
 entirely less than 400 meters deep,                                                annually after calendar year
                                                                                    2007 for inflation unless
                                                                                    the lease terms prescribe a
                                                                                    different price threshold.
----------------------------------------------------------------------------------------------------------------

    (b) Determine the threshold price for any calendar year after 2007 
by adjusting the threshold price in the previous year by the percentage 
that the implicit price deflator for the gross domestic product, as 
published by the Department of Commerce, changed during the calendar 
year.
    (c) You must pay any royalty due under this section no later than 
March 31 of the year following the calendar year for which you owe 
royalty. If you do not pay by that date, you must pay late payment 
interest under Sec. 218.54 from April 1 until the date of payment.
    (d) Production volumes on which you must pay royalty under this 
section count as part of your RSV and RSS.

[73 FR 69514, Nov. 18, 2008]



Sec. 203.49  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 203.48 if you have a lease issued 
with royalty relief provisions for deep-well drilling. Such leases:
    (1) Must be issued as part of an OCS lease sale held after January 
1, 2001, and before April 1, 2004; and
    (2) Must be located wholly west of 87 degrees, 30 minutes West 
longitude in the GOM entirely or partly in water less than 200 meters 
deep.
    (b) To exercise the option under paragraph (a) of this section, you 
must notify, in writing, the 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 203.48.
    (d) Exercising the option under paragraph (a) of this section is 
irrevocable. If you do not exercise this option, then the terms of your 
lease apply.

[69 FR 3510, Jan. 26, 2004. Redesignated and amended at 73 FR 69512, 
69515, Nov. 18, 2008]

[[Page 38]]

                  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 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

[[Page 39]]

    (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 Pre-Act Deep Water Leases and for Development and 
                           Expansion Projects



Sec. 203.60  Who may apply for royalty relief on a case-by-case basis in deep water in the Gulf of Mexico or offshore of Alaska?

    You may apply for royalty relief under Sec. Sec. 203.61(b) and 
203.62 for an individual lease, unit or project if you:
    (a) Hold a pre-Act lease (as defined in Sec. 203.0) that we have 
assigned to an authorized field (as defined in Sec. 203.0);
    (b) Propose an expansion project (as defined in Sec. 203.0); or
    (c) Propose a development project (as defined in Sec. 203.0).

[73 FR 69515, Nov. 18, 2008]



Sec. 203.61  How do I assess my chances for getting relief?

    You may ask for a nonbinding assessment (a formal opinion on whether 
a field would qualify for royalty relief) before turning in your first 
complete application on an authorized field. This field must have a 
qualifying well under 30 CFR part 250, subpart A, or be on a lease that 
has allocated production under an approved unit agreement.
    (a) To request a nonbinding assessment, you must:
    (1) Submit a draft application in the format and detail specified in 
guidance from the MMS regional office for the GOM;
    (2) Propose to drill at least one more appraisal well if you get a 
favorable assessment; and
    (3) Pay a fee under Sec. 203.3.
    (b) You must wait at least 90 days after receiving our assessment to 
apply for relief under Sec. 203.62.
    (c) This assessment is not binding because a complete application 
may contain more accurate information that does not support our original 
assessment. It will help you decide whether your proposed inputs for 
evaluating economic viability and your supporting data and assumptions 
are adequate.



Sec. 203.62  How do I apply for relief?

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

[73 FR 69515, Nov. 18, 2008]

[[Page 40]]



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]



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


[[Page 41]]

    (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]



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

[[Page 42]]

or the regulations of this chapter (e.g., fuel gas).
    (a) For authorized fields, the minimum royalty-suspension volumes 
are:
    (1) 17.5 million barrels of oil equivalent (MMBOE) for fields in 200 
to 400 meters of water;
    (2) 52.5 MMBOE for fields in 400 to 800 meters of water; and
    (3) 87.5 MMBOE for fields in more than 800 meters of water.
    (b) For development projects, any relief we grant applies only to 
project wells and replaces the royalty relief, if any, with which we 
issued your lease.
    (c) If your project is economic given the royalty relief with which 
we issued your lease, we will reject the application.
    (d) If the lease has earned or may earn deep gas royalty relief 
under Sec. Sec. 203.40 through 203.49 or ultra-deep gas royalty relief 
under Sec. Sec. 203.30 through 203.36, we will take the deep gas 
royalty relief or ultra-deep gas royalty relief into account in 
determining whether further royalty relief for a development project is 
necessary for production to be economic.
    (e) If neither paragraph (c) nor (d) of this section apply, the 
minimum royalty suspension volumes are as shown in the following table:

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

    (f) If your application includes pre-Act leases in different 
categories of water depth, we apply the minimum royalty suspension 
volume for the deepest such lease then assigned to the field. We base 
the water depth and makeup of a field on the water-depth delineations in 
the ``Lease Terms and Economic Conditions'' map and the ``Fields 
Directory'' documents and updates in effect at the time your application 
is deemed complete. These publications are available from the MMS Gulf 
of Mexico Regional Office.
    (g) You will get a royalty suspension volume above the minimum if we 
determine that you need more to make the field or development project 
economic.
    (h) For expansion projects, the minimum royalty suspension volume 
equals 10 percent of the median of the distribution of known recoverable 
resources upon which we based approval of your application from all 
reservoirs included in your project plus any suspension volumes required 
under 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.
    (i) The royalty suspension volume applicable to specific leases will 
continue through the end of the month in which cumulative production 
reaches that volume. You must calculate cumulative production from all 
the leases in the authorized field or project that are entitled to share 
the royalty suspension volume.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1876, Jan. 15, 2002; 73 
FR 58472, Oct. 7, 2008; 73 FR 69515, Nov. 18, 2008]



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

[[Page 43]]

203.81, 203.90, and 203.91 describe what these reports must include. The 
MMS Regional Office for your region 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, the MMS
                                   that is subject     Regional Director
                                   to the approved     for your region
                                   royalty             may extend the
                                   suspension volume.  due date up to 30
                                                       days.
------------------------------------------------------------------------


[67 FR 1876, Jan. 15, 2002, as amended at 73 FR 69515, Nov. 18, 2008]



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  Production from
 to your authorized field after    your authorized     the assigned
 we approve relief.                field's royalty     eligible lease(s)
                                   suspension volume   counts toward the
                                   determined under    royalty
                                   Sec.  203.69.      suspension volume
                                                       for the
                                                       authorized field,
                                                       but the eligible
                                                       lease will not
                                                       share any
                                                       remaining royalty
                                                       suspension volume
                                                       for the
                                                       authorized field
                                                       after the
                                                       eligible lease
                                                       has produced the
                                                       volume applicable
                                                       under Sec.
                                                       260.114 of this
                                                       chapter.
(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.
(3) We assign another lease that  In our evaluation   (i) You toll the
 you operate to your field while   of your             time period for
 we are evaluating your            authorized field,   evaluation until
 application.                      we will take into   you modify your
                                   account the value   application to be
                                   of any royalty      consistent with
                                   relief the added    the newly
                                   lease already has   constituted
                                   under Sec.         field;
                                   260.114 or its     (ii) We have an
                                   lease document.     additional 60
                                   If we find your     days to review
                                   authorized field    the new
                                   still needs         information; and
                                   additional         (iii) The assigned
                                   royalty             pre-Act lease or
                                   suspension          royalty
                                   volume, that        suspension lease
                                   volume will be at   shares the
                                   least the           royalty
                                   combined royalty    suspension we
                                   suspension volume   grant to the
                                   to which all        newly constituted
                                   added leases on     field. An
                                   the field are       eligible lease
                                   entitled, or the    does not share
                                   minimum             the royalty
                                   suspension volume   suspension we
                                   of the authorized   grant to the new
                                   field, whichever    field. If you do
                                   is greater.         not agree to
                                                       toll, we will
                                                       have to reject
                                                       your application
                                                       due to incomplete
                                                       information.
                                                       Production from
                                                       an assigned
                                                       eligible lease
                                                       counts toward the
                                                       royalty
                                                       suspension volume
                                                       that we grant
                                                       under Sec.
                                                       203.69 for your
                                                       authorized field,
                                                       but you will not
                                                       owe royalty on
                                                       production from
                                                       the eligible
                                                       lease until it
                                                       has produced the
                                                       volume applicable
                                                       under Sec.
                                                       260.114 of this
                                                       chapter.

[[Page 44]]

 
(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            For any field
 Act, eligible, or royalty         production from     based relief, the
 suspension lease from field A     the well counts     past production
 to field B.                       toward the          for that well
                                   royalty             will not count
                                   suspension volume   toward any
                                   that we grant       royalty
                                   under Sec.         suspension volume
                                   203.69 to field B.  that we grant
                                                       under Sec.
                                                       203.69 to field
                                                       A. Moreover, past
                                                       production from
                                                       that well will
                                                       count toward the
                                                       royalty
                                                       suspension volume
                                                       applicable for
                                                       the lease under
                                                       Sec.  260.114 if
                                                       the well is on an
                                                       eligible lease or
                                                       under Sec.
                                                       260.124 if the
                                                       well is on a
                                                       royalty
                                                       suspension lease.
------------------------------------------------------------------------

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

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1877, Jan. 15, 2002; 73 
FR 58472, Oct. 7, 2008]



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.

[[Page 45]]

    (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 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

[[Page 46]]

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, you may voluntarily give up relief by sending a letter to that 
effect to the MMS Regional office for your region.

[73 FR 69516, Nov. 18, 2008]



Sec. 203.78  Do I keep relief approved by MMS under Sec. Sec. 203.60-203.77 for my lease, unit or project if prices rise significantly?

    If prices rise above a base price threshold for light sweet crude 
oil or natural gas, you must pay full royalties on production otherwise 
subject to royalty relief approved by MMS under Sec. Sec. 203.60-203.77 
for your lease, unit or project as prescribed in this section.
    (a) The following table shows the base price threshold for various 
types of leases, subject to paragraph (b) of this section. Note that, 
for post-November 2000 deepwater leases in the GOM, price thresholds 
apply on a lease basis, so different leases on the same development 
project or expansion project approved for royalty relief may have 
different price thresholds.

----------------------------------------------------------------------------------------------------------------
                  For . . .                                    The base price threshold is . . .
----------------------------------------------------------------------------------------------------------------
(1) Pre-Act leases in the GOM,                 set by statute.
(2) Post-November 2000 deep water leases in    indicated in your original lease agreement or, if none, those in
 the GOM or leases offshore of Alaska for       the Notice of Sale under which your lease was issued.
 which the lease or Notice of Sale set a base
 price threshold,
(3) Post-November 2000 deep water leases in    the threshold set by statute for pre-Act leases.
 the GOM or leases offshore of Alaska for
 which the lease or Notice of Sale did not
 set a base price threshold,
----------------------------------------------------------------------------------------------------------------

    (b) An exception may occur if we determine that the price thresholds 
in paragraphs (a)(2) or (a)(3) mean the royalty suspension volume set 
under Sec. 203.69 and in lease terms would provide inadequate 
encouragement to increase production or development, in which 
circumstance we could specify a different set of price thresholds on a 
case-by-case basis.
    (c) Suppose your base oil price threshold set under paragraph (a) is 
$28.00 per barrel, and the daily closing NYMEX light sweet crude oil 
prices for the previous calendar year exceeds $28.00 per barrel, as 
adjusted in paragraph (h) of this section. In this case, we retract the 
royalty relief authorized in this subpart and you must:
    (1) Pay royalties on all oil production for the previous year at the 
lease stipulated royalty rate plus interest (under 30 U.S.C. 1721 and 
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.

[[Page 47]]

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

[73 FR 69516, Nov. 18, 2008]



Sec. 203.79  How do I appeal MMS's decisions related to royalty relief for a deepwater lease or a development or expansion project?

    (a) Once we have designated your lease as part of a field and 
notified you and other affected operators of the designation, you can 
request reconsideration by sending the 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 royalty relief under other sections in the subpart?

    We may grant royalty relief when it serves the statutory purposes 
summarized in Sec. 203.1 and our formal relief programs, including but 
not limited to the applicable levels of the royalty suspension volumes 
and price thresholds, provide inadequate encouragement to promote 
development or increase production. Unless your lease lies offshore of 
Alaska or wholly west of 87 degrees, 30 minutes West longitude in the 
GOM, your lease must be producing to qualify for relief. Before you may 
apply for royalty relief apart from our programs for end-of-life leases 
or for pre-Act deep water leases and development and expansion projects, 
we must agree that your lease or project has two or more of the 
following characteristics:
    (a) The lease has produced for a substantial period and the lessee 
can recover significant additional resources. Significant additional 
resources means enough to allow production for at least

[[Page 48]]

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, as amended at 73 FR 69516, Nov. 18, 2008]

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

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002; 73 
FR 69516, Nov. 18, 2008]



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.

[[Page 49]]

    (1) Your application for royalty relief must contain enough 
information on finances, economics, reservoirs, G&G characteristics, 
production, and engineering estimates for us to determine whether:
    (i) We should grant relief under the law, and
    (ii) The requested relief will ultimately recover more resources and 
return a reasonable profit on project investments.
    (2) Your fabricator confirmation and post-production development 
reports must contain enough information for us to verify that your 
application reasonably represented your plans.
    (b) Applicants (respondents) are Federal OCS oil and gas lessees. 
Applications are required to obtain or retain a benefit. Therefore, if 
you apply for royalty relief, you must provide this information. We will 
protect information considered proprietary under applicable law and 
under regulations at 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 5438, 1849 C Street, NW., Washington, DC 
20240.

[63 FR 2618, Jan. 16, 1998, as amended at 65 FR 2875, Jan. 19, 2000; 74 
FR 46907, Sept. 14, 2009]



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:

[[Page 50]]

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

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



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

[[Page 51]]

and paleo correlation markers at least every 500-feet,
    (ii) The 1-inch type log shows missing sections from other logs 
where faulting occurs,
    (iii) The 5-inch electric log shows pay zones and pay counts and 
labeled points used in establishing resistivity of the formation, 100 
percent water saturated (Ro) and the resistivity of the 
undisturbed formation (Rt), and
    (iv) The 5-inch porosity logs show pay zones and pay counts and 
labeled points used in establishing reservoir porosity or labeled points 
showing values used in calculating reservoir porosity such as bulk 
density or transit time;
    (2) Digital copies of all well logs spudded before December 1, 1995;
    (3) Core data, if available;
    (4) Well correlation sections;
    (5) Pressure data;
    (6) Production test results;
    (7) Pressure-volume-temperature analysis, if available; and
    (8) A table listing the wells and completions, and indicating which 
sands and fault blocks will be targeted for completion or recompletion.
    (c) Map interpretations which includes for each reservoir in the 
field:
    (1) Structure maps consisting of top and base of sand maps showing 
well and seismic shot point locations;
    (2) Isopach maps for net sand, net oil, net gas, all with well 
locations;
    (3) Maps indicating well surface and bottom hole locations, location 
of development facilities, and shot points; and
    (4) An explanation for excluding the reservoirs you are not planning 
to develop.
    (d) Reservoir-specific data which includes:
    (1) Probability of reservoir occurrence with hydrocarbons;
    (2) Probability the hydrocarbon in the reservoir is all oil and the 
probability it is all gas;
    (3) Distributions or point estimates (accompanied by explanations of 
why distributions less appropriately reflect the uncertainty) for the 
parameters used to estimate reservoir size, i.e., acres and net 
thickness;
    (4) Most likely values for porosity, salt water saturation, volume 
factor for oil formation, and volume factor for gas formation;
    (5) Distributions or point estimates (accompanied by explanations of 
why distributions less appropriately reflect the uncertainty) for 
recovery efficiency (in percent) and oil or gas recovery (in stock-tank-
barrels per acre-foot or in thousands of cubic feet per acre foot);
    (6) A gas/oil ratio distribution or point estimate (accompanied by 
explanations of why distributions less appropriately reflect the 
uncertainty) for each reservoir;
    (7) A yield distribution or point estimate (accompanied by 
explanations of why distributions less appropriately reflect the 
uncertainty) for each gas reservoir; and
    (8) Reserve or resource distribution by reservoir.
    (e) Aggregated reserve and resource data which includes:
    (1) The aggregated distributions for reserves and resources (in BOE) 
and oil fraction for your field computed by the resource module of our 
RSVP model;
    (2) A description of anticipated hydrocarbon quality (i.e., specific 
gravity); and
    (3) The ranges within the aggregated distribution for reserves and 
resources that define the development and production scenarios presented 
in the engineering and production reports. Typically there will be three 
ranges specified by two positive reserve and resource points on the 
aggregated distribution. The range at the low end of the distribution 
will be associated with the conservative development and production 
scenario; the middle range will be related to the most likely 
development and production scenario; and, the high end range will be 
consistent with the optimistic development and production scenario.

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



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,

[[Page 52]]

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

[[Page 53]]

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

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



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 
Regional Director for your region certifying when construction started 
on your system; and
    (c) Evidence of an appropriate down payment or equal action that 
you've started acquiring the approved system.

[63 FR 2618, Jan. 16, 1998, as amended at 73 FR 69516, Nov. 18, 2008]



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]

[[Page 54]]

Subpart I--OCS Sulfur [Reserved]



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 55]]



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 56]]

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 57]]

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 58]]

    (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 59]]

    (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 60]]



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

[[Page 61]]

206.62 Does MMS protect information I provide?

                          Subpart C_Federal Oil

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

                          Subpart D_Federal Gas

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

                          Subpart E_Indian Gas

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

                        Transportation Allowances

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

                          Processing Allowances

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

                         Subpart F_Federal Coal

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

[[Page 62]]

                     Subpart G_Other Solid Minerals

206.301 Value basis for royalty computation.

                     Subpart H_Geothermal Resources

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

Subpart I--OCS Sulfur [Reserved]

                          Subpart J_Indian Coal

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

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

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



                      Subpart A_General Provisions



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  What is the purpose of this subpart?

    (a) This subpart applies to all oil produced from Indian (tribal and 
allotted) oil and gas leases (except leases on the Osage Indian 
Reservation, Osage County, Oklahoma). This subpart does not apply to 
Federal leases, including Federal leases for which revenues are shared 
with Alaska Native Corporations. This subpart:
    (1) Establishes the value of production for royalty purposes 
consistent with the Indian mineral leasing laws, other applicable laws, 
and lease terms;
    (2) Explains how you as a lessee must calculate the value of 
production for royalty purposes consistent with applicable statutes and 
lease terms; and
    (3) Is intended to ensure that the United States discharges its 
trust responsibilities for administering Indian oil and gas leases under 
the governing

[[Page 63]]

Indian mineral leasing laws, treaties, and lease terms.
    (b) If the regulations in this subpart are inconsistent with a 
Federal statute, a settlement agreement or written agreement as these 
terms are defined in this paragraph, or an express provision of an oil 
and gas lease subject to this subpart, then the statute, settlement 
agreement, written agreement, or lease provision will govern to the 
extent of the inconsistency. For purposes of this paragraph:
    (1) Settlement agreement means a settlement agreement that is 
between the United States and a lessee, or between an individual Indian 
mineral owner and a lessee and is approved by the United States, 
resulting from administrative or judicial litigation; and
    (2) Written agreement means a written agreement between the lessee 
and the MMS Director (and approved by the tribal lessor for tribal 
leases) establishing a method to determine the value of production from 
any lease that MMS expects at least would approximate the value 
established under this subpart.
    (c) The MMS or Indian tribes may audit, or perform other compliance 
reviews, and require a lessee to adjust royalty payments and reports.

[72 FR 71241, Dec. 17, 2007]



Sec. 206.51  What definitions apply to this subpart?

    For purposes of this subpart:
    Affiliate means a person who controls, is controlled by, or is under 
common control with another person.
    (1) Ownership or common ownership of more than 50 percent of the 
voting securities, or instruments of ownership, or other forms of 
ownership, of another person constitutes control. Ownership of less than 
10 percent constitutes a presumption of noncontrol that MMS may rebut.
    (2) If there is ownership or common ownership of 10 through 50 
percent of the voting securities or instruments of ownership, or other 
forms of ownership, of another person, MMS will consider the following 
factors in determining whether there is control in a particular case:
    (i) The extent to which there are common officers or directors;
    (ii) With respect to the voting securities, or instruments of 
ownership, or other forms of ownership:
    (A) The percentage of ownership or common ownership;
    (B) The relative percentage of ownership or common ownership 
compared to the percentage(s) of ownership by other persons;
    (C) Whether a person is the greatest single owner; and
    (D) Whether there is an opposing voting bloc of greater ownership;
    (iii) Operation of a lease, plant, or other facility;
    (iv) The extent of participation by other owners in operations and 
day-to-day management of a lease, plant, or other facility; and
    (v) Other evidence of power to exercise control over or common 
control with another person.
    (3) Regardless of any percentage of ownership or common ownership, 
relatives, either by blood or marriage, are affiliates.
    Area means a geographic region at least as large as the defined 
limits of an oil and/or gas field in which oil and/or gas lease products 
have similar quality, economic, and legal characteristics.
    Arm's-length contract means a contract or agreement between 
independent persons who are not affiliates and who have opposing 
economic interests regarding that contract. To be considered arm's 
length for any production month, a contract must satisfy this definition 
for that month, as well as when the contract was executed.
    Audit means a review, conducted in accordance with generally 
accepted accounting and auditing standards, of royalty payment 
compliance activities of lessees or other interest holders who pay 
royalties, rents, or bonuses on Indian leases.
    BLM means the Bureau of Land Management of the Department of the 
Interior.
    Condensate means liquid hydrocarbons (generally exceeding 40 degrees 
of API gravity) recovered at the surface without resorting to 
processing.

[[Page 64]]

Condensate is the mixture of liquid hydrocarbons that results from 
condensation of petroleum hydrocarbons existing initially in a gaseous 
phase in an underground reservoir.
    Contract means any oral or written agreement, including amendments 
or revisions thereto, between two or more persons and enforceable by law 
that with due consideration creates an obligation.
    Exchange agreement means an agreement where one person agrees to 
deliver oil to another person at a specified location in exchange for 
oil deliveries at another location, and other consideration. Exchange 
agreements:
    (1) May or may not specify prices for the oil involved;
    (2) Frequently specify dollar amounts reflecting location, quality, 
or other differentials;
    (3) Include buy/sell agreements, which specify prices to be paid at 
each exchange point and may appear to be two separate sales within the 
same agreement, or in separate agreements; and
    (4) May include, but are not limited to, exchanges of produced oil 
for specific types of oil (e.g., WTI); exchanges of produced oil for 
other oil at other locations (location trades); exchanges of produced 
oil for other grades of oil (grade trades); and multi-party exchanges.
    Field means a geographic region situated over one or more subsurface 
oil and gas reservoirs encompassing at least the outermost boundaries of 
all oil and gas accumulations known to be within those reservoirs 
vertically projected to the land surface. Onshore fields usually are 
given names, and their official boundaries are often designated by oil 
and gas regulatory agencies in the respective states in which the fields 
are located.
    Gathering means the movement of lease production to a central 
accumulation or treatment point on the lease, unit, or communitized 
area, or to a central accumulation or treatment point off the lease, 
unit, or communitized area as approved by BLM operations personnel.
    Gross proceeds means the total monies and other consideration 
accruing for the disposition of oil produced. Gross proceeds also 
include, but are not limited to, the following examples:
    (1) Payments for services, such as dehydration, marketing, 
measurement, or gathering that the lessee must perform at no cost to the 
lessor in order to put the production into marketable condition;
    (2) The value of services to put the production into marketable 
condition, such as salt water disposal, that the lessee normally 
performs but that the buyer performs on the lessee's behalf;
    (3) Reimbursements for harboring or terminaling fees;
    (4) Tax reimbursements, even though the Indian royalty interest may 
be exempt from taxation;
    (5) Payments made to reduce or buy down the purchase price of oil to 
be produced in later periods, by allocating those payments over the 
production whose price the payment reduces and including the allocated 
amounts as proceeds for the production as it occurs; and
    (6) Monies and all other consideration to which a seller is 
contractually or legally entitled, but does not seek to collect through 
reasonable efforts.
    Indian tribe means any Indian tribe, band, nation, pueblo, 
community, rancheria, colony, or other group of Indians for which any 
minerals or interest in minerals is held in trust by the United States 
or that is subject to Federal restriction against alienation.
    Individual Indian mineral owner means any Indian for whom minerals 
or an interest in minerals is held in trust by the United States or who 
holds title subject to Federal restriction against alienation.
    Lease means any contract, profit-share arrangement, joint venture, 
or other agreement issued or approved by the United States under an 
Indian mineral leasing law that authorizes exploration for, development 
or extraction of, or removal of lease products. Depending on the 
context, lease may also refer to the land area covered by that 
authorization.
    Lease products means any leased minerals attributable to, 
originating from, or allocated to Indian leases.
    Lessee means any person to whom the United States, a tribe, or 
individual Indian mineral owner issues a lease, and

[[Page 65]]

any person who has been assigned an obligation to make royalty or other 
payments required by the lease. Lessee includes:
    (1) Any person who has an interest in a lease (including operating 
rights owners); and
    (2) An operator, purchaser, or other person with no lease interest 
who makes royalty payments to MMS or the lessor on the lessee's behalf
    Lessor means an Indian tribe or individual Indian mineral owner who 
has entered into a lease.
    Like-quality oil means oil that has similar chemical and physical 
characteristics.
    Location differential means an amount paid or received (whether in 
money or in barrels of oil) under an exchange agreement that results 
from differences in location between oil delivered in exchange and oil 
received in the exchange. A location differential may represent all or 
part of the difference between the price received for oil delivered and 
the price paid for oil received under a buy/sell exchange agreement.
    Marketable condition means lease products that are sufficiently free 
from impurities and otherwise in a condition that they will be accepted 
by a purchaser under a sales contract typical for the field or area.
    MMS means the Minerals Management Service of the Department of the 
Interior.
    Net means to reduce the reported sales value to account for 
transportation instead of reporting a transportation allowance as a 
separate entry on Form MMS-2014.
    NYMEX price means the average of the New York Mercantile Exchange 
(NYMEX) settlement prices for light sweet oil delivered at Cushing, 
Oklahoma, calculated as follows:
    (1) Sum the prices published for each day during the calendar month 
of production (excluding weekends and holidays) for oil to be delivered 
in the nearest month of delivery for which NYMEX futures prices are 
published corresponding to each such day; and
    (2) Divide the sum by the number of days on which those prices are 
published (excluding weekends and holidays).
    Oil means a mixture of hydrocarbons that existed in the liquid phase 
in natural underground reservoirs and remains liquid at atmospheric 
pressure after passing through surface separating facilities and is 
marketed or used as such. Condensate recovered in lease separators or 
field facilities is considered to be oil.
    Operating rights owner, also known as a working interest owner, 
means any person who owns operating rights in a lease subject to this 
subpart. A record title owner is the owner of operating rights under a 
lease until the operating rights have been transferred from record title 
(see Bureau of Land Management regulations at 43 CFR 3100.0-5(d)).
    Person means any individual, firm, corporation, association, 
partnership, consortium, or joint venture (when established as a 
separate entity).
    Processing means any process designed to remove elements or 
compounds (hydrocarbon and nonhydrocarbon) from gas, including 
absorption, adsorption, or refrigeration. Field processes that normally 
take place on or near the lease, such as natural pressure reduction, 
mechanical separation, heating, cooling, dehydration, and compression, 
are not considered processing. The changing of pressures and/or 
temperatures in a reservoir is not considered processing.
    Quality differential means an amount paid or received under an 
exchange agreement (whether in money or in barrels of oil) that results 
from differences in API gravity, sulfur content, viscosity, metals 
content, and other quality factors between oil delivered and oil 
received in the exchange. A quality differential may represent all or 
part of the difference between the price received for oil delivered and 
the price paid for oil received under a buy/sell agreement.
    Sale means a contract between two persons where:
    (1) The seller unconditionally transfers title to the oil to the 
buyer and does not retain any related rights such as the right to buy 
back similar quantities of oil from the buyer elsewhere;
    (2) The buyer pays money or other consideration for the oil; and

[[Page 66]]

    (3) The parties' intent is for a sale of the oil to occur.
    Sales type code means the contract type or general disposition 
(e.g., arm's-length or non-arm's-length) of production from the lease. 
The sales type code applies to the sales contract, or other disposition, 
and not to the arm's-length or non-arm's-length nature of a 
transportation allowance.
    Transportation allowance means a deduction in determining royalty 
value for the reasonable, actual costs of moving oil to a point of sale 
or delivery off the lease, unit area, or communitized area. The 
transportation allowance does not include gathering costs.
    WTI means West Texas Intermediate.
    You means a lessee, operator, or other person who pays royalties 
under this subpart.

[72 FR 71241, Dec. 17, 2007, as amended at 73 FR 15890, Mar. 26, 2008]



Sec. 206.52  How do I calculate royalty value for oil that I or my affiliate sell(s) or exchange(s) under an arm's-length contract?

    (a) The value of oil under this section is the gross proceeds 
accruing to the seller under the arm's-length contract, less applicable 
allowances determined under Sec. Sec. 206.56 and 206.57. If the arm's-
length sales contract does not reflect the total consideration actually 
transferred either directly or indirectly from the buyer to the seller, 
you must value the oil sold as the total consideration accruing to the 
seller. Use this section to value oil that:
    (1) You sell under an arm's-length sales contract; or
    (2) You sell or transfer to your affiliate or another person under a 
non-arm's-length contract and that affiliate or person, or another 
affiliate of either of them, then sells the oil under an arm's-length 
contract.
    (b) If you have multiple arm's-length contracts to sell oil produced 
from a lease that is valued under paragraph (a) of this section, the 
value of the oil is the volume-weighted average of the total 
consideration established under this section for all contracts for the 
sale of oil produced from that lease.
    (c) If MMS determines that the value under paragraph (a) of this 
section does not reflect the reasonable value of the production due to 
either:
    (1) Misconduct by or between the parties to the arm's-length 
contract; or
    (2) Breach of your duty to market the oil for the mutual benefit of 
yourself and the lessor, MMS will establish a value based on other 
relevant matters.
    (i) The MMS will not use this provision to simply substitute its 
judgment of the market value of the oil for the proceeds received by the 
seller under an arm's-length sales contract.
    (ii) The fact that the price received by the seller under an arm's-
length contract is less than other measures of market price is 
insufficient to establish breach of the duty to market unless MMS finds 
additional evidence that the seller acted unreasonably or in bad faith 
in the sale of oil produced from the lease.
    (d) You must base value on the highest price that the seller can 
receive through legally enforceable claims under the oil sales contract. 
If the seller fails to take proper or timely action to receive prices or 
benefits to which it is entitled, you must base value on that obtainable 
price or benefit.
    (1) In some cases the seller may apply timely for a price increase 
or benefit allowed under the oil sales contract, but the purchaser 
refuses the seller's request. If this occurs, and the seller takes 
reasonable documented measures to force purchaser compliance, you will 
owe no additional royalties unless or until the seller receives monies 
or consideration resulting from the price increase or additional 
benefits. This paragraph (d)(1) does not permit you to avoid your 
royalty payment obligation if a purchaser fails to pay, pays only in 
part, or pays late.
    (2) Any contract revisions or amendments that reduce prices or 
benefits to which the seller is entitled must be in writing and signed 
by all parties to the arm's-length contract.
    (e) If you or your affiliate enter(s) into an arm's-length exchange 
agreement, or multiple sequential arm's-length exchange agreements, then 
you must value your oil under this paragraph.
    (1) If you or your affiliate exchange(s) oil at arm's length for WTI

[[Page 67]]

or equivalent oil at Cushing, Oklahoma, you must value the oil using the 
NYMEX price, adjusted for applicable location and quality differentials 
under paragraph (e)(3) of this section and any transportation costs 
under paragraph (e)(4) of this section and Sec. Sec. 206.56 and 206.57.
    (2) If you do not exchange oil for WTI or equivalent oil at Cushing, 
but exchange it at arm's length for oil at another location and 
following the arm's-length exchange(s) you or your affiliate sell(s) the 
oil received in the exchange(s) under an arm's-length contract, then you 
must use the gross proceeds under your or your affiliate's arm's-length 
sales contract after the exchange(s) occur(s), adjusted for applicable 
location and quality differentials under paragraph (e)(3) of this 
section and any transportation costs under paragraph (e)(4) of this 
section and Sec. Sec. 206.56 and 206.57.
    (3) You must adjust your gross proceeds for any location or quality 
differential, or other adjustments, you received or paid under the 
arm's-length exchange agreement(s). If MMS determines that any exchange 
agreement does not reflect reasonable location or quality differentials, 
MMS may adjust the differentials you used based on relevant information. 
You may not otherwise use the price or differential specified in an 
arm's-length exchange agreement to value your production.
    (4) If you value oil under this paragraph, MMS will allow a 
deduction, under Sec. Sec. 206.56 and 206.57, for the reasonable, 
actual costs to transport the oil:
    (i) From the lease to a point where oil is given in exchange; and
    (ii) If oil is not exchanged to Cushing, Oklahoma, from the point 
where oil is received in exchange to the point where the oil received in 
exchange is sold.
    (5) If you or your affiliate exchange(s) your oil at arm's length, 
and neither paragraph (e)(1) nor (e)(2) of this section applies, MMS 
will establish a value for the oil based on relevant matters. After MMS 
establishes the value, you must report and pay royalties and any late 
payment interest owed based on that value.
    (f) You may not deduct any costs of gathering as part of a 
transportation deduction or allowance.
    (g) You must also comply with Sec. 206.54.

[72 FR 71241, Dec. 17, 2007]



Sec. 206.53  How do I determine value for oil that I or my affiliate do(es) not sell under an arm's-length contract?

    (a) The unit value of your oil not sold under an arm's-length 
contract is the volume-weighted average of the gross proceeds paid or 
received by you or your affiliate, including your refining affiliate, 
for purchases or sales under arm's-length contracts.
    (1) When calculating that unit value, use only purchases or sales of 
other like-quality oil produced from the field (or the same area if you 
do not have sufficient arm's-length purchases or sales of oil produced 
from the field) during the production month.
    (2) You may adjust the gross proceeds determined under paragraph (a) 
of this section for transportation costs under paragraph (c) of this 
section and Sec. Sec. 206.56 and 206.57 before including those proceeds 
in the volume-weighted average calculation.
    (3) If you have purchases away from the field(s) and cannot 
calculate a price in the field because you cannot determine the seller's 
cost of transportation that would be allowed under paragraph (c) of this 
section and Sec. Sec. 206.56 and 206.57, you must not include those 
purchases in your weighted-average calculation.
    (b) Before calculating the volume-weighted average, you must 
normalize the quality of the oil in your or your affiliate's arm's-
length purchases or sales to the same gravity as that of the oil 
produced from the lease. Use applicable gravity adjustment tables for 
the field (or the same general area for like-quality oil if you do not 
have gravity adjustment tables for the specific field) to normalize for 
gravity.

    Example to paragraph (b): 1. Assume that a lessee, who owns a 
refinery and refines the oil produced from the lease at that refinery, 
purchases like-quality oil from other producers in the same field at 
arm's length for use as feedstock in its refinery. Further assume that 
the oil produced from the lease

[[Page 68]]

that is being valued under this section is Wyoming general sour with an 
API gravity of 23.5[deg]. Assume that the refinery purchases at arm's 
length oil (all of which must be Wyoming general sour) in the following 
volumes of the API gravities stated at the prices and locations 
indicated:

----------------------------------------------------------------------------------------------------------------
 
----------------------------------------------------------------------------------------------------------------
10,000 bbl.........................  24.5[deg].............  $34.70/bbl............  Purchased in the field.
8,000 bbl..........................  24.0[deg].............  34.00/bbl.............  Purchased at the refinery
                                                                                      after the third-party
                                                                                      producer transported it to
                                                                                      the refinery, and the
                                                                                      lessee does not know the
                                                                                      transportation costs.
9,000 bbl..........................  23.0[deg].............  33.25/bbl.............  Purchased in the field.
4,000 bbl..........................  22.0[deg].............  33.00/bbl.............  Purchased in the field.
----------------------------------------------------------------------------------------------------------------

    2. Because the lessee does not know the costs that the seller of the 
8,000 bbl incurred to transport that volume to the refinery, that volume 
will not be included in the volume-weighted average price calculation. 
Further assume that the gravity adjustment scale provides for a 
deduction of $0.02 per \1/10\ degree API gravity below 34[deg]. 
Normalized to 23.5[deg] (the gravity of the oil being valued under this 
section), the prices of each of the volumes that the refiner purchased 
that are included in the volume-weighted average calculation are as 
follows:

----------------------------------------------------------------------------------------------------------------
 
----------------------------------------------------------------------------------------------------------------
10,000 bbl.......................  24.5[deg]..........  $34.50.............  (1.0[deg] difference over 23.5[deg]
                                                                              = $0.20 deducted).
9,000 bbl........................  23.0[deg]..........  33.35..............  (0.5[deg] difference under
                                                                              23.5[deg] = $0.10 added).
4,000 bbl........................  22.0[deg]..........  33.30..............  (1.5[deg] difference under
                                                                              23.5[deg] = $0.30 added).
----------------------------------------------------------------------------------------------------------------

    3. The volume-weighted average price is ((10,000 bbl x $34.50/bbl) + 
(9,000 bbl x $33.35/bbl) + (4,000 bbl x $33.30/bbl)) / 23,000 bbl = 
$33.84/bbl. That price will be the value of the oil produced from the 
lease and refined prior to an arm's-length sale, under this section.

    (c) If you value oil under this section, MMS will allow a deduction, 
under Sec. Sec. 206.56 and 206.57, for the reasonable, actual costs:
    (1) That you incur to transport oil that you or your affiliate 
sell(s), which is included in the weighted-average price calculation, 
from the lease to the point where the oil is sold; and
    (2) That the seller incurs to transport oil that you or your 
affiliate purchase(s), which is included in the weighted-average cost 
calculation, from the property where it is produced to the point where 
you or your affiliate purchase(s) it. You may not deduct any costs of 
gathering as part of a transportation deduction or allowance.
    (d) If paragraphs (a) and (b) of this section result in an 
unreasonable value for your production as a result of circumstances 
regarding that production, the MMS Director may establish an alternative 
valuation method.
    (e) You must also comply with Sec. 206.54.

[72 FR 71241, Dec. 17, 2007]



Sec. 206.54  How do I fulfill the lease provision regarding valuing production on the basis of the major portion of like-quality oil?

    (a) For any Indian leases that provide that the Secretary may 
consider the highest price paid or offered for a major portion of 
production (major portion) in determining value for royalty purposes, if 
data are available to compute a major portion, MMS will, where 
practicable, compare the value determined in accordance with this 
section with the major portion. The value to be used in determining the 
value of production, for royalty purposes, will be the higher of those 
two values.
    (b) For purposes of this paragraph, major portion means the highest 
price paid or offered at the time of production for the major portion of 
oil production from the same field. The major portion will be calculated 
using like-quality oil sold under arm's-length contracts from the same 
field (or, if

[[Page 69]]

necessary to obtain a reasonable sample, from the same area) for each 
month. All such oil production will be arrayed from highest price to 
lowest price (at the bottom). The major portion is that price at which 
50 percent by volume plus one barrel of oil (starting from the bottom) 
is sold.

[72 FR 71241, Dec. 17, 2007]



Sec. 206.55  What are my responsibilities to place production into marketable condition and to market the production?

    You must place oil in marketable condition and market the oil for 
the mutual benefit of yourself and the Indian lessor at no cost to the 
lessor, unless the lease agreement provides otherwise. If, in the 
process of marketing the oil or placing it in marketable condition, your 
gross proceeds are reduced because services are performed on your behalf 
that would be your responsibility, and if you valued the oil using your 
or your affiliate's gross proceeds (or gross proceeds received in the 
sale of oil received in exchange) under Sec. 206.52, you must increase 
value to the extent that your gross proceeds are reduced.

[72 FR 71241, Dec. 17, 2007]



Sec. 206.56  Transportation allowances--general.

    (a) Where the value of oil has been determined under Sec. 206.52 or 
Sec. 206.53 of this subpart at a point (e.g., sales point or point of 
value determination) off the lease, MMS shall allow a deduction for the 
reasonable, actual costs incurred by the lessee to transport oil to a 
point off the lease; provided, however, that no transportation allowance 
will be granted for transporting oil taken as Royalty-In-Kind (RIK); or
    (b)(1) Except as provided in paragraph (b)(2) of this section, the 
transportation allowance deduction on the basis of a sales type code may 
not exceed 50 percent of the value of the oil at the point of sale as 
determined under Sec. 206.52 of this subpart. Transportation costs 
cannot be transferred between sales type codes or to other products.
    (2) Upon request of a lessee, MMS may approve a transportation 
allowance deduction in excess of the limitation prescribed by paragraph 
(b)(1) of this section. The lessee must demonstrate that the 
transportation costs incurred in excess of the limitation prescribed in 
paragraph (b)(1) of this section were reasonable, actual, and necessary. 
An application for exception (using Form MMS-4393, Request to Exceed 
Regulatory Allowance Limitation) must contain all relevant and 
supporting documentation necessary for MMS to make a determination. 
Under no circumstances may the value, for royalty purposes, under any 
sales type code, be reduced to zero.
    (c) Transportation costs must be allocated among all products 
produced and transported as provided in Sec. 206.57. Transportation 
allowances for oil shall be expressed as dollars per barrel.
    (d) If, after a review or audit, MMS determines that a lessee has 
improperly determined a transportation allowance authorized by this 
subpart, then the lessee will pay any additional royalties, plus 
interest determined in accordance with 30 CFR 218.54, or will be 
entitled to a credit without interest.

[61 FR 5455, Feb. 12, 1996. Redesignated and amended at 72 FR 71241, 
Dec. 17, 2007; 73 FR 15890, Mar. 26, 2008]



Sec. 206.57  Determination of transportation allowances.

    (a) Arm's-length transportation contracts. (1)(i) For transportation 
costs incurred by a lessee under an arm's-length contract, the 
transportation allowance shall be the reasonable, actual costs incurred 
by the lessee for transporting oil under that contract, except as 
provided in paragraphs (a)(1)(ii) and (a)(1)(iii) of this section, 
subject to monitoring, review, audit, and adjustment. The lessee shall 
have the burden of demonstrating that its contract is arm's-length. Such 
allowances shall be subject to the provisions of paragraph (f) of this 
section. Before any deduction may be taken, the lessee must submit a 
completed page one of Form MMS-4110 (and Schedule 1), Oil Transportation 
Allowance Report, in accordance with paragraph (c)(1) of this section. A 
transportation allowance may be claimed retroactively for a period of 
not more than 3 months prior to the first day of the month that Form 
MMS-4110 is filed with MMS, unless

[[Page 70]]

MMS approves a longer period upon a showing of good cause by the lessee.
    (ii) In conducting reviews and audits, MMS will examine whether the 
contract reflects more than the consideration actually transferred 
either directly or indirectly from the lessee to the transporter for the 
transportation. If the contract reflects more than the total 
consideration, then MMS may require that the transportation allowance be 
determined in accordance with paragraph (b) of this section.
    (iii) If MMS determines that the consideration paid under an arm's-
length transportation contract does not reflect the reasonable value of 
the transportation because of misconduct by or between the contracting 
parties, or because the lessee otherwise has breached its duty to the 
lessor to market the production for the mutual benefit of the lessee and 
the lessor, then MMS shall require that the transportation allowance be 
determined in accordance with paragraph (b) of this section. When MMS 
determines that the value of the transportation may be unreasonable, MMS 
will notify the lessee and give the lessee an opportunity to provide 
written information justifying the lessee's transportation costs.
    (2)(i) If an arm's-length transportation contract includes more than 
one liquid product, and the transportation costs attributable to each 
product cannot be determined from the contract, then the total 
transportation costs shall be allocated in a consistent and equitable 
manner to each of the liquid products transported in the same proportion 
as the ratio of the volume of each product (excluding waste products 
which have no value) to the volume of all liquid products (excluding 
waste products which have no value). Except as provided in this 
paragraph, no allowance may be taken for the costs of transporting lease 
production which is not royalty-bearing without MMS approval.
    (ii) Notwithstanding the requirements of paragraph (i), the lessee 
may propose to MMS a cost allocation method on the basis of the values 
of the products transported. MMS shall approve the method unless it 
determines that it is not consistent with the purposes of the 
regulations in this part.
    (3) If an arm's-length transportation contract includes both gaseous 
and liquid products, and the transportation costs attributable to each 
product cannot be determined from the contract, the lessee shall propose 
an allocation procedure to MMS. The lessee may use the oil 
transportation allowance determined in accordance with its proposed 
allocation procedure until MMS issues its determination on the 
acceptability of the cost allocation. The lessee shall submit all 
available data to support its proposal. The initial proposal must be 
submitted by June 30, 1988 or within 3 months after the last day of the 
month for which the lessee requests a transportation allowance, 
whichever is later (unless MMS approves a longer period). MMS shall then 
determine the oil transportation allowance based upon the lessee's 
proposal and any additional information MMS deems necessary.
    (4) Where the lessee's payments for transportation under an arm's-
length contract are not on a dollar-per-unit basis, the lessee shall 
convert whatever consideration is paid to a dollar value equivalent for 
the purposes of this section.
    (5) Where an arm's-length sales contract price, or a posted price, 
includes a provision whereby the listed price is reduced by a 
transportation factor, MMS will not consider the transportation factor 
to be a transportation allowance. The transportation factor may be used 
in determining the lessee's gross proceeds for the sale of the product. 
The transportation factor may not exceed 50 percent of the base price of 
the product without MMS approval.
    (b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length transportation contract or has no contract, including those 
situations where the lessee performs transportation services for itself, 
the transportation allowance will be based upon the lessee's reasonable, 
actual costs as provided in this paragraph. All transportation 
allowances deducted under a non-arms-length or no-contract situation are 
subject to monitoring, review, audit, and adjustment. Before any 
estimated or actual deduction may be

[[Page 71]]

taken, the lessee must submit a completed Form MMS-4110 in its entirety 
in accordance with paragraph (c)(2) of this section. A transportation 
allowance may be claimed retroactively for a period of not more than 3 
months prior to the first day of the month that Form MMS-4110 is filed 
with MMS, unless MMS approves a longer period upon a showing of good 
cause by the lessee. MMS will monitor the allowance deductions to 
determine whether lessees are taking deductions that are reasonable and 
allowable. When necessary or appropriate, MMS may direct a lessee to 
modify its actual transportation allowance deduction.
    (2) The transportation allowance for non-arms-length or no-contract 
situations shall be based upon the lessee's actual costs for 
transportation during the reporting period, including operating and 
maintenance expenses, overhead, and either depreciation and a return on 
undepreciated capital investment in accordance with paragraph 
(b)(2)(iv)(A) of this section, or a cost equal to the initial capital 
investment in the transportation system multiplied by a rate of return 
in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable 
capital costs are generally those for depreciable fixed assets 
(including costs of delivery and installation of capital equipment) 
which are an integral part of the transportation system.
    (i) Allowable operating expenses include: Operations supervision and 
engineering; operations labor; fuel; utilities; materials; ad valorem 
property taxes; rent; supplies; and any other directly allocable and 
attributable operating expense which the lessee can document.
    (ii) Allowable maintenance expenses include: Maintenance of the 
transportation system; maintenance of equipment; maintenance labor; and 
other directly allocable and attributable maintenance expenses which the 
lessee can document.
    (iii) Overhead directly attributable and allocable to the operation 
and maintenance of the transportation system is an allowable expense. 
State and Federal income taxes and severance taxes and other fees, 
including royalties, are not allowable expenses.
    (iv) A lessee may use either depreciation or a return on depreciable 
capital investment. After a lessee has elected to use either method for 
a transportation system, the lessee may not later elect to change to the 
other alternative without approval of MMS.
    (A) To compute depreciation, the lessee may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the transportation system services or on 
a unit-of-production method. After an election is made, the lessee may 
not change methods without MMS approval. A change in ownership of a 
transportation system shall not alter the depreciation schedule 
established by the original transporter/lessee for purposes of the 
allowance calculation. With or without a change in ownership, a 
transportation system shall be depreciated only once. Equipment shall 
not be depreciated below a reasonable salvage value.
    (B) MMS shall allow as a cost an amount equal to the initial capital 
investment in the transportation system multiplied by the rate of return 
determined under paragraph (b)(2)(v) of this section. No allowance shall 
be provided for depreciation. This alternative shall apply only to 
transportation facilities first placed in service after March 1, 1988.
    (v) The rate of return shall be the industrial rate associated with 
Standard and Poor's BBB rating. The rate of return shall be the monthly 
average rate as published in Standard and Poor's Bond Guide for the 
first month of the reporting period for which the allowance is 
applicable and shall be effective during the reporting period. The rate 
shall be redetermined at the beginning of each subsequent transportation 
allowance reporting period (which is determined under paragraph (c) of 
this section).
    (3)(i) The deduction for transportation costs shall be determined on 
the basis of the lessee's cost of transporting each product through each 
individual transportation system. Where more than one liquid product is 
transported, allocation of costs to each of the liquid products 
transported shall be in the same proportion as the ratio of

[[Page 72]]

the volume of each liquid product (excluding waste products which have 
no value) to the volume of all liquid products (excluding waste products 
which have no value) and such allocation shall be made in a consistent 
and equitable manner. Except as provided in this paragraph, the lessee 
may not take an allowance for transporting lease production which is not 
royalty-bearing without MMS approval.
    (ii) Notwithstanding the requirements of paragraph (i), the lessee 
may propose to MMS a cost allocation method on the basis of the values 
of the products transported. MMS shall approve the method unless it 
determines that it is not consistent with the purposes of the 
regulations in this part.
    (4) Where both gaseous and liquid products are transported through 
the same transportation system, the lessee shall propose a cost 
allocation procedure to MMS. The lessee may use the oil transportation 
allowance determined in accordance with its proposed allocation 
procedure until MMS issues its determination on the acceptability of the 
cost allocation. The lessee shall submit all available data to support 
its proposal. The initial proposal must be submitted by June 30, 1988 or 
within 3 months after the last day of the month for which the lessee 
requests a transportation allowance, whichever is later (unless MMS 
approves a longer period). MMS shall then determine the oil 
transportation allowance on the basis of the lessee's proposal and any 
additional information MMS deems necessary.
    (5) A lessee may apply to MMS for an exception from the requirement 
that it compute actual costs in accordance with paragraphs (b)(1) 
through (b)(4) of this section. MMS will grant the exception only if the 
lessee has a tariff for the transportation system approved by the 
Federal Energy Regulatory Commission (FERC) for Indian leases. MMS shall 
deny the exception request if it determines that the tariff is excessive 
as compared to arm's-length transportation charges by pipelines, owned 
by the lessee or others, providing similar transportation services in 
that area. If there are no arm's-length transportation charges, MMS 
shall deny the exception request if:
    (i) No FERC cost analysis exists and the FERC has declined to 
investigate under MMS timely objections upon filing; and
    (ii) the tariff significantly exceeds the lessee's actual costs for 
transportation as determined under this section.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) With the 
exception of those transportation allowances specified in paragraphs 
(c)(1)(v) and (c)(1)(vi) of this section, the lessee shall submit page 
one of the initial Form MMS-4110 (and Schedule 1), Oil Transportation 
Allowance Report, prior to, or at the same time as, the transportation 
allowance determined, under an arm's-length contract, is reported on 
Form MMS-2014, Report of Sales and Royalty Remittance. A Form MMS-4110 
received by the end of the month that the Form MMS-2014 is due shall be 
considered to be timely received.
    (ii) The initial Form MMS-4110 shall be effective for a reporting 
period beginning the month that the lessee is first authorized to deduct 
a transportation allowance and shall continue until the end of the 
calendar year, or until the applicable contract or rate terminates or is 
modified or amended, whichever is earlier.
    (iii) After the initial reporting period and for succeeding 
reporting periods, lessees must submit page one of Form MMS-4110 (and 
Schedule 1) within 3 months after the end of the calendar year, or after 
the applicable contract or rate terminates or is modified or amended, 
whichever is earlier, unless MMS approves a longer period (during which 
period the lessee shall continue to use the allowance from the previous 
reporting period).
    (iv) MMS may require that a lessee submit arm's-length 
transportation contracts, production agreements, operating agreements, 
and related documents. Documents shall be submitted within a reasonable 
time, as determined by MMS.
    (v) Transportation allowances which are based on arm's-length 
contracts and which are in effect at the time these regulations become 
effective will

[[Page 73]]

be allowed to continue until such allowances terminate. For the purposes 
of this section, only those allowances that have been approved by MMS in 
writing shall qualify as being in effect at the time these regulations 
become effective.
    (vi) MMS may establish, in appropriate circumstances, reporting 
requirements which are different from the requirements of this section.
    (2) Non-arm's-length or no contract. (i) With the exception of those 
transportation allowances specified in paragraphs (c)(2)(v), (c)(2)(vii) 
and (c)(2)(viii) of this section, the lessee shall submit an initial 
Form MMS-4110 prior to, or at the same time as, the transportation 
allowance determined under a non-arm's-length contract or no-contract 
situation is reported on Form MMS-2014. A Form MMS-4110 received by the 
end of the month that the Form MMS-2014 is due shall be considered to be 
timely received. The initial report may be based upon estimated costs.
    (ii) The initial Form MMS-4110 shall be effective for a reporting 
period beginning the month that the lessee first is authorized to deduct 
a transportation allowance and shall continue until the end of the 
calendar year, or until transportation under the non-arm's-length 
contract or the no-contract situation terminates, whichever is earlier.
    (iii) For calendar-year reporting periods succeeding the initial 
reporting period, the lessee shall submit a completed Form MMS-4110 
containing the actual costs for the previous reporting period. If oil 
transportation is continuing, the lessee shall include on Form MMS-4110 
its estimated costs for the next calendar year. The estimated oil 
transportation allowance shall be based on the actual costs for the 
previous reporting period plus or minus any adjustments which are based 
on the lessee's knowledge of decreases or increases that will affect the 
allowance. MMS must receive the Form MMS-4110 within 3 months after the 
end of the previous reporting period, unless MMS approves a longer 
period (during which period the lessee shall continue to use the 
allowance from the previous reporting period).
    (iv) For new transportation facilities or arrangements, the lessee's 
initial Form MMS-4110 shall include estimates of the allowable oil 
transportation costs for the applicable period. Cost estimates shall be 
based upon the most recently available operations data for the 
transportation system or, if such data are not available, the lessee 
shall use estimates based upon industry data for similar transportation 
systems.
    (v) Non-arm's-length contract or no-contract transportation 
allowances which are in effect at the time these regulations become 
effective will be allowed to continue until such allowances terminate. 
For the purposes of this section, only those allowances that have been 
approved by MMS in writing shall qualify as being in effect at the time 
these regulations become effective.
    (vi) Upon request by MMS, the lessee shall submit all data used to 
prepare its Form MMS-4110. The data shall be provided within a 
reasonable period of time, as determined by MMS.
    (vii) MMS may establish, in appropriate circumstances, reporting 
requirements which are different from the requirements of this section.
    (viii) If the lessee is authorized to use its FERC-approved tariff 
as its transportation cost in accordance with paragraph (b)(5) of this 
section, it shall follow the reporting requirements of paragraph (c)(1) 
of this section.
    (3) MMS may establish reporting dates for individual lessees 
different from those specified in this subpart in order to provide more 
effective administration. Lessees will be notified of any change in 
their reporting period.
    (4) Transportation allowances must be reported as a separate entry 
on Form MMS-2014, unless MMS approves a different reporting procedure.
    (d) Interest assessments for incorrect or late reports and for 
failure to report. (1) If a lessee deducts a transportation allowance on 
its Form MMS-2014 without complying with the requirements of this 
section, the lessee shall pay interest only on the amount of such 
deduction until the requirements of this section are complied with. The 
lessee also

[[Page 74]]

shall repay the amount of any allowance which is disallowed by this 
section.
    (2) If a lessee erroneously reports a transportation allowance which 
results in an underpayment of royalties, interest shall be paid on the 
amount of that underpayment.
    (3) Interest required to be paid by this section shall be determined 
in accordance with 30 CFR 218.54.
    (e) Adjustments. (1) If the actual transportation allowance is less 
than the amount the lessee has taken on Form MMS-2014 for each month 
during the allowance form reporting period, the lessee must pay 
additional royalties due plus interest computed under 30 CFR 218.54, 
retroactive to the first day of the first month the lessee is authorized 
to deduct a transportation allowance. If the actual transportation 
allowance is greater than the amount the lessee has taken on Form MMS-
2014 for each month during the allowance form reporting period, the 
lessee will be entitled to a credit without interest.
    (2) For lessees transporting production from Indian leases, the 
lessee must submit a corrected Form MMS-2014 to reflect actual costs, 
together with any payment, in accordance with instructions provided by 
MMS.
    (f) Actual or theoretical losses. Notwithstanding any other 
provisions of this subpart, for other than arm's-length contracts, no 
cost shall be allowed for oil transportation which results from payments 
(either volumetric or for value) for actual or theoretical losses. This 
section does not apply when the transportation allowance is based upon a 
FERC or State regulatory agency approved tariff.
    (g) Other transportation cost determinations. The provisions of this 
section shall apply to determine transportation costs when establishing 
value using a netback valuation procedure or any other procedure that 
requires deduction of transportation costs.

[61 FR 5455, Feb. 12, 1996. Redesignated at 72 FR 71241, Dec. 17, 2007, 
as amended at 73 FR 15890, Mar. 26, 2008]



Sec. 206.58  What must I do if MMS finds that I have not properly determined value?

    (a) If MMS finds that you have not properly determined value, you 
must:
    (1) Pay the difference, if any, between the royalty payments you 
made and those that are due, based upon the value MMS establishes; and
    (2) Pay interest on the difference computed under Sec. 218.54 of 
this chapter.
    (b) If you are entitled to a credit due to overpayment on Indian 
leases, see Sec. 218.53 of this chapter. The credit will be without 
interest.

[72 FR 71244, Dec. 17, 2007]



Sec. 206.59  May I ask MMS for valuation guidance?

    You may ask MMS for guidance in determining value. You may propose a 
value method to MMS. Submit all available data related to your proposal 
and any additional information MMS deems necessary. We will promptly 
review your proposal and provide you with non-binding guidance.

[72 FR 71244, Dec. 17, 2007]



Sec. 206.60  What are the quantity and quality bases for royalty settlement?

    (a) You must compute royalties on the quantity and quality of oil as 
measured at the point of settlement approved by BLM for the lease.
    (b) If you determine the value of oil under Sec. Sec. 206.52, 
206.53, or 206.54 of this subpart based on a quantity or quality 
different from the quantity or quality at the point of royalty 
settlement approved by BLM for the lease, you must adjust the value for 
those quantity or quality differences.
    (c) You may not deduct from the royalty volume or royalty value 
actual or theoretical losses incurred before the royalty settlement 
point unless BLM determines that any actual loss was unavoidable.

[72 FR 71244, Dec. 17, 2007]



Sec. 206.61  What records must I keep and produce?

    (a) On request, you must make available sales, volume, and 
transportation data for production you sold, purchased, or obtained from 
the field or

[[Page 75]]

area. You must make this data available to MMS, Indian representatives, 
or other authorized persons.
    (b) You must retain all data relevant to the determination of 
royalty value. Document retention and recordkeeping requirements are 
found at Sec. Sec. 207.5, 212.50, and 212.51 of this chapter. The MMS, 
Indian representatives, or other authorized persons may review and audit 
such data you possess, and MMS will direct you to use a different value 
if it determines that the reported value is inconsistent with the 
requirements of this subpart or the lease.

[72 FR 71244, Dec. 17, 2007]



Sec. 206.62  Does MMS protect information I provide?

    The MMS will keep confidential, to the extent allowed under 
applicable laws and regulations, any data or other information you 
submit that is privileged, confidential, or otherwise exempt from 
disclosure. All requests for information must be submitted under the 
Freedom of Information Act regulations of the Department of the 
Interior, 43 CFR part 2.

[72 FR 71244, Dec. 17, 2007]



                          Subpart C_Federal Oil

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



Sec. 206.100  What is the purpose of this subpart?

    (a) This subpart applies to all oil produced from Federal oil and 
gas leases onshore and on the Outer Continental Shelf (OCS). It explains 
how you as a lessee must calculate the value of production for royalty 
purposes consistent with the mineral leasing laws, other applicable 
laws, and lease terms.
    (b) If you are a designee and if you dispose of production on behalf 
of a lessee, the terms ``you'' and ``your'' in this subpart refer to you 
and not to the lessee. In this circumstance, you must determine and 
report royalty value for the lessee's oil by applying the rules in this 
subpart to your disposition of the lessee's oil.
    (c) If you are a designee and only report for a lessee, and do not 
dispose of the lessee's production, references to ``you'' and ``your'' 
in this subpart refer to the lessee and not the designee. In this 
circumstance, you as a designee must determine and report royalty value 
for the lessee's oil by applying the rules in this subpart to the 
lessee's disposition of its oil.
    (d) If the regulations in this subpart are inconsistent with:
    (1) A Federal statute;
    (2) A settlement agreement between the United States and a lessee 
resulting from administrative or judicial litigation;
    (3) A written agreement between the lessee and the MMS Director 
establishing a method to determine the value of production from any 
lease that MMS expects at least would approximate the value established 
under this subpart; or
    (4) An express provision of an oil and gas lease subject to this 
subpart, then the statute, settlement agreement, written agreement, or 
lease provision 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

[[Page 76]]

other forms of ownership: the percentage of ownership or common 
ownership, the relative percentage of ownership or common ownership 
compared to the percentage(s) of ownership by other persons, whether a 
person is the greatest single owner, or whether there is an opposing 
voting bloc of greater ownership;
    (iii) Operation of a lease, plant, or other facility;
    (iv) The extent of participation by other owners in operations and 
day-to-day management of a lease, plant, or other facility; and
    (v) Other evidence of power to exercise control over or common 
control with another person.
    (3) Regardless of any percentage of ownership or common ownership, 
relatives, either by blood or marriage, are affiliates.
    ANS means Alaska North Slope (ANS).
    Area means a geographic region at least as large as the limits of an 
oil field, in which oil has similar quality, economic, and legal 
characteristics.
    Arm's-length contract means a contract or agreement between 
independent persons who are not affiliates and who have opposing 
economic interests regarding that contract. To be considered arm's 
length for any production month, a contract must satisfy this definition 
for that month, as well as when the contract was executed.
    Audit means a review, conducted under generally accepted accounting 
and auditing standards, of royalty payment compliance activities of 
lessees, designees or other persons who pay royalties, rents, or bonuses 
on Federal leases.
    BLM means the Bureau of Land Management of the Department of the 
Interior.
    Condensate means liquid hydrocarbons (normally exceeding 40 degrees 
of API gravity) recovered at the surface without processing. Condensate 
is the mixture of liquid hydrocarbons resulting from condensation of 
petroleum hydrocarbons existing initially in a gaseous phase in an 
underground reservoir.
    Contract means any oral or written agreement, including amendments 
or revisions, between two or more persons, that is enforceable by law 
and that with due consideration creates an obligation.
    Designee means the person the lessee designates to report and pay 
the lessee's royalties for a lease.
    Exchange agreement means an agreement where one person agrees to 
deliver oil to another person at a specified location in exchange for 
oil deliveries at another location. Exchange agreements may or may not 
specify prices for the oil involved. They frequently specify dollar 
amounts reflecting location, quality, or other differentials. Exchange 
agreements include buy/sell agreements, which specify prices to be paid 
at each exchange point and may appear to be two separate sales within 
the same agreement. Examples of other types of exchange agreements 
include, but are not limited to, exchanges of produced oil for specific 
types of crude oil (e.g., West Texas Intermediate); exchanges of 
produced oil for other crude oil at other locations (Location Trades); 
exchanges of produced oil for other grades of oil (Grade Trades); and 
multi-party exchanges.
    Field means a geographic region situated over one or more subsurface 
oil and gas reservoirs and encompassing at least the outermost 
boundaries of all oil and gas accumulations known within those 
reservoirs, vertically projected to the land surface. State oil and gas 
regulatory agencies usually name onshore fields and designate their 
official boundaries. MMS names and designates boundaries of OCS fields.
    Gathering means the movement of lease production to a central 
accumulation or treatment point on the lease, unit, or communitized 
area, or to a central accumulation or treatment point off the lease, 
unit, or communitized area that BLM or MMS approves for onshore and 
offshore leases, respectively.
    Gross proceeds means the total monies and other consideration 
accruing for the disposition of oil produced. Gross proceeds also 
include, but are not limited to, the following examples:
    (1) Payments for services such as dehydration, marketing, 
measurement,

[[Page 77]]

or gathering which the lessee must perform at no cost to the Federal 
Government;
    (2) The value of services, such as salt water disposal, that the 
producer normally performs but that the buyer performs on the producer's 
behalf;
    (3) Reimbursements for harboring or terminaling fees;
    (4) Tax reimbursements, even though the Federal royalty interest may 
be exempt from taxation;
    (5) Payments made to reduce or buy down the purchase price of oil to 
be produced in later periods, by allocating such payments over the 
production whose price the payment reduces and including the allocated 
amounts as proceeds for the production as it occurs; and
    (6) Monies and all other consideration to which a seller is 
contractually or legally entitled, but does not seek to collect through 
reasonable efforts.
    Lease means any contract, profit-share arrangement, joint venture, 
or other agreement issued or approved by the United States under a 
mineral leasing law that authorizes exploration for, development or 
extraction of, or removal of oil or gas--or the land area covered by 
that authorization, whichever the context requires.
    Lessee means any person to whom the United States issues an oil and 
gas lease, an assignee of all or a part of the record title interest, or 
any person to whom operating rights in a lease have been assigned.
    Location differential means an amount paid or received (whether in 
money or in barrels of oil) under an exchange agreement that results 
from differences in location between oil delivered in exchange and oil 
received in the exchange. A location differential may represent all or 
part of the difference between the price received for oil delivered and 
the price paid for oil received under a buy/sell exchange agreement.
    Market center means a major point MMS recognizes for oil sales, 
refining, or transshipment. Market centers generally are locations where 
MMS-approved publications publish oil spot prices.
    Marketable condition means oil sufficiently free from impurities and 
otherwise in a condition a purchaser will accept under a sales contract 
typical for the field or area.
    MMS-approved publication means a publication MMS approves for 
determining ANS spot prices or WTI differentials.
    Netting means reducing the reported sales value to account for 
transportation instead of reporting a transportation allowance as a 
separate entry on Form MMS-2014.
    NYMEX price means the average of the New York Mercantile Exchange 
(NYMEX) settlement prices for light sweet crude oil delivered at 
Cushing, Oklahoma, calculated as follows:
    (1) Sum the prices published for each day during the calendar month 
of production (excluding weekends and holidays) for oil to be delivered 
in the prompt month corresponding to each such day; and
    (2) Divide the sum by the number of days on which those prices are 
published (excluding weekends and holidays).
    Oil means a mixture of hydrocarbons that existed in the liquid phase 
in natural underground reservoirs, remains liquid at atmospheric 
pressure after passing through surface separating facilities, and is 
marketed or used as a liquid. Condensate recovered in lease separators 
or field facilities is oil.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside of the area of lands beneath navigable waters as 
defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of 
which the subsoil and seabed appertain to the United States and are 
subject to its jurisdiction and control.
    Person means any individual, firm, corporation, association, 
partnership, consortium, or joint venture (when established as a 
separate entity).
    Prompt month means the nearest month of delivery for which NYMEX 
futures prices are published during the trading month.
    Quality differential means an amount paid or received under an 
exchange agreement (whether in money or in barrels of oil) that results 
from differences in API gravity, sulfur content, viscosity, metals 
content, and other quality factors between oil delivered and oil 
received in the exchange. A

[[Page 78]]

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 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

[[Page 79]]

    (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 
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-

[[Page 80]]

length sales contract does not reflect the total consideration actually 
transferred either directly or indirectly from the buyer to the seller, 
MMS may require that you value the oil sold under that contract either 
under Sec. 206.103 or at the total consideration received.
    (2) You must value the oil under Sec. 206.103 if MMS determines 
that the value under paragraph (a) of this section does not reflect the 
reasonable value of the production due to either:
    (i) Misconduct by or between the parties to the arm's-length 
contract; or
    (ii) Breach of your duty to market the oil for the mutual benefit of 
yourself and the lessor.
    (A) MMS will not use this provision to simply substitute its 
judgment of the market value of the oil for the proceeds received by the 
seller under an arm's-length sales contract.
    (B) The fact that the price received by the seller under an arm's 
length contract is less than other measures of market price, such as 
index prices, is insufficient to establish breach of the duty to market 
unless MMS finds additional evidence that the seller acted unreasonably 
or in bad faith in the sale of oil from the lease.
    (d)(1) If you enter into an arm's-length exchange agreement, or 
multiple sequential arm's-length exchange agreements, and following the 
exchange(s) you or your affiliate sell(s) the oil received in the 
exchange(s) under an arm's-length contract, then you may use either 
Sec. 206.102(a) or Sec. 206.103 to value your production for royalty 
purposes.
    (i) If you use Sec. 206.102(a), your gross proceeds are the gross 
proceeds under your or your affiliate's arm's-length sales contract 
after the exchange(s) occur(s). You must adjust your gross proceeds for 
any location or quality differential, or other adjustments, you received 
or paid under the arm's-length exchange agreement(s). If MMS determines 
that any arm's-length exchange agreement does not reflect reasonable 
location or quality differentials, MMS may require you to value the oil 
under Sec. 206.103. You may not otherwise use the price or differential 
specified in an arm's-length exchange agreement to value your 
production.
    (ii) When you elect under Sec. 206.102(d)(1) to use Sec. 
206.102(a) or Sec. 206.103, you must make the same election for all of 
your production from the same unit, communitization agreement, or lease 
(if the lease is not part of a unit or communitization agreement) sold 
under arm's-length contracts following arm's-length exchange agreements. 
You may not change your election more often than once every 2 years.
    (2)(i) If you sell or transfer your oil production to your affiliate 
and that affiliate or another affiliate then sells the oil under an 
arm's-length contract, you may use either Sec. 206.102(a) or Sec. 
206.103 to value your production for royalty purposes.
    (ii) When you elect under Sec. 206.102(d)(2)(i) to use Sec. 
206.102(a) or Sec. 206.103, you must make the same election for all of 
your production from the same unit, communitization agreement, or lease 
(if the lease is not part of a unit or communitization agreement) that 
your affiliates resell at arm's length. You may not change your election 
more often than once every 2 years.
    (e) If you value oil under paragraph (a) of this section:
    (1) MMS may require you to certify that your or your affiliate's 
arm's-length contract provisions include all of the consideration the 
buyer must pay, either directly or indirectly, for the oil.
    (2) You must base value on the highest price the seller can receive 
through legally enforceable claims under the contract.
    (i) If the seller fails to take proper or timely action to receive 
prices or benefits it is entitled to, you must pay royalty at a value 
based upon that obtainable price or benefit. But you will owe no 
additional royalties unless or until the seller receives monies or 
consideration resulting from the price increase or additional benefits, 
if:
    (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.

[[Page 81]]

    (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
    (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

[[Page 82]]

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 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

[[Page 83]]

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
    (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

[[Page 84]]

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 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

[[Page 85]]

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 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.

[[Page 86]]

    (c) You may not deduct any costs that are not actual costs of 
transporting oil, including but not limited to the following:
    (1) Fees paid for long-term storage (more than 30 days).
    (2) Administrative, handling, and accounting fees associated with 
terminalling.
    (3) Title and terminal transfer fees.
    (4) Fees paid to track and match receipts and deliveries at a market 
center or to avoid paying title transfer fees.
    (5) Fees paid to brokers.
    (6) Fees paid to a scheduling service provider.
    (7) Internal costs, including salaries and related costs, rent/space 
costs, office equipment costs, legal fees, and other costs to schedule, 
nominate, and account for sale or movement of production.
    (8) Gauging fees.
    (d) If your arm's-length transportation contract includes more than 
one liquid product, and the transportation costs attributable to each 
product cannot be determined from the contract, then you must allocate 
the total transportation costs to each of the liquid products 
transported.
    (1) Your allocation must use the same proportion as the ratio of the 
volume of each product (excluding waste products with no value) to the 
volume of all liquid products (excluding waste products with no value).
    (2) You may not claim an allowance for the costs of transporting 
lease production that is not royalty-bearing.
    (3) You may propose to MMS a cost allocation method on the basis of 
the values of the products transported. MMS will approve the method 
unless it is not consistent with the purposes of the regulations in this 
subpart.
    (e) If your arm's-length transportation contract includes both 
gaseous and liquid products, and the transportation costs attributable 
to each product cannot be determined from the contract, then you must 
propose an allocation procedure to MMS.
    (1) You may use your proposed procedure to calculate a 
transportation allowance until MMS accepts or rejects your cost 
allocation. If MMS rejects your cost allocation, you must amend your 
Form MMS-2014 for the months that you used the rejected method and pay 
any additional royalty and interest due.
    (2) You must submit your initial proposal, including all available 
data, within 3 months after first claiming the allocated deductions on 
Form MMS-2014.
    (f) If your payments for transportation under an arm's-length 
contract are not on a dollar-per-unit basis, you must convert whatever 
consideration is paid to a dollar-value equivalent.
    (g) If your arm's-length sales contract includes a provision 
reducing the contract price by a transportation factor, do not 
separately report the transportation factor as a transportation 
allowance on Form MMS-2014.
    (1) You may use the transportation factor in determining your gross 
proceeds for the sale of the product.
    (2) You must obtain MMS approval before claiming a transportation 
factor in excess of 50 percent of the base price of the product.

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



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

[[Page 87]]

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;
    (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

[[Page 88]]

approval. You may not depreciate equipment below a reasonable salvage 
value.
    (h) This paragraph describes the basis for your depreciation 
schedule.
    (1) If you or your affiliate own a transportation system on June 1, 
2000, you must base your depreciation schedule used in calculating 
actual transportation costs for production after June 1, 2000, on your 
total capital investment in the system (including your original purchase 
price or construction cost and subsequent reinvestment).
    (2) If you or your affiliate purchased the transportation system at 
arm's length before June 1, 2000, you must incorporate depreciation on 
the schedule based on your purchase price (and subsequent reinvestment) 
into your transportation allowance calculations for production after 
June 1, 2000, beginning at the point on the depreciation schedule 
corresponding to that date. You must prorate your depreciation for 
calendar year 2000 by claiming part-year depreciation for the period 
from June 1, 2000 until December 31, 2000. You may not adjust your 
transportation costs for production before June 1, 2000, using the 
depreciation schedule based on your purchase price.
    (3) If you are the original owner of the transportation system on 
June 1, 2000, or if you purchased your transportation system before 
March 1, 1988, you must continue to use your existing depreciation 
schedule in calculating actual transportation costs for production in 
periods after June 1, 2000.
    (4) If you or your affiliate purchase a transportation system at 
arm's length from the original owner after June 1, 2000, you must base 
your depreciation schedule used in calculating actual transportation 
costs on your total capital investment in the system (including your 
original purchase price and subsequent reinvestment). You must prorate 
your depreciation for the year in which you or your affiliate purchased 
the system to reflect the portion of that year for which you or your 
affiliate own the system.
    (5) If you or your affiliate purchase a transportation system at 
arm's length after June 1, 2000, from anyone other than the original 
owner, you must assume the depreciation schedule of the person from whom 
you bought the system. Include in the depreciation schedule any 
subsequent reinvestment.
    (i)(1) To calculate a return on undepreciated capital investment, 
multiply the remaining undepreciated capital balance as of the beginning 
of the period for which you are calculating the transportation allowance 
by the rate of return provided in paragraph (i)(2) of this section.
    (2) The rate of return is 1.3 times the industrial bond yield index 
for Standard & Poor's BBB bond rating. Use the monthly average rate 
published in ``Standard & Poor's Bond Guide'' for the first month of the 
reporting period for which the allowance applies. Calculate the rate at 
the beginning of each subsequent transportation allowance reporting 
period.
    (j)(1) After a transportation system has been depreciated at or 
below a value equal to ten percent of your total capital investment, you 
may continue to include in the allowance calculation a cost equal to ten 
percent of your total capital investment in the transportation system 
multiplied by a rate of return under paragraph (i)(2) of this section.
    (2) You may apply this paragraph to a transportation system that 
before June 1, 2000, was depreciated at or below a value equal to ten 
percent of your total capital investment.
    (k) Calculate the deduction for transportation costs based on your 
or your affiliate's cost of transporting each product through each 
individual transportation system. Where more than one liquid product is 
transported, allocate costs consistently and equitably to each of the 
liquid products transported. Your allocation must use the same 
proportion as the ratio of the volume of each liquid product (excluding 
waste products with no value) to the volume of all liquid products 
(excluding waste products with no value).
    (1) You may not take an allowance for transporting lease production 
that is not royalty-bearing.
    (2) You may propose to MMS a cost allocation method on the basis of 
the values of the products transported. MMS will approve the method if 
it is consistent with the purposes of the regulations in this subpart.

[[Page 89]]

    (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 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

[[Page 90]]

do not transport or exchange (or both transport and exchange) from your 
lease to a market center.
    (4) If you transport or exchange (or both transport and exchange) 
less than 20 percent of the crude oil produced from your lease between 
the lease and a market center, you must propose to MMS an adjustment 
between the lease and the market center for the portion of the oil that 
you do not transport or exchange (or both transport and exchange) to a 
market center. Until you obtain such approval, you may use your proposed 
adjustment. If MMS prescribes a different adjustment, you must apply 
MMS's adjustment to all periods for which you used your proposed 
adjustment. You must pay any additional royalties owed resulting from 
using MMS's adjustment plus late payment interest from the original 
royalty due date, or you may report a credit for any overpaid royalties 
plus interest under 30 U.S.C. 1721(h).
    (5) You may not both take a transportation allowance and use a 
location and quality adjustment or exchange differential for the same 
oil between the same points.
    (b) For oil that you value using NYMEX prices, adjust the value 
between the market center and Cushing, Oklahoma, as follows:
    (1) If you have arm's-length exchange agreements between the market 
center and Cushing under which you exchange to Cushing at least 20 
percent of all the oil you own at the market center during the 
production month, you must use the volume-weighted average of the 
location and quality differentials from those agreements as the 
adjustment between the market center and Cushing for all the oil that 
you produce from the leases during that production month for which that 
market center is used.
    (2) If paragraph (b)(1) of this section does not apply, you must use 
the WTI differential published in an MMS-approved publication for the 
market center nearest your lease, for crude oil most similar in quality 
to your production, as the adjustment between the market center and 
Cushing. (For example, for light sweet crude oil produced offshore of 
Louisiana, use the WTI differential for Light Louisiana Sweet crude oil 
at St. James, Louisiana.) After you select an MMS-approved publication, 
you may not select a different publication more often than once every 2 
years, unless the publication you use is no longer published or MMS 
revokes its approval of the publication. If you are required to change 
publications, you must begin a new 2-year period.
    (3) If neither paragraph (b)(1) nor (b)(2) of this section applies, 
you may propose an alternative differential to MMS. Until you obtain 
such approval, you may use your proposed differential. If MMS prescribes 
a different differential, you must apply MMS's differential to all 
periods for which you used your proposed differential. You must pay any 
additional royalties owed resulting from using MMS's differential plus 
late payment interest from the original royalty due date, or you may 
report a credit for any overpaid royalties plus interest under 30 U.S.C. 
1721(h).
    (c)(1) If you adjust for location and quality differentials or for 
transportation costs under paragraphs (a) and (b) of this section, also 
adjust the NYMEX price or ANS spot price for quality based on premiums 
or penalties determined by pipeline quality bank specifications at 
intermediate commingling points or at the market center if those points 
are downstream of the royalty measurement point approved by MMS or BLM, 
as applicable. Make this adjustment only if and to the extent that such 
adjustments were not already included in the location and quality 
differentials determined from your arm's-length exchange agreements.
    (2) If the quality of your oil as adjusted is still different from 
the quality of the representative crude oil at the market center after 
making the quality adjustments described in paragraphs (a), (b) and 
(c)(1) of this section, you may make further gravity adjustments using 
posted price gravity tables. If quality bank adjustments do not 
incorporate or provide for adjustments for sulfur content, you may make 
sulfur adjustments, based on the quality of the representative crude oil 
at the market center, of 5.0 cents per one-tenth percent difference in 
sulfur

[[Page 91]]

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:
    (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

[[Page 92]]

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 applies if I improperly report a transportation allowance?

    (a) If you or your affiliate deducts a transportation allowance on 
Form MMS-2014 that exceeds 50 percent of the value of the oil 
transported without obtaining MMS's prior approval under 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 files an 
exception request that MMS approves. If you do not file an exception 
request, or if MMS does not approve your request, you must pay interest 
on the excess allowance amount taken from the date that amount is taken 
until the date you pay the additional royalties owed.
    (b) If you or your affiliate takes a deduction for transportation on 
Form MMS-2014 by improperly netting an allowance against the oil instead 
of reporting the allowance as a separate entry, MMS may assess a civil 
penalty under 30 CFR part 241.

[73 FR 15890, Mar. 26, 2008]



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 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.

[[Page 93]]

    (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.
    (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.

[[Page 94]]

    BLM means the Bureau of Land Management of the Department of the 
Interior.
    Compression means the process of raising the pressure of gas.
    Condensate means liquid hydrocarbons (normally exceeding 40 degrees 
of API gravity) recovered at the surface without resorting to 
processing. Condensate is the mixture of liquid hydrocarbons that 
results from condensation of petroleum hydrocarbons existing initially 
in a gaseous phase in an underground reservoir.
    Contract means any oral or written agreement, including amendments 
or revisions thereto, between two or more persons and enforceable by law 
that with due consideration creates an obligation.
    Field means a geographic region situated over one or more subsurface 
oil and gas reservoirs encompassing at least the outermost boundaries of 
all oil and gas accumulations known to be within those reservoirs 
vertically projected to the land surface. Onshore fields are usually 
given names and their official boundaries are often designated by oil 
and gas regulatory agencies in the respective States in which the fields 
are located. Outer Continental Shelf (OCS) fields are named and their 
boundaries are designated by MMS.
    Gas means any fluid, either combustible or noncombustible, 
hydrocarbon or nonhydrocarbon, which is extracted from a reservoir and 
which has neither independent shape nor volume, but tends to expand 
indefinitely. It is a substance that exists in a gaseous or rarefied 
state under standard temperature and pressure conditions.
    Gas plant products means separate marketable elements, compounds, or 
mixtures, whether in liquid, gaseous, or solid form, resulting from 
processing gas, excluding residue gas.
    Gathering means the movement of lease production to a central 
accumulation and/or treatment point on the lease, unit or communitized 
area, or to a central accumulation or treatment point off the lease, 
unit or communitized area as approved by BLM or MMS OCS operations 
personnel for onshore and OCS leases, respectively.
    Gross proceeds (for royalty payment purposes) means the total monies 
and other consideration accruing to an oil and gas lessee for the 
disposition of the gas, residue gas, and gas plant products produced. 
Gross proceeds includes, but is not limited to, payments to the lessee 
for certain services such as dehydration, measurement, and/or gathering 
to the extent that the lessee is obligated to perform them at no cost to 
the Federal Government. Tax reimbursements are part of the gross 
proceeds accruing to a lessee even though the Federal royalty interest 
may be exempt from taxation. Monies and other consideration, including 
the forms of consideration identified in this paragraph, to which a 
lessee is contractually or legally entitled but which it does not seek 
to collect through reasonable efforts are also part of gross proceeds.
    Lease means any contract, profit-share arrangement, joint venture, 
or other agreement issued or approved by the United States under a 
mineral leasing law that authorizes exploration for, development or 
extraction of, or removal of lease products--or the land area covered by 
that authorization, whichever is required by the context.
    Lease products means any leased minerals attributable to, 
originating from, or allocated to Outer Continental Shelf or onshore 
Federal leases.
    Lessee means any person to whom the United States issues a lease, 
and any person who has been assigned an obligation to make royalty or 
other payments required by the lease. This includes any person who has 
an interest in a lease as well as an operator or payor who has no 
interest in the lease but who has assumed the royalty payment 
responsibility.
    Like-quality lease products means lease products which have similar 
chemical, physical, and legal characteristics.
    Marketable condition means lease products which are sufficiently 
free from impurities and otherwise in a condition that they will be 
accepted by a purchaser under a sales contract typical for the field or 
area.

[[Page 95]]

    Marketing affiliate means an affiliate of the lessee whose function 
is to acquire only the lessee's production and to market that 
production.
    Minimum royalty means that minimum amount of annual royalty that the 
lessee must pay as specified in the lease or in applicable leasing 
regulations.
    Net-back method (or work-back method) means a method for calculating 
market value of gas at the lease. Under this method, costs of 
transportation, processing, or manufacturing are deducted from the 
proceeds received for the gas, residue gas or gas plant products, and 
any extracted, processed, or manufactured products, or from the value of 
the gas, residue gas or gas plant products, and any extracted, 
processed, or manufactured products, at the first point at which 
reasonable values for any such products may be determined by a sale 
pursuant to an arm's-length contract or comparison to other sales of 
such products, to ascertain value at the lease.
    Net output means the quantity of residue gas and each gas plant 
product that a processing plant produces.
    Net profit share (for applicable Federal leases) means the specified 
share of the net profit from production of oil and gas as provided in 
the agreement.
    Netting means the deduction of an allowance from the sales value by 
reporting a net sales value, instead of correctly reporting the 
deduction as a separate entry on Form MMS-2014.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside of the area of land beneath navigable waters as 
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of 
which the subsoil and seabed appertain to the United States and are 
subject to its jurisdiction and control.
    Person means any individual, firm, corporation, association, 
partnership, consortium, or joint venture (when established as a 
separate entity).
    Posted price means the price, net of all adjustments for quality and 
location, specified in publicly available price bulletins or other price 
notices available as part of normal business operations for quantities 
of unprocessed gas, residue gas, or gas plant products in marketable 
condition.
    Processing means any process designed to remove elements or 
compounds (hydrocarbon and nonhydrocarbon) from gas, including 
absorption, adsorption, or refrigeration. Field processes which normally 
take place on or near the lease, such as natural pressure reduction, 
mechanical separation, heating, cooling, dehydration, and compression, 
are not considered processing. The changing of pressures and/or 
temperatures in a reservoir is not considered processing.
    Residue gas means that hydrocarbon gas consisting principally of 
methane resulting from processing gas.
    Sales type code means the contract type or general disposition 
(e.g., arm's-length or non-arm's-length) of production from the lease. 
The sales type code applies to the sales contract, or other disposition, 
and not to the arm's-length or non-arm's-length nature of a 
transportation or processing allowance.
    Section 6 lease means an OCS lease subject to section 6 of the Outer 
Continental Shelf Lands Act, as amended, 43 U.S.C. 1335.
    Spot sales agreement means a contract wherein a seller agrees to 
sell to a buyer a specified amount of unprocessed gas, residue gas, or 
gas plant products at a specified price over a fixed period, usually of 
short duration, which does not normally require a cancellation notice to 
terminate, and which does not contain an obligation, nor imply an 
intent, to continue in subsequent periods.
    Warranty contract means a long-term contract entered into prior to 
1970, including any amendments thereto, for the sale of gas wherein the 
producer agrees to sell a specific amount of gas and the gas delivered 
in satisfaction of this obligation may come from fields or sources 
outside of the designated fields.

[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45084, Nov. 8, 1988; 61 
FR 5464, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999; 70 FR 11878, Mar. 
10, 2005; 73 FR 15890, Mar. 26, 2008]

[[Page 96]]



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 (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

[[Page 97]]

gas sold pursuant to a warranty contract; provided, however, that any 
value determination for a warranty contract in effect on the effective 
date of these regulations shall remain in effect until modified by MMS.
    (3) MMS may require a lessee to certify that its arm's-length 
contract provisions include all of the consideration to be paid by the 
buyer, either directly or indirectly, for the gas.
    (c) The value of gas subject to this section which is not sold 
pursuant to an arm's-length contract shall be the reasonable value 
determined in accordance with the first applicable of the following 
methods:
    (1) The gross proceeds accruing to the lessee pursuant to a sale 
under its non-arm's-length contract (or other disposition other than by 
an arm's-length contract), provided that those gross proceeds are 
equivalent to the gross proceeds derived from, or paid under, comparable 
arm's-length contracts for purchases, sales, or other dispositions of 
like-quality gas in the same field (or, if necessary to obtain a 
reasonable sample, from the same area). In evaluating the comparability 
of arm's-length contracts for the purposes of these regulations, the 
following factors shall be considered: price, time of execution, 
duration, market or markets served, terms, quality of gas, volume, and 
such other factors as may be appropriate to reflect the value of the 
gas;
    (2) A value determined by consideration of other information 
relevant in valuing like-quality gas, including gross proceeds under 
arm's-length contracts for like-quality gas in the same field or nearby 
fields or areas, posted prices for gas, prices received in arm's-length 
spot sales of gas, other reliable public sources of price or market 
information, and other information as to the particular lease operation 
or the saleability of the gas; or
    (3) A net-back method or any other reasonable method to determine 
value.
    (d)(1) Notwithstanding any other provisions of this section, except 
paragraph (h) of this section, if the maximum price permitted by Federal 
law at which gas may be sold is less than the value determined pursuant 
to this section, then MMS shall accept such maximum price as the value. 
For purposes of this section, price limitations set by any State or 
local government shall not be considered as a maximum price permitted by 
Federal law.
    (2) The limitation prescribed in paragraph (d)(1) of this section 
shall not apply to gas sold pursuant to a warranty contract and valued 
pursuant to paragraph (b)(2) of this section.
    (e)(1) Where the value is determined pursuant to paragraph (c) of 
this section, the lessee shall retain all data relevant to the 
determination of royalty value. Such data shall be subject to review and 
audit, and MMS will direct a lessee to use a different value if it 
determines that the reported value is inconsistent with the requirements 
of these regulations.
    (2) Any Federal lessee will make available upon request to the 
authorized MMS or State representatives, to the Office of the Inspector 
General of the Department of the Interior, or other person authorized to 
receive such information, arm's-length sales and volume data for like-
quality production sold, purchased or otherwise obtained by the lessee 
from the field or area or from nearby fields or areas.
    (3) A lessee shall notify MMS if it has determined value pursuant to 
paragraph (c)(2) or (c)(3) of this section. The notification shall be by 
letter to the MMS Associate Director for Minerals Revenue Management or 
his/her designee. The letter shall identify the valuation method to be 
used and contain a brief description of the procedure to be followed. 
The notification required by this paragraph is a one-time notification 
due no later than the end of the month following the month the lessee 
first reports royalties on a Form MMS-2014 using a valuation method 
authorized by paragraph (c)(2) or (c)(3) of this section, and each time 
there is a change in a method under paragraph (c)(2) or (c)(3) of this 
section.
    (f) If MMS determines that a lessee has not properly determined 
value, the lessee shall pay the difference, if any, between royalty 
payments made based upon the value it has used and the royalty payments 
that are due based upon the value established by MMS. The lessee shall 
also pay interest on that difference computed pursuant to 30 CFR

[[Page 98]]

218.54. If the lessee is entitled to a credit, MMS will provide 
instructions for the taking of that credit.
    (g) The lessee may request a value determination from MMS. In that 
event, the lessee shall propose to MMS a value determination method, and 
may use that method in determining value for royalty purposes until MMS 
issues its decision. The lessee shall submit all available data relevant 
to its proposal. The MMS shall expeditiously determine the value based 
upon the lessee's proposal and any additional information MMS deems 
necessary. In making a value determination MMS may use any of the 
valuation criteria authorized by this subpart. That determination shall 
remain effective for the period stated therein. After MMS issues its 
determination, the lessee shall make the adjustments in accordance with 
paragraph (f) of this section.
    (h) Notwithstanding any other provision of this section, under no 
circumstances shall the value of production for royalty purposes be less 
than the gross proceeds accruing to the lessee for lease production, 
less applicable allowances.
    (i) The lessee must place gas in marketable condition and market the 
gas for the mutual benefit of the lessee and the lessor at no cost to 
the Federal Government. Where the value established under this section 
is determined by a lessee's gross proceeds, that value will be increased 
to the extent that the gross proceeds have been reduced because the 
purchaser, or any other person, is providing certain services the cost 
of which ordinarily is the responsibility of the lessee to place the gas 
in marketable condition or to market the gas.
    (j) Value shall be based on the highest price a prudent lessee can 
receive through legally enforceable claims under its contract. If there 
is no contract revision or amendment, and the lessee fails to take 
proper or timely action to receive prices or benefits to which it is 
entitled, it must pay royalty at a value based upon that obtainable 
price or benefit. Contract revisions or amendments shall be in writing 
and signed by all parties to an arm's-length contract. If the lessee 
makes timely application for a price increase or benefit allowed under 
its contract but the purchaser refuses, and the lessee takes reasonable 
measures, which are documented, to force purchaser compliance, the 
lessee will owe no additional royalties unless or until monies or 
consideration resulting from the price increase or additional benefits 
are received. This paragraph shall not be construed to permit a lessee 
to avoid its royalty payment obligation in situations where a purchaser 
fails to pay, in whole or in part or timely, for a quantity of gas.
    (k) Notwithstanding any provision in these regulations to the 
contrary, no review, reconciliation, monitoring, or other like process 
that results in a redetermination by MMS of value under this section 
shall be considered final or binding as against the Federal Government 
or its beneficiaries until the audit period is formally closed.
    (l) Certain information submitted to MMS to support valuation 
proposals, including transportation or extraordinary cost allowances, is 
exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 
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

[[Page 99]]

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 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

[[Page 100]]

proceeds are equivalent to the gross proceeds derived from, or paid 
under, comparable arm's-length contracts for purchases, sales, or other 
dispositions of like quality residue gas or gas plant products from the 
same processing plant (or, if necessary to obtain a reasonable sample, 
from nearby plants). In evaluating the comparability of arm's-length 
contracts for the purposes of these regulations, the following factors 
shall be considered: price, time of execution, duration, market or 
markets served, terms, quality of residue gas or gas plant products, 
volume, and such other factors as may be appropriate to reflect the 
value of the residue gas or gas plant products;
    (2) A value determined by consideration of other information 
relevant in valuing like-quality residue gas or gas plant products, 
including gross proceeds under arm's-length contracts for like-quality 
residue gas or gas plant products from the same gas plant or other 
nearby processing plants, posted prices for residue gas or gas plant 
products, prices received in spot sales of residue gas or gas plant 
products, other reliable public sources of price or market information, 
and other information as to the particular lease operation or the 
saleability of such residue gas or gas plant products; or
    (3) A net-back method or any other reasonable method to determine 
value.
    (d)(1) Notwithstanding any other provisions of this section, except 
paragraph (h) of this section, if the maximum price permitted by Federal 
law at which any residue gas or gas plant products may be sold is less 
than the value determined pursuant to this section, then MMS shall 
accept such maximum price as the value. For the purposes of this 
section, price limitations set by any State or local government shall 
not be considered as a maximum price permitted by Federal law.
    (2) The limitation prescribed by paragraph (d)(1) of this section 
shall not apply to residue gas sold pursuant to a warranty contract and 
valued pursuant to paragraph (b)(2) of this section.
    (e)(1) Where the value is determined pursuant to paragraph (c) of 
this section, the lessee shall retain all data relevant to the 
determination of royalty value. Such data shall be subject to review and 
audit, and MMS will direct a lessee to use a different value if it 
determines upon review or audit that the reported value is inconsistent 
with the requirements of these regulations.
    (2) Any Federal lessee will make available upon request to the 
authorized MMS or State representatives, to the Office of the Inspector 
General of the Department of the Interior, or other persons authorized 
to receive such information, arm's-length sales and volume data for 
like-quality residue gas and gas plant products sold, purchased or 
otherwise obtained by the lessee from the same processing plant or from 
nearby processing plants.
    (3) A lessee shall notify MMS if it has determined any value 
pursuant to paragraph (c)(2) or (c)(3) of this section. The notification 
shall be by letter to the MMS Associate Director for Minerals Revenue 
Management or his/her designee. The letter shall identify the valuation 
method to be used and contain a brief description of the procedure to be 
followed. The notification required by this paragraph is a one-time 
notification due no later than the end of the month following the month 
the lessee first reports royalties on a Form MMS-2014 using a valuation 
method authorized by paragraph (c)(2) or (c)(3) of this section, and 
each time there is a change in a method under paragraph (c)(2) or (c)(3) 
of this section.
    (f) If MMS determines that a lessee has not properly determined 
value, the lessee shall pay the difference, if any, between royalty 
payments made based upon the value it has used and the royalty payments 
that are due based upon the value established by MMS. The lessee shall 
also pay interest computed on that difference pursuant to 30 CFR 218.54. 
If the lessee is entitled to a credit, MMS will provide instructions for 
the taking of that credit.
    (g) The lessee may request a value determination from MMS. In that 
event, the lessee shall propose to MMS a value determination method, and 
may use that method in determining value for royalty purposes until MMS 
issues its decision. The lessee shall submit all available data relevant 
to its proposal. The MMS shall expeditiously

[[Page 101]]

determine the value based upon the lessee's proposal and any additional 
information MMS deems necessary. In making a value determination, MMS 
may use any of the valuation criteria authorized by this subpart. That 
determination shall remain effective for the period stated therein. 
After MMS issues its determination, the lessee shall make the 
adjustments in accordance with paragraph (f) of this section.
    (h) Notwithstanding any other provision of this section, under no 
circumstances shall the value of production for royalty purposes be less 
than the gross proceeds accruing to the lessee for residue gas and/or 
any gas plant products, less applicable transportation allowances and 
processing allowances determined pursuant to this subpart.
    (i) The lessee must place residue gas and gas plant products in 
marketable condition and market the residue gas and gas plant products 
for the mutual benefit of the lessee and the lessor at no cost to the 
Federal Government. Where the value established under this section is 
determined by a lessee's gross proceeds, that value will be increased to 
the extent that the gross proceeds have been reduced because the 
purchaser, or any other person, is providing certain services the cost 
of which ordinarily is the responsibility of the lessee to place the 
residue gas or gas plant products in marketable condition or to market 
the residue gas and gas plant products.
    (j) Value shall be based on the highest price a prudent lessee can 
receive through legally enforceable claims under its contract. Absent 
contract revision or amendment, if the lessee fails to take proper or 
timely action to receive prices or benefits to which it is entitled it 
must pay royalty at a value based upon that obtainable price or benefit. 
Contract revisions or amendments shall be in writing and signed by all 
parties to an arm's-length contract. If the lessee makes timely 
application for a price increase or benefit allowed under its contract 
but the purchaser refuses, and the lessee takes reasonable measures, 
which are documented, to force purchaser compliance, the lessee will owe 
no additional royalties unless or until monies or consideration 
resulting from the price increase or additional benefits are received. 
This paragraph shall not be construed to permit a lessee to avoid its 
royalty payment obligation in situations where a purchaser fails to pay, 
in whole or in part, or timely, for a quantity of residue gas or gas 
plant product.
    (k) Notwithstanding any provision in these regulations to the 
contrary, no review, reconciliation, monitoring, or other like process 
that results in a redetermination by MMS of value under this section 
shall be considered final or binding against the Federal Government or 
its beneficiaries until the audit period is formally closed.
    (l) Certain information submitted to MMS to support valuation 
proposals, including transportation allowances, processing allowances or 
extraordinary cost allowances, is exempted from disclosure by the 
Freedom of Information Act, 5 U.S.C. 552, or other Federal law. Any data 
specified by law to be privileged, confidential, or otherwise exempt, 
will be maintained in a confidential manner in accordance with 
applicable law and regulations. All requests for information about 
determinations made under this part are to be submitted in accordance 
with the Freedom of Information Act regulation of the Department of the 
Interior, 43 CFR part 2.

[53 FR 1272, Jan. 15, 1988, as amended at 56 FR 46530, Sept. 13, 1991; 
61 FR 5465, Feb. 12, 1996; 62 FR 65762, Dec. 16, 1997]



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

[[Page 102]]

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 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,

[[Page 103]]

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 sales type code 
may not exceed 50 percent of the value of the unprocessed gas determined 
under 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 sales type code may 
not exceed 50 percent of the value of the residue gas or gas plant 
product determined under Sec. 206.153 of this subpart. For purposes of 
this section, natural gas liquids will be considered one product.
    (3) Upon request of a lessee, MMS may approve a transportation 
allowance deduction in excess of the limitations prescribed by 
paragraphs (c)(1) and (c)(2) of this section. The lessee must 
demonstrate that the transportation costs incurred in excess of the 
limitations prescribed in paragraphs (c)(1) and (c)(2) of this section 
were reasonable, actual, and necessary. An application for exception 
(using Form MMS-4393, Request to Exceed Regulatory Allowance Limitation) 
must contain all relevant and supporting documentation necessary for MMS 
to make a determination. Under no circumstances may the value for 
royalty purposes under any sales type code be reduced to zero.
    (d) If, after a review or audit, MMS determines that a lessee has 
improperly determined a transportation allowance authorized by this 
subpart, then the lessee must pay any additional royalties, plus 
interest, determined in accordance with 30 CFR 218.54, or will be 
entitled to a credit, with interest. If the lessee takes a deduction for 
transportation on Form MMS-2014 by improperly netting the allowance 
against the sales value of the unprocessed gas, residue gas, and gas 
plant products instead of reporting the allowance as a separate entry, 
MMS may assess a civil penalty under 30 CFR part 241.

[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5465, Feb. 12, 1996; 64 
FR 43288, Aug. 10, 1999; 73 FR 15890, Mar. 26, 2008]



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

[[Page 104]]

that its contract is arm's-length. MMS' prior approval is not required 
before a lessee may deduct costs incurred under an arm's-length 
contract. Such allowances shall be subject to the provisions of 
paragraph (f) of this section. The lessee must claim a transportation 
allowance by reporting it as a separate entry on the Form MMS-2014.
    (ii) In conducting reviews and audits, MMS will examine whether or 
not the contract reflects more than the consideration actually 
transferred either directly or indirectly from the lessee to the 
transporter for the transportation. If the contract reflects more than 
the total consideration, then the MMS may require that the 
transportation allowance be determined in accordance with paragraph (b) 
of this section.
    (iii) If the MMS determines that the consideration paid pursuant to 
an arm's-length transportation contract does not reflect the reasonable 
value of the transportation because of misconduct by or between the 
contracting parties, or because the lessee otherwise has breached its 
duty to the lessor to market the production for the mutual benefit of 
the lessee and the lessor, then MMS shall require that the 
transportation allowance be determined in accordance with paragraph (b) 
of this section. When MMS determines that the value of the 
transportation may be unreasonable, MMS will notify the lessee and give 
the lessee an opportunity to provide written information justifying the 
lessee's transportation costs.
    (2)(i) If an arm's-length transportation contract includes more than 
one product in a gaseous phase and the transportation costs attributable 
to each product cannot be determined from the contract, the total 
transportation costs shall be allocated in a consistent and equitable 
manner to each of the products transported in the same proportion as the 
ratio of the volume of each product (excluding waste products which have 
no value) to the volume of all products in the gaseous phase (excluding 
waste products which have no value). Except as provided in this 
paragraph, no allowance may be taken for the costs of transporting lease 
production which is not royalty bearing without MMS approval.
    (ii) Notwithstanding the requirements of paragraph (i), the lessee 
may propose to MMS a cost allocation method on the basis of the values 
of the products transported. MMS shall approve the method unless it 
determines that it is not consistent with the purposes of the 
regulations in this part.
    (3) If an arm's-length transportation contract includes both gaseous 
and liquid products and the transportation costs attributable to each 
cannot be determined from the contract, the lessee shall propose an 
allocation procedure to MMS. The lessee may use the transportation 
allowance determined in accordance with its proposed allocation 
procedure until MMS issues its determination on the acceptability of the 
cost allocation. The lessee shall submit all relevant data to support 
its proposal. MMS shall then determine the gas transportation allowance 
based upon the lessee's proposal and any additional information MMS 
deems necessary. The lessee must submit the allocation proposal within 3 
months of claiming the allocated deduction on the Form MMS-2014.
    (4) Where the lessee's payments for transportation under an arm's-
length contract are not based on a dollar per unit, the lessee shall 
convert whatever consideration is paid to a dollar value equivalent for 
the purposes of this section.
    (5) Where an arm's-length sales contract price or a posted price 
includes a provision whereby the listed price is reduced by a 
transportation factor, MMS will not consider the transportation factor 
to be a transportation allowance. The transportation factor may be used 
in determining the lessee's gross proceeds for the sale of the product. 
The transportation factor may not exceed 50 percent of the base price of 
the product without MMS approval.
    (b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length transportation contract or has no contract, including those 
situations where the lessee performs transportation services for itself, 
the transportation allowance will be based upon the lessee's reasonable 
actual costs as provided in this paragraph. All transportation 
allowances deducted under a

[[Page 105]]

non-arm's-length or no contract situation are subject to monitoring, 
review, audit, and adjustment. The lessee must claim a transportation 
allowance by reporting it as a separate entry on the Form MMS-2014. When 
necessary or appropriate, MMS may direct a lessee to modify its 
estimated or actual transportation allowance deduction.
    (2) The transportation allowance for non-arm's-length or no-contract 
situations shall be based upon the lessee's actual costs for 
transportation during the reporting period, including operating and 
maintenance expenses, overhead, and either depreciation and a return on 
undepreciated capital investment in accordance with paragraph 
(b)(2)(iv)(A) of this section, or a cost equal to the initial 
depreciable investment in the transportation system multiplied by a rate 
of return in accordance with paragraph (b)(2)(iv)(B) of this section. 
Allowable capital costs are generally those costs for depreciable fixed 
assets (including costs of delivery and installation of capital 
equipment) which are an integral part of the transportation system.
    (i) Allowable operating expenses include: Operations supervision and 
engineering; operations labor; fuel; utilities; materials; ad valorem 
property taxes; rent; supplies; and any other directly allocable and 
attributable operating expense which the lessee can document.
    (ii) Allowable maintenance expenses include: Maintenance of the 
transportation system; maintenance of equipment; maintenance labor; and 
other directly allocable and attributable maintenance expenses which the 
lessee can document.
    (iii) Overhead directly attributable and allocable to the operation 
and maintenance of the transportation system is an allowable expense. 
State and Federal income taxes and severance taxes and other fees, 
including royalties, are not allowable expenses.
    (iv) A lessee may use either depreciation or a return on depreciable 
capital investment. After a lessee has elected to use either method for 
a transportation system, the lessee may not later elect to change to the 
other alternative without approval of the MMS.
    (A) To compute depreciation, the lessee may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the transportation system services, or a 
unit of production method. After an election is made, the lessee may not 
change methods without MMS approval. A change in ownership of a 
transportation system shall not alter the depreciation schedule 
established by the original transporter/lessee for purposes of the 
allowance calculation. With or without a change in ownership, a 
transportation system shall be depreciated only once. Equipment shall 
not be depreciated below a reasonable salvage value.
    (B) The MMS shall allow as a cost an amount equal to the allowable 
initial capital investment in the transportation system multiplied by 
the rate of return determined pursuant to paragraph (b)(2)(v) of this 
section. No allowance shall be provided for depreciation. This 
alternative shall apply only to transportation facilities first placed 
in service after March 1, 1988.
    (v) The rate of return must be 1.3 times the industrial rate 
associated with Standard & Poor's BBB rating. The BBB rate must be the 
monthly average rate as published in Standard & Poor's Bond Guide for 
the first month for which the allowance is applicable. The rate must be 
redetermined at the beginning of each subsequent calendar year.
    (3)(i) The deduction for transportation costs shall be determined on 
the basis of the lessee's cost of transporting each product through each 
individual transportation system. Where more than one product in a 
gaseous phase is transported, the allocation of costs to each of the 
products transported shall be made in a consistent and equitable manner 
in the same proportion as the ratio of the volume of each product 
(excluding waste products which have no value) to the volume of all 
products in the gaseous phase (excluding waste products which have no 
value). Except as provided in this paragraph, the lessee may not take an 
allowance for transporting a product which is not royalty bearing 
without MMS approval.

[[Page 106]]

    (ii) Notwithstanding the requirements of paragraph (b)(3)(i), the 
lessee may propose to the MMS a cost allocation method on the basis of 
the values of the products transported. MMS shall approve the method 
unless it determines that it is not consistent with the purposes of the 
regulations in this part.
    (4) Where both gaseous and liquid products are transported through 
the same transportation system, the lessee shall propose a cost 
allocation procedure to MMS. The lessee may use the transportation 
allowance determined in accordance with its proposed allocation 
procedure until MMS issues its determination on the acceptability of the 
cost allocation. The lessee shall submit all relevant data to support 
its proposal. MMS shall then determine the transportation allowance 
based upon the lessee's proposal and any additional information MMS 
deems necessary. The lessee must submit the allocation proposal within 3 
months of claiming the allocated deduction on the Form MMS-2014.
    (5) You may apply for an exception from the requirement to compute 
actual costs under paragraphs (b)(1) through (b)(4) of this section.
    (i) The MMS will grant the exception if:
    (A) The transportation system has a tariff filed with the Federal 
Energy Regulatory Commission (FERC) or a state regulatory agency, that 
FERC or the state regulatory agency has permitted to become effective, 
and
    (B) Third parties are paying prices, including discounted prices, 
under the tariff to transport gas on the system under arm's-length 
transportation contracts.
    (ii) If MMS approves the exception, you must calculate your 
transportation allowance for each production month based on the lesser 
of the volume-weighted average of the rates paid by the third parties 
under arm's-length transportation contracts during that production month 
or the non-arm's-length payment by the lessee to the pipeline.
    (iii) If during any production month there are no prices paid under 
the tariff by third parties to transport gas on the system under arm's-
length transportation contracts, you may use the volume-weighted average 
of the rates paid by third parties under arm's-length transportation 
contracts in the most recent preceding production month in which the 
tariff remains in effect and third parties paid such rates, for up to 
five successive production months. You must use the non-arm's-length 
payment by the lessee to the pipeline if it is less than the volume-
weighted average of the rates paid by third parties under arm's-length 
contracts.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) You must 
use a separate entry on Form MMS-2014 to notify MMS of a transportation 
allowance.
    (ii) The MMS may require you to submit arm's-length transportation 
contracts, production agreements, operating agreements, and related 
documents. Recordkeeping requirements are found at part 207 of this 
chapter.
    (iii) You may not use a transportation allowance that was in effect 
before March 1, 1988. You must use the provisions of this subpart to 
determine your transportation allowance.
    (2) Non-arm's-length or no contract. (i) You must use a separate 
entry on Form MMS-2014 to notify MMS of a transportation allowance.
    (ii) For new transportation facilities or arrangements, base your 
initial deduction on estimates of allowable gas transportation costs for 
the applicable period. Use the most recently available operations data 
for the transportation system or, if such data are not available, use 
estimates based on data for similar transportation systems. Paragraph 
(e) of this section will apply when you amend your report based on your 
actual costs.
    (iii) The MMS may require you to submit all data used to calculate 
the allowance deduction. Recordkeeping requirements are found at part 
207 of this chapter.
    (iv) If you are authorized under paragraph (b)(5) of this section to 
use an exception to the requirement to calculate your actual 
transportation costs, you must follow the reporting requirements of 
paragraph (c)(1) of this section.
    (v) You may not use a transportation allowance that was in effect 
before

[[Page 107]]

March 1, 1988. You must use the provisions of this subpart to determine 
your transportation allowance.
    (d) Interest and assessments. (1) If a lessee deducts a 
transportation allowance on its Form MMS-2014 that exceeds 50 percent of 
the value of the gas transported without obtaining prior approval of MMS 
under 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.
    (2) If a lessee erroneously reports a transportation allowance which 
results in an underpayment of royalties, interest shall be paid on the 
amount of that underpayment.
    (3) Interest required to be paid by this section shall be determined 
in accordance with 30 CFR 218.54.
    (e) Adjustments. (1) If the actual transportation allowance is less 
than the amount the lessee has taken on Form MMS-2014 for each month 
during the allowance reporting period, the lessee shall be required to 
pay additional royalties due plus interest computed under 30 CFR 218.54 
from the allowance reporting period when the lessee took the deduction 
to the date the lessee repays the difference to MMS. If the actual 
transportation allowance is greater than the amount the lessee has taken 
on Form MMS-2014 for each month during the allowance reporting period, 
the lessee shall be entitled to a credit without interest.
    (2) For lessees transporting production from onshore Federal leases, 
the lessee must submit a corrected Form MMS-2014 to reflect actual 
costs, together with any payment, in accordance with instructions 
provided by MMS.
    (3) For lessees transporting gas production from leases on the OCS, 
if the lessee's estimated transportation allowance exceeds the allowance 
based on actual costs, the lessee must submit a corrected Form MMS-2014 
to reflect actual costs, together with its payment, in accordance with 
instructions provided by MMS. If the lessee's estimated transportation 
allowance is less than the allowance based on actual costs, the refund 
procedure will be specified by MMS.
    (f) Allowable costs in determining transportation allowances. You 
may include, but are not limited to (subject to the requirements of 
paragraph (g) of this section), the following costs in determining the 
arm's-length transportation allowance under paragraph (a) of this 
section or the non-arm's-length transportation allowance under paragraph 
(b) of this section. You may not use any cost as a deduction that 
duplicates all or part of any other cost that you use under this 
paragraph.
    (1) Firm demand charges paid to pipelines. You may deduct firm 
demand charges or capacity reservation fees paid to a pipeline, 
including charges or fees for unused firm capacity that you have not 
sold before you report your allowance. If you receive a payment from any 
party for release or sale of firm capacity after reporting a 
transportation allowance that included the cost of that unused firm 
capacity, or if you receive a payment or credit from the pipeline for 
penalty refunds, rate case refunds, or other reasons, you must reduce 
the firm demand charge claimed on the Form MMS-2014 by the amount of 
that payment. You must modify the Form MMS-2014 by the amount received 
or credited for the affected reporting period, and pay any resulting 
royalty and late payment interest due;
    (2) Gas supply realignment (GSR) costs. The GSR costs result from a 
pipeline reforming or terminating supply contracts with producers to 
implement the restructuring requirements of FERC Orders in 18 CFR part 
284;
    (3) Commodity charges. The commodity charge allows the pipeline to 
recover the costs of providing service;
    (4) Wheeling costs. Hub operators charge a wheeling cost for 
transporting gas from one pipeline to either the same or another 
pipeline through a market center or hub. A hub is a connected manifold 
of pipelines through which a series of incoming pipelines are 
interconnected to a series of outgoing pipelines;
    (5) Gas Research Institute (GRI) fees. The GRI conducts research, 
development, and commercialization programs on natural gas related 
topics for the benefit of the U.S. gas industry and gas

[[Page 108]]

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 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

[[Page 109]]

procedure that requires deduction of transportation costs.

[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45762, Nov. 14, 1988; 61 
FR 5465, Feb. 12, 1996; 62 FR 65762, Dec. 16, 1997; 70 FR 11878, Mar. 
10, 2005; 73 FR 15891, Mar. 26, 2008]



Sec. 206.158  Processing allowances--general.

    (a) Where the value of gas is determined pursuant to Sec. 206.153 
of this subpart, a deduction shall be allowed for the reasonable actual 
costs of processing.
    (b) Processing costs must be allocated among the gas plant products. 
A separate processing allowance must be determined for each gas plant 
product and processing plant relationship. Natural gas liquids (NGL's) 
shall be considered as one product.
    (c)(1) Except as provided in paragraph (d)(2) of this section, the 
processing allowance shall not be applied against the value of the 
residue gas. Where there is no residue gas MMS may designate an 
appropriate gas plant product against which no allowance may be applied.
    (2) Except as provided in paragraph (c)(3) of this section, the 
processing allowance deduction on the basis of an individual product 
shall not exceed 66\2/3\ percent of the value of each gas plant product 
determined in accordance with Sec. 206.153 of this subpart (such value 
to be reduced first for any transportation allowances related to 
postprocessing transportation authorized by Sec. 206.156 of this 
subpart).
    (3) Upon request of a lessee, MMS may approve a processing allowance 
in excess of the limitation prescribed by paragraph (c)(2) of this 
section. The lessee must demonstrate that the processing costs incurred 
in excess of the limitation prescribed in paragraph (c)(2) of this 
section were reasonable, actual, and necessary. An application for 
exception (using Form MMS-4393, Request to Exceed Regulatory Allowance 
Limitation) shall contain all relevant and supporting documentation for 
MMS to make a determination. Under no circumstances shall the value for 
royalty purposes of any gas plant product be reduced to zero.
    (d)(1) Except as provided in paragraph (d)(2) of this section, no 
processing cost deduction shall be allowed for the costs of placing 
lease products in marketable condition, including dehydration, 
separation, compression, or storage, even if those functions are 
performed off the lease or at a processing plant. Where gas is processed 
for the removal of acid gases, commonly referred to as ``sweetening,'' 
no processing cost deduction shall be allowed for such costs unless the 
acid gases removed are further processed into a gas plant product. In 
such event, the lessee shall be eligible for a processing allowance as 
determined in accordance with this subpart. However, MMS will not grant 
any processing allowance for processing lease production which is not 
royalty bearing.
    (2)(i) If the lessee incurs extraordinary costs for processing gas 
production from a gas production operation, it may apply to MMS for an 
allowance for those costs which shall be in addition to any other 
processing allowance to which the lessee is entitled pursuant to this 
section. Such an allowance may be granted only if the lessee can 
demonstrate that the costs are, by reference to standard industry 
conditions and practice, extraordinary, unusual, or unconventional.
    (ii) Prior MMS approval to continue an extraordinary processing cost 
allowance is not required. However, to retain the authority to deduct 
the allowance the lessee must report the deduction to MMS in a form and 
manner prescribed by MMS.
    (e) If MMS determines that a lessee has improperly determined a 
processing allowance authorized by this subpart, then the lessee must 
pay any additional royalties, plus interest determined under 30 CFR 
218.54, or will be entitled to a credit with interest. If the lessee 
takes a deduction for processing on Form MMS-2014 by improperly netting 
the allowance against the sales value of the gas plant products instead 
of reporting the allowance as a separate entry, MMS may assess a civil 
penalty under 30 CFR part 241.

[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5466, Feb. 12, 1996; 64 
FR 43288, Aug. 10, 1999; 73 FR 15891, Mar. 26, 2008]

[[Page 110]]



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 entry on the Form MMS-2014.
    (ii) In conducting reviews and audits, MMS will examine whether the 
contract reflects more than the consideration actually transferred 
either directly or indirectly from the lessee to the processor for the 
processing. If the contract reflects more than the total consideration, 
then the MMS may require that the processing allowance be determined in 
accordance with paragraph (b) of this section.
    (iii) If MMS determines that the consideration paid pursuant to an 
arm's-length processing contract does not reflect the reasonable value 
of the processing because of misconduct by or between the contracting 
parties, or because the lessee otherwise has breached its duty to the 
lessor to market the production for the mutual benefit of the lessee and 
lessor, then MMS shall require that the processing allowance be 
determined in accordance with paragraph (b) of this section. When MMS 
determines that the value of the processing may be unreasonable, MMS 
will notify the lessee and give the lessee an opportunity to provide 
written information justifying the lessee's processing costs.
    (2) If an arm's-length processing contract includes more than one 
gas plant product and the processing costs attributable to each product 
can be determined from the contract, then the processing costs for each 
gas plant product shall be determined in accordance with the contract. 
No allowance may be taken for the costs of processing lease production 
which is not royalty-bearing.
    (3) If an arm's-length processing contract includes more than one 
gas plant product and the processing costs attributable to each product 
cannot be determined from the contract, the lessee shall propose an 
allocation procedure to MMS. The lessee may use its proposed allocation 
procedure until MMS issues its determination. The lessee shall submit 
all relevant data to support its proposal. MMS shall then determine the 
processing allowance based upon the lessee's proposal and any additional 
information MMS deems necessary. No processing allowance will be granted 
for the costs of processing lease production which is not royalty 
bearing. The lessee must submit the allocation proposal within 3 months 
of claiming the allocated deduction on Form MMS-2014.
    (4) Where the lessee's payments for processing under an arm's-length 
contract are not based on a dollar per unit basis, the lessee shall 
convert whatever consideration is paid to a dollar value equivalent for 
the purposes of this section.
    (b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length processing contract or has no contract, including those 
situations where the lessee performs processing for itself, the 
processing allowance will be based upon the lessee's reasonable actual 
costs as provided in this paragraph. All processing allowances deducted 
under a non-arm's-length or no-contract situation are subject to 
monitoring, review, audit, and adjustment. The lessee must claim a 
processing allowance by reflecting it as a separate entry on the Form 
MMS-2014. When necessary or appropriate, MMS may direct a lessee to 
modify its estimated or actual processing allowance.
    (2) The processing allowance for non-arm's-length or no-contract 
situations shall be based upon the lessee's actual costs for processing 
during the reporting period, including operating and maintenance 
expenses, overhead, and either depreciation and a return on 
undepreciated capital investment in accordance with paragraph 
(b)(2)(iv)(A) of this section, or a cost equal to the initial 
depreciable investment in the

[[Page 111]]

processing plant multiplied by a rate of return in accordance with 
paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are 
generally those costs for depreciable fixed assets (including costs of 
delivery and installation of capital equipment) which are an integral 
part of the processing plant.
    (i) Allowable operating expenses include: Operations supervision and 
engineering; operations labor; fuel; utilities; materials; ad valorem 
property taxes; rent; supplies; and any other directly allocable and 
attributable operating expense which the lessee can document.
    (ii) Allowable maintenance expenses include: Maintenance of the 
processing plant; maintenance of equipment; maintenance labor; and other 
directly allocable and attributable maintenance expenses which the 
lessee can document.
    (iii) Overhead directly attributable and allocable to the operation 
and maintenance of the processing plant is an allowable expense. State 
and Federal income taxes and severance taxes, including royalties, are 
not allowable expenses.
    (iv) A lessee may use either depreciation or a return on depreciable 
capital investment. When a lessee has elected to use either method for a 
processing plant, the lessee may not later elect to change to the other 
alternative without approval of the MMS.
    (A) To compute depreciation, the lessee may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the processing plant services, or a unit-
of-production method. After an election is made, the lessee may not 
change methods without MMS approval. A change in ownership of a 
processing plant shall not alter the depreciation schedule established 
by the original processor/lessee for purposes of the allowance 
calculation. With or without a change in ownership, a processing plant 
shall be depreciated only once. Equipment shall not be depreciated below 
a reasonable salvage value.
    (B) The MMS shall allow as a cost an amount equal to the allowable 
initial capital investment in the processing plant multiplied by the 
rate of return determined pursuant to paragraph (b)(2)(v) of this 
section. No allowance shall be provided for depreciation. This 
alternative shall apply only to plants first placed in service after 
March 1, 1988.
    (v) The rate of return must be the industrial rate associated with 
Standard and Poor's BBB rating. The rate of return must be the monthly 
average rate as published in Standard and Poor's Bond Guide for the 
first month for which the allowance is applicable. The rate must be 
redetermined at the beginning of each subsequent calendar year.
    (3) The processing allowance for each gas plant product shall be 
determined based on the lessee's reasonable and actual cost of 
processing the gas. Allocation of costs to each gas plant product shall 
be based upon generally accepted accounting principles. The lessee may 
not take an allowance for the costs of processing lease production which 
is not royalty bearing.
    (4) A lessee may apply to MMS for an exception from the requirement 
that it compute actual costs in accordance with paragraphs (b)(1) 
through (b)(3) of this section. The MMS may grant the exception only if: 
(i) The lessee has arm's-length contracts for processing other gas 
production at the same processing plant; and (ii) at least 50 percent of 
the gas processed annually at the plant is processed pursuant to arm's-
length processing contracts; if the MMS grants the exception, the lessee 
shall use as its processing allowance the volume weighted average prices 
charged other persons pursuant to arm's-length contracts for processing 
at the same plant.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) The 
lessee must notify MMS of an allowance based on incurred costs by using 
a separate entry on the Form MMS-2014.
    (ii) The MMS may require that a lessee submit arm's-length 
processing contracts and related documents. Documents shall be submitted 
within a reasonable time, as determined by MMS.
    (2) Non-arm's-length or no contract. (i) The lessee must notify MMS 
of an allowance based on the incurred costs by

[[Page 112]]

using a separate entry on the Form MMS-2014.
    (ii) For new processing plants, the lessee's initial deduction shall 
include estimates of the allowable gas processing costs for the 
applicable period. Cost estimates shall be based upon the most recently 
available operations data for the plant or, if such data are not 
available, the lessee shall use estimates based upon industry data for 
similar gas processing plants.
    (iii) Upon request by MMS, the lessee shall submit all data used to 
prepare the allowance deduction. The data shall be provided within a 
reasonable period of time, as determined by MMS.
    (iv) If the lessee is authorized to use the volume weighted average 
prices charged other persons as its processing allowance in accordance 
with paragraph (b)(4) of this section, it shall follow the reporting 
requirements of paragraph (c)(1) of this section.
    (d) Interest. (1) If a lessee deducts a processing allowance on its 
Form MMS-2014 that exceeds 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.
    (2) If a lessee erroneously reports a processing allowance which 
results in an underpayment of royalties, interest shall be paid on the 
amount of that underpayment.
    (3) Interest required to be paid by this section shall be determined 
in accordance with 30 CFR 218.54.
    (e) Adjustments. (1) If the actual processing allowance is less than 
the amount the lessee has taken on Form MMS-2014 for each month during 
the allowance reporting period, the lessee shall pay additional 
royalties due plus interest computed under 30 CFR 218.54 from the 
allowance reporting period when the lessee took the deduction to the 
date the lessee repays the difference to MMS. If the actual processing 
allowance is greater than the amount the lessee has taken on Form MMS-
2014 for each month during the allowance reporting period, the lessee 
shall be entitled to a credit with interest.
    (2) For lessees processing production from onshore Federal leases, 
the lessee must submit a corrected Form MMS-2014 to reflect actual 
costs, together with any payment, in accordance with instructions 
provided by MMS.
    (3) For lessees processing gas production from leases on the OCS, if 
the lessee's estimated processing allowance exceeds the allowance based 
on actual costs, the lessee must submit a corrected Form MMS-2014 to 
reflect actual costs, together with its payment, in accordance with 
instructions provided by MMS. If the lessee's estimated costs were less 
than the actual costs, the refund procedure will be specified by MMS.
    (f) Other processing cost determinations. The provisions of this 
section shall apply to determine processing costs when establishing 
value using a net back valuation procedure or any other procedure that 
requires deduction of processing costs.

[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45762, Nov. 14, 1988; 61 
FR 5466, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999; 73 FR 15891, Mar. 
26, 2008]



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

[[Page 113]]

the value of production for royalty purposes consistent with the mineral 
leasing laws, other applicable laws, and lease terms. This subpart does 
not apply to Federal leases.
    (b) If the specific provisions of any Federal statute, treaty, 
negotiated agreement, settlement agreement resulting from any 
administrative or judicial proceeding, or Indian oil and gas lease are 
inconsistent with any regulation in this subpart, then the Federal 
statute, treaty, negotiated agreement, settlement agreement, or lease 
will govern to the extent of that inconsistency.
    (c) You may calculate the value of production for royalty purposes 
under methods other than those the regulations in this title require, 
but only if you, the tribal lessor, and MMS jointly agree to the 
valuation methodology. For leases on Indian allotted lands, you and MMS 
must agree to the valuation methodology.
    (d) All royalty payments you make to MMS are subject to monitoring, 
review, audit, and adjustment.
    (e) The regulations in this subpart are intended to ensure that the 
trust responsibilities of the United States with respect to the 
administration of Indian oil and gas leases are discharged in accordance 
with the requirements of the governing mineral leasing laws, treaties, 
and lease terms.



Sec. 206.171  What definitions apply to this subpart?

    The following definitions apply to this subpart and to subpart J of 
part 202 of this title:
    Accounting for comparison means the same as dual accounting.
    Active spot market means a market where one or more MMS-acceptable 
publications publish bidweek prices (or if bidweek prices are not 
available, first of the month prices) for at least one index-pricing 
point in the index zone.
    Allowance means a deduction in determining value for royalty 
purposes. Processing allowance means an allowance for the reasonable, 
actual costs of processing gas determined under this subpart. 
Transportation allowance means an allowance for the reasonable, actual 
cost of transportation determined under this subpart.
    Approved Federal Agreement (AFA) means a unit or communitization 
agreement approved under departmental regulations.
    Area means a geographic region at least as large as the defined 
limits of an oil or gas field, in which oil or gas lease products have 
similar quality, economic, or legal characteristics. An area may be all 
lands within the boundaries of an Indian reservation.
    Arm's-length contract means a contract or agreement that has been 
arrived at in the marketplace between independent, nonaffiliated persons 
with opposing economic interests regarding that contract. For purposes 
of this subpart, two persons are affiliated if one person controls, is 
controlled by, or is under common control with another person. The 
following percentages (based on the instruments of ownership of the 
voting securities of an entity, or based on other forms of ownership) 
determine if persons are affiliated:
    (1) Ownership in excess of 50 percent constitutes control.
    (2) Ownership of 10 through 50 percent creates a presumption of 
control.
    (3) Ownership of less than 10 percent creates a presumption of 
noncontrol which MMS may rebut if it demonstrates actual or legal 
control, including the existence of interlocking directorates. 
Notwithstanding any 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.

[[Page 114]]

    Compression means raising the pressure of gas.
    Condensate means liquid hydrocarbons (normally exceeding 40 degrees 
of API gravity) recovered at the surface without resorting to 
processing. Condensate is the mixture of liquid hydrocarbons that 
results from condensation of petroleum hydrocarbons existing initially 
in a gaseous phase in an underground reservoir.
    Contract means any oral or written agreement, including amendments 
or revisions thereto, between two or more persons and enforceable by law 
that with due consideration creates an obligation.
    Dedicated means a contractual commitment to deliver gas production 
(or a specified portion of production) from a lease or well when that 
production is specified in a sales contract and that production must be 
sold pursuant to that contract to the extent that production occurs from 
that lease or well.
    Drip condensate means any condensate recovered downstream of the 
facility measurement point without resorting to processing. Drip 
condensate includes condensate recovered as a result of its becoming a 
liquid during the transportation of the gas removed from the lease or 
recovered at the inlet of a gas processing plant by mechanical means, 
often referred to as scrubber condensate.
    Dual Accounting (or accounting for comparison) refers to the 
requirement to pay royalty based on a value which is the higher of the 
value of gas prior to processing less any applicable allowances as 
compared to the combined value of drip condensate, residue gas, and gas 
plant products after processing, less applicable allowances.
    Entitlement (or entitled share) means the gas production from a 
lease, or allocable to lease acreage under the terms of an AFA, 
multiplied by the operating rights owner's percentage of interest 
ownership in the lease or the acreage.
    Facility measurement point (or point of royalty settlement) means 
the point where the BLM-approved measurement device is located for 
determining the volume of gas removed from the lease. The facility 
measurement point may be on the lease or off-lease with BLM approval.
    Field means a geographic region situated over one or more subsurface 
oil and gas reservoirs encompassing at least the outermost boundaries of 
all oil and gas accumulations known to be within those reservoirs 
vertically projected to the land surface. Onshore fields are usually 
given names and their official boundaries are often designated by oil 
and gas regulatory agencies in the respective States in which the fields 
are located.
    Gas means any fluid, either combustible or noncombustible, 
hydrocarbon or nonhydrocarbon, which is extracted from a reservoir and 
which has neither independent shape nor volume, but tends to expand 
indefinitely. It is a substance that exists in a gaseous or rarefied 
state under standard temperature and pressure conditions.
    Gas plant products means separate marketable elements, compounds, or 
mixtures, whether in liquid, gaseous, or solid form, resulting from 
processing gas. However, it does not include residue gas.
    Gathering means the movement of lease production to a central 
accumulation or treatment point on the lease, unit, or communitized 
area; or a central accumulation or treatment point off the lease, unit, 
or communitized area as approved by BLM operations personnel.
    Gross proceeds (for royalty payment purposes) means the total monies 
and other consideration accruing to an oil and gas lessee for the 
disposition of unprocessed gas, residue gas, and gas plant products 
produced. Gross proceeds includes, but is not limited to, payments to 
the lessee for certain services such as compression, dehydration, 
measurement, or field gathering to the extent that the lessee is 
obligated to perform them at no cost to the Indian lessor, and payments 
for gas processing rights. Gross proceeds, as applied to gas, also 
includes but is not limited to reimbursements for severance taxes and 
other reimbursements. Tax reimbursements are part of the gross proceeds 
accruing to a lessee even though the Indian royalty interest is exempt

[[Page 115]]

from taxation. Monies and other consideration, including the forms of 
consideration identified in this paragraph, to which a lessee is 
contractually or legally entitled but which it does not seek to collect 
through reasonable efforts are also part of gross proceeds.
    Index means the calculated composite price ($/MMBtu) of spot-market 
sales published by a publication that meets MMS-established criteria for 
acceptability at the index-pricing point.
    Index-pricing point (IPP) means any point on a pipeline for which 
there is an index.
    Index zone means a field or an area with an active spot market and 
published indices applicable to that field or area that are acceptable 
to MMS under Sec. 206.172(d)(2).
    Indian allottee means any Indian for whom land or an interest in 
land is held in trust by the United States or who holds title subject to 
Federal restriction against alienation.
    Indian tribe means any Indian tribe, band, nation, pueblo, 
community, rancheria, colony, or other group of Indians for which any 
land or interest in land is held in trust by the United States or which 
is subject to Federal restriction against alienation.
    Lease means any contract, profit-share arrangement, joint venture, 
or other agreement issued or approved by the United States under a 
mineral leasing law that authorizes exploration for, development or 
extraction of, or removal of lease products--or the land area covered by 
that authorization, whichever is required by the context. For purposes 
of this subpart, this definition excludes Federal leases.
    Lease products means any leased minerals attributable to, 
originating from, or allocated to a lease.
    Lessee means any person to whom the United States, a tribe, and/or 
individual Indian landowner issues a lease, and any person who has been 
assigned an obligation to make royalty or other payments required by the 
lease. This includes any person who has an interest in a lease 
(including operating rights owners) as well as an operator or payor who 
has no interest in the lease but who has assumed the royalty payment 
responsibility.
    Like-quality lease products means lease products which have similar 
chemical, physical, and legal characteristics.
    Marketable condition means a condition in which lease products are 
sufficiently free from impurities and otherwise so conditioned that a 
purchaser will accept them under a sales contract typical for the field 
or area.
    MMS means the Minerals Management Service, Department of the 
Interior. MMS includes, where appropriate, tribal auditors acting under 
agreements under the Federal Oil and Gas Royalty Management Act of 1982, 
30 U.S.C. 1701 et seq. or other applicable agreements.
    Minimum royalty means that minimum amount of annual royalty that the 
lessee must pay as specified in the lease or in applicable leasing 
regulations.
    Natural gas liquids (NGL's) means those gas plant products 
consisting of ethane, propane, butane, or heavier liquid hydrocarbons.
    Net-back method (or work-back method) means a method for calculating 
market value of gas at the lease under which costs of transportation, 
processing, and manufacturing are deducted from the proceeds received 
for, or the value of, the gas, residue gas, or gas plant products, and 
any extracted, processed, or manufactured products, at the first point 
at which reasonable values for any such products may be determined by a 
sale under an arm's-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,

[[Page 116]]

consortium, or joint venture (when established as a separate entity).
    Point of royalty measurement means the same as facility measurement 
point.
    Processing means any process designed to remove elements or 
compounds (hydrocarbon and nonhydrocarbon) from gas, including 
absorption, adsorption, or refrigeration. Field processes which normally 
take place on or near the lease, such as natural pressure reduction, 
mechanical separation, heating, cooling, dehydration, desulphurization 
(or ``sweetening''), and compression, are not considered processing. The 
changing of pressures and/or temperatures in a reservoir is not 
considered processing.
    Residue gas means that hydrocarbon gas consisting principally of 
methane resulting from processing gas.
    Sales type code means the contract type or general disposition 
(e.g., arm's-length or non-arm's-length) of production from the lease. 
The sales type code applies to the sales contract, or other disposition, 
and not to the arm's-length or non-arm's-length nature of a 
transportation or processing allowance.
    Spot sales agreement means a contract wherein a seller agrees to 
sell to a buyer a specified amount of unprocessed gas, residue gas, or 
gas plant products at a specified price over a fixed period, usually of 
short duration. It also does not normally require a cancellation notice 
to terminate, and does not contain an obligation, or imply an intent, to 
continue in subsequent periods.
    Takes means when the operating rights owner sells or removes 
production from, or allocated to, the lease, or when such sale or 
removal occurs for the benefit of an operating rights owner.
    Work-back method means the same as net-back method.

[64 FR 43515, Aug. 10, 1999, as amended at 73 FR 15891, Mar. 26, 2008]



Sec. 206.172  How do I value gas produced from leases in an index zone?

    (a) What leases this section applies to. This section explains how 
lessees must value, for royalty purposes, gas produced from Indian 
leases located in an index zone. For other leases, value must be 
determined under Sec. 206.174.
    (1) You must use the valuation provision of this section if your 
lease is in an index zone and meets one of the following two 
requirements:
    (i) Has a major portion provision;
    (ii) Does not have a major portion provision, but provides for the 
Secretary to determine the value of production.
    (2) This section does not apply to carbon dioxide, nitrogen, or 
other non-hydrocarbon components of the gas stream. However, if they are 
recovered and sold separately from the gas stream, you must determine 
the value of these products under Sec. 206.174.
    (b) Valuing residue gas and gas before processing. (1) Except as 
provided in paragraphs (e), (f), and (g) of this section, this paragraph 
(b) explains how you must value the following four types of gas:
    (i) Gas production before processing;
    (ii) Gas production that you certify on Form MMS-4410, Certification 
for Not Performing Accounting for Comparison (Dual Accounting), is not 
processed before it flows into a pipeline with an index but which may be 
processed later;
    (iii) Residue gas after processing; and
    (iv) Gas that is never processed.
    (2) The value of gas production that is not sold under an arm's-
length dedicated contract is the index-based value determined under 
paragraph (d) of this section unless the gas was subject to a previous 
contract which was part of a gas contract settlement. If the previous 
contract was subject to a gas 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

[[Page 117]]

section or the value of that production determined under Sec. 
206.174(b).
    (c) Valuing gas that is processed before it flows into a pipeline 
with an index. Except as provided in paragraphs (e), (f), and (g) of 
this section, this paragraph (c) explains how you must value gas that is 
processed before it flows into a pipeline with an index. You must value 
this gas production based on the higher of the following two values:
    (1) The value of the gas before processing determined under 
paragraph (b) of this section.
    (2) The value of the gas after processing, which is either the 
alternative dual accounting value under Sec. 206.173 or the sum of the 
following three values:
    (i) The value of the residue gas determined under paragraph (b)(2) 
or (3) of this section, as applicable;
    (ii) The value of the gas plant products determined under Sec. 
206.174, less any applicable processing and/or transportation allowances 
determined under this subpart; and
    (iii) The value of any drip condensate associated with the processed 
gas determined under subpart B of this part.
    (d) Determining the index-based value for gas production. (1) To 
determine the index-based value per MMBtu for production from a lease in 
an index zone, you must use the following procedures:
    (i) For each MMS-approved publication, calculate the average of the 
highest reported prices for all index-pricing points in the index zone, 
except for any prices excluded under paragraph (d)(6) of this section;
    (ii) Sum the averages calculated in paragraph (d)(1)(i) of this 
section and divide by the number of publications; and
    (iii) Reduce the number calculated under paragraph (d)(1)(ii) of 
this section by 10 percent, but not by less than 10 cents per MMBtu or 
more than 30 cents per MMBtu. The result is the index-based value per 
MMBtu for production from all leases in that index zone.
    (2) MMS will publish in the Federal Register the index zones that 
are eligible for the index-based valuation method under this paragraph. 
MMS will monitor the market activity in the index zones and, if 
necessary, hold a technical conference to add or modify a particular 
index zone. Any change to the index zones will be published in the 
Federal Register. MMS will consider the following five factors and 
conditions in determining eligible index zones:
    (i) Areas for which MMS-approved publications establish index prices 
that accurately reflect the value of production in the field or area 
where the production occurs;
    (ii) Common markets served;
    (iii) Common pipeline systems;
    (iv) Simplification; and
    (v) Easy identification in MMS's systems, such as counties or Indian 
reservations.
    (3) If market conditions change so that an index-based method for 
determining value is no longer appropriate for an index zone, MMS will 
hold a technical conference to consider disqualification of an index 
zone. MMS will publish notice in the Federal Register if an index zone 
is disqualified. If an index zone is disqualified, then production from 
leases in that index zone cannot be valued under this paragraph.
    (4) MMS periodically will publish in the Federal Register a list of 
acceptable publications based on certain criteria, including, but not 
limited to the following five criteria:
    (i) Publications buyers and sellers frequently use;
    (ii) Publications frequently referenced in purchase or sales 
contracts;
    (iii) Publications that use adequate survey techniques, including 
the gathering of information from a substantial number of sales;
    (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.

[[Page 118]]

    (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-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:

[[Page 119]]

    (i) You must report the safety net price for each index zone to MMS 
on Form MMS-4411, Safety Net Report, no later than June 30 following 
each calendar year;
    (ii) You must pay and report on Form MMS-2014 additional royalties 
due no later than June 30 following each calendar year; and
    (iii) MMS may order you to amend your safety net price within one 
year from the date your Form MMS-4411 is due or is filed, whichever is 
later. If MMS does not order any amendments within that one-year period, 
your safety net price calculation is final.
    (f) Excluding some or all tribal leases from valuation under this 
section. (1) An Indian tribe may ask MMS to exclude some or all of its 
leases from valuation under this section. MMS will consult with BIA 
regarding the request.
    (i) If MMS approves the request for your lease, you must value your 
production under Sec. 206.174 beginning with production on the first 
day of the second month following the date MMS publishes notice of its 
decision in the Federal Register.
    (ii) If an Indian tribe requests exclusion from an index zone for 
less than all of its leases, MMS will approve the request only if the 
excluded leases may be segregated into one or more groups based on 
separate fields within the reservation.
    (2) An Indian tribe may ask MMS to terminate exclusion of its leases 
from valuation under this section. MMS will consult with BIA regarding 
the request.
    (i) If MMS approves the request, you must value your production 
under Sec. 206.172 beginning with production on the first day of the 
second month following the date MMS publishes notice of its decision in 
the Federal Register.
    (ii) Termination of an exclusion under paragraph (f)(2)(i) of this 
section cannot take effect earlier than 1 year after the first day of 
the production month that the exclusion was effective.
    (3) The Indian tribe's request to MMS under either paragraph (f)(1) 
or (2) of this section must be in the form of a tribal resolution.
    (g) Excluding Indian allotted leases from valuation under this 
section. (1)(i) MMS may exclude any Indian allotted leases from 
valuation under this section. MMS will consult with BIA regarding the 
exclusion.
    (ii) If MMS excludes your lease, you must value your production 
under Sec. 206.174 beginning with production on the first day of the 
second month following the date MMS publishes notice of its decision in 
the Federal Register.
    (iii) If MMS excludes any Indian allotted leases under this 
paragraph (g)(1), it will exclude all Indian allotted leases in the same 
field.
    (2)(i) MMS may terminate the exclusion of any Indian allotted leases 
from valuation under this section. MMS will consult with BIA regarding 
the termination.
    (ii) If MMS terminates the exclusion, you must value your production 
under Sec. 206.172 beginning with production on the first day of the 
second month following the date MMS publishes notice of its decision in 
the Federal Register.



Sec. 206.173  How do I calculate the alternative methodology for dual accounting?

    (a) Electing a dual accounting method. (1) If you are required to 
perform the accounting for comparison (dual accounting) under Sec. 
206.176, you have two choices. You may elect to perform the dual 
accounting calculation according to either Sec. 206.176(a) (called 
actual dual accounting), or paragraph (b) of this section (called the 
alternative methodology for dual accounting).
    (2) You must make a separate election to use the alternative 
methodology for dual accounting for your Indian leases in each MMS-
designated 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;

[[Page 120]]

    (F) Fort Peck Reservation;
    (G) Jicarilla Apache Reservation;
    (H) MMS-designated groups of counties in the State of Oklahoma;
    (I) Navajo Reservation;
    (J) Northern Cheyenne Reservation;
    (K) Rocky Boys Reservation;
    (L) Southern Ute Reservation;
    (M) Turtle Mountain Reservation;
    (N) Ute Mountain Ute Reservation;
    (O) Uintah and Ouray Reservation;
    (P) Wind River Reservation; and
    (Q) Any other area that MMS designates. MMS will publish a new area 
designation in the Federal Register.
    (ii) You may elect to begin using the alternative methodology for 
dual accounting at the beginning of any month. The first election to use 
the alternative methodology will be effective from the time of election 
through the end of the following calendar year. Thereafter, each 
election to use the alternative methodology must remain in effect for 2 
calendar years. You may return to the actual dual accounting method only 
at the beginning of the next election period or with the written 
approval of MMS and the tribal lessor for tribal leases, and MMS for 
Indian allottee leases in the designated area.
    (iii) When you elect to use the alternative methodology for a 
designated area, you must also use the alternative methodology for any 
new wells commenced and any new leases acquired in the designated area 
during the term of the election.
    (b) Calculating value using the alternative methodology for dual 
accounting. (1) The alternative methodology adjusts the value of gas 
before processing determined under either Sec. 206.172 or Sec. 206.174 
to provide the value of the gas after processing. You must use the value 
of the gas after processing for royalty payment purposes. The amount of 
the increase depends on your relationship with the owner(s) of the plant 
where the gas is processed. If you have no direct or indirect ownership 
interest in the processing plant, then the increase is lower, as 
provided in the table in paragraph (b)(2)(ii) of this section. If you 
have a direct or indirect ownership interest in the plant where the gas 
is processed, the increase is higher, as provided in paragraph 
(b)(2)(ii) of this section.
    (2) To calculate the value of the gas after processing using the 
alternative methodology for dual accounting, you must apply the increase 
to the value before processing, determined in either Sec. 206.172 or 
Sec. 206.174, as follows:
    (i) Value of gas after processing = (value determined under either 
Sec. 206.172 or Sec. 206.174, as applicable) x (1 + increment for dual 
accounting); and
    (ii) In this equation, the increment for dual accounting is the 
number you take from the applicable Btu range, determined under 
paragraph (b)(3) of this section, in the following table:

------------------------------------------------------------------------
                                                 Increment    Increment
                                                 if Lessee    if lessee
                                                   has no       has an
                   BTU range                     ownership    ownership
                                                interest in  interest in
                                                   plant        plant
------------------------------------------------------------------------
1001 to 1050..................................        .0275        .0375
1051 to 1100..................................        .0400        .0625
1101 to 1150..................................        .0425        .0750
1151 to 1200..................................        .0700        .1225
1201 to 1250..................................        .0975        .1700
1251 to 1300..................................        .1175        .2050
1301 to 1350..................................        .1400        .2400
1351 to 1400..................................        .1450        .2500
1401 to 1450..................................        .1500        .2600
1451 to 1500..................................        .1550        .2700
1501 to 1550..................................        .1600        .2800
1551 to 1600..................................        .1650        .2900
1601 to 1650..................................        .1850        .3225
1651 to 1700..................................        .1950        .3425
1701+.........................................        .2000        .3550
------------------------------------------------------------------------

    (3) The applicable Btu for purposes of this section is the volume 
weighted-average Btu for the lease computed from measurements at the 
facility measurement point(s) for gas production from the lease.
    (4) If any of your gas from the lease is processed during a month, 
use the following two paragraphs to determine which amounts are subject 
to dual accounting and which dual accounting method you must use.
    (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

[[Page 121]]

Btu/cf. Only the volumes of lease production measured at facility 
measurement points whose quality exceeds 1,000 Btu/cf are subject to 
dual accounting, and you may use the alternative methodology for these 
volumes. For gas measured at facility measurement points for these 
leases where the quality is equal to or less than 1,000 Btu/cf, you are 
not required to do dual accounting.



Sec. 206.174  How do I value gas production when an index-based method cannot be used?

    (a) Situations in which an index-based method cannot be used. (1) 
Gas production must be valued under this section in the following 
situations.
    (i) Your lease is not in an index zone (or MMS has excluded your 
lease from an index zone).
    (ii) If your lease is in an index zone and you sell your gas under 
an arm's-length dedicated contract, then the value of your gas is the 
higher of the value received under the dedicated contract determined 
under Sec. 206.174(b) or the value under Sec. 206.172.
    (iii) Also use this section to value any other gas production that 
cannot be valued under Sec. 206.172, as well as gas plant products, and 
to value components of the gas stream that have no Btu value (for 
example, carbon dioxide, nitrogen, etc.).
    (2) The value for royalty purposes of gas production subject to this 
subpart is the value of gas determined under this section less 
applicable allowances determined under this subpart.
    (3) You must determine the value of gas production that is processed 
and is subject to accounting for comparison using the procedure in Sec. 
206.176.
    (4) This paragraph applies if your lease has a major portion 
provision. It also applies if your lease does not have a major portion 
provision but the lease provides for the Secretary to determine value.
    (i) The value of production you must initially report and pay is the 
value determined in accordance with the other paragraphs of this 
section.
    (ii) MMS will determine the major portion value and notify you in 
the Federal Register of that value. The value of production for royalty 
purposes for your lease is the higher of either the value determined 
under this section which you initially used to report and pay royalties, 
or the major portion value calculated under this paragraph (a)(4). If 
the major portion value is higher, you must submit an amended Form MMS-
2014 to MMS by the due date specified in the written notice from MMS of 
the major portion value. Late-payment interest under 30 CFR 218.54 on 
any underpayment will not begin to accrue until the date the amended 
Form MMS-2014 is due to MMS.
    (iii) Except as provided in paragraph (a)(4)(iv) of this section, 
MMS will calculate the major portion value for each designated area 
(which are the same designated areas as under Sec. 206.173) using 
values reported for unprocessed gas and residue gas on Form MMS-2014 for 
gas produced from leases on that Indian reservation or other designated 
area. MMS will array the reported prices from highest to lowest price. 
The major portion value is that price at which 25 percent (by volume) of 
the gas (starting from the highest) is sold. MMS cannot unilaterally 
change the major portion value after you are notified in writing of what 
that value is for your leases.
    (iv) MMS may calculate the major portion value using different data 
than the data described in paragraph (a)(4)(iii) of this section or data 
to augment the data described in paragraph (a)(4)(iii) of this section. 
This may include price data reported to the State tax authority or price 
data from leases MMS has reviewed in the designated area. MMS may use 
this alternate or the augmented data source beginning with production on 
the first day of the month following the date MMS publishes notice in 
the Federal Register 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.

[[Page 122]]

    (i) You have the burden of demonstrating that your contract is 
arm's-length.
    (ii) In conducting reviews and audits for gas valued based upon 
gross proceeds under this paragraph, MMS will examine whether or not 
your contract reflects the total consideration actually transferred 
either directly or indirectly from the buyer to you or your affiliate 
for the gas, residue gas, or gas plant product. If the contract does not 
reflect the total consideration, then MMS may require that the gas, 
residue gas, or gas plant product sold under that contract be valued in 
accordance with paragraph (c) of this section. Value may not be less 
than the gross proceeds accruing to you or your affiliate, including the 
additional consideration.
    (iii) If MMS determines for gas valued under this paragraph that the 
gross proceeds accruing to you or your affiliate under an arm's-length 
contract do not reflect the value of the gas, residue gas, or gas plant 
products because of misconduct by or between the contracting parties, or 
because you otherwise have breached your duty to the lessor to market 
the production for the mutual benefit of you and the lessor, then MMS 
will require that the gas, residue gas, or gas plant product be valued 
under paragraphs (c)(2) or (3) of this section. In these circumstances, 
MMS will notify you and give you an opportunity to provide written 
information justifying your value.
    (iv) This paragraph applies to situations where a pipeline purchases 
gas from a lessee according to a cash-out program under a transportation 
contract. For all over-delivered volumes, the royalty value is the price 
the pipeline is required to pay for volumes within the tolerances for 
over-delivery specified in the transportation contract. Use the same 
value for volumes that exceed the over-delivery tolerances even if those 
volumes are subject to a lower price specified in the transportation 
contract. However, if MMS determines that the price specified in the 
transportation contract for over-delivered volumes is unreasonably low, 
the lessees must value all over-delivered volumes under paragraph (c)(2) 
or (3) of this section.
    (2) MMS may require you to certify that your arm's-length contract 
provisions include all of the consideration the buyer pays, either 
directly or indirectly, for the gas, residue gas, or gas plant product.
    (c) Non-arm's-length contracts. If your gas, residue gas, or any gas 
plant product is not sold under an arm's-length contract, then you must 
value the production using the first applicable method of the following 
three methods:
    (1) The gross proceeds accruing to you under your non-arm's-length 
contract sale (or other disposition other than by an arm's-length 
contract), provided that those gross proceeds are equivalent to the 
gross proceeds derived from, or paid under, comparable arm's-length 
contracts for purchases, sales, or other dispositions of like-quality 
gas in the same field (or, if necessary to obtain a reasonable sample, 
from the same area). For residue gas or gas plant products, the 
comparable arm's-length contracts must be for gas from the same 
processing plant (or, if necessary to obtain a reasonable sample, from 
nearby plants). In evaluating the comparability of arm's-length 
contracts for the purposes of these regulations, the following factors 
will be considered: price, time of execution, duration, market or 
markets served, terms, quality of gas, residue gas, or gas plant 
products, volume, and such other factors as may be appropriate to 
reflect the value of the gas, residue gas, or gas plant products.
    (2) A value determined by consideration of other information 
relevant in valuing like-quality gas, residue gas, or gas plant 
products, including gross proceeds under arm's-length contracts for 
like-quality gas in the same field or nearby fields or areas, or for 
residue gas or gas plant products from the same gas plant or other 
nearby processing plants. Other factors to consider include prices 
received in spot sales of gas, residue gas or gas plant products, other 
reliable public sources of price or market information, and other 
information as to the particular lease operation or the salability of 
such gas, residue gas, or gas plant products.
    (3) A net-back method or any other reasonable method to determine 
value.

[[Page 123]]

    (d) Supporting data. If you determine the value of production under 
paragraph (c) of this section, you must retain all data relevant to the 
determination of royalty value.
    (1) Such data will be subject to review and audit, and MMS will 
direct you to use a different value if we determine upon review or audit 
that the value you reported is inconsistent with the requirements of 
these regulations.
    (2) You must make all such data available upon request to the 
authorized MMS or Indian representatives, to the Office of the Inspector 
General of the Department, or other authorized persons. This includes 
your arm's-length sales and volume data for like-quality gas, residue 
gas, and gas plant products that are sold, purchased, or otherwise 
obtained from the same processing plant or from nearby processing 
plants, or from the same or nearby field or area.
    (e) Improper values. If MMS determines that you have not properly 
determined value, you must pay the difference, if any, between royalty 
payments made based upon the value you used and the royalty payments 
that are due based upon the value MMS established. You also must pay 
interest computed on that difference under 30 CFR 218.54. If you are 
entitled to a credit, MMS will provide instructions on how to take that 
credit.
    (f) Value guidance. You may ask MMS for guidance in determining 
value. You may propose a valuation method to MMS. Submit all available 
data related to your proposal and any additional information MMS deems 
necessary. MMS will promptly review your proposal and provide you with a 
non-binding determination of the guidance you request.
    (g) Minimum value of production. (1) For gas, residue gas, and gas 
plant products valued under this section, under no circumstances may the 
value of production for royalty purposes be less than the gross proceeds 
accruing to the lessee (including its affiliates) for gas, residue gas 
and/or any gas plant products, less applicable transportation allowances 
and processing allowances determined under this subpart.
    (2) For gas plant products valued under this section and not valued 
under Sec. 206.173, the alternative methodology for dual accounting, 
the minimum value of production for each gas plant product is as 
follows:
    (i) Leases in certain States and areas have specific minimum values.
    (A) For production from leases in Colorado in the San Juan Basin, 
New Mexico, and Texas, the monthly average minimum price reported in 
commercial price bulletins for the gas plant product at Mont Belvieu, 
Texas, minus 8.0 cents per gallon.
    (B) For production in Arizona, in Colorado outside the San Juan 
Basin, Minnesota, Montana, North Dakota, Oklahoma, South Dakota, Utah, 
and Wyoming, the monthly average minimum price reported in commercial 
price bulletins for the gas plant product at Conway, Kansas, minus 7.0 
cents per gallon;
    (ii) You may use any commercial price bulletin, but you must use the 
same bulletin for all of the calendar year. If the commercial price 
bulletin you are using stops publication, you may use a different 
commercial price bulletin for the remaining part of the calendar year; 
and (iii) If you use a commercial price bulletin that is published 
monthly, the monthly average minimum price is the bulletin's minimum 
price. If you use a commercial price bulletin that is published weekly, 
the monthly average minimum price is the arithmetic average of the 
bulletin's weekly minimum prices. If you use a commercial price bulletin 
that is published daily, the monthly average minimum price is the 
arithmetic average of the bulletin's minimum prices for each Wednesday 
in the month.
    (h) Marketable condition/Marketing. You are required to place gas, 
residue gas, and gas plant products in marketable condition and market 
the gas for the mutual benefit of the lessee and the lessor at no cost 
to the Indian lessor. When your gross proceeds establish 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.

[[Page 124]]

    (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 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:

[[Page 125]]

    (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 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

[[Page 126]]

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 sales type 
code may not exceed 50 percent of the value of the unprocessed gas, 
residue gas, or gas plant product. For purposes of this section, natural 
gas liquids are considered one product.
    (2) If you ask MMS, MMS may approve a transportation allowance 
deduction in excess of the limitations in paragraph (c)(1) of this 
section. To receive this approval, you must demonstrate that the 
transportation costs incurred in excess of the limitations in paragraph 
(c)(1) of this section were reasonable, actual, and necessary. Under no 
circumstances may an allowance reduce the value for royalty purposes 
under any sales type code to zero.
    (3) Your application for exception (using Form MMS-4393, Request to 
Exceed Regulatory Allowance Limitation) must contain all relevant and 
supporting documentation necessary for MMS to make a determination.
    (d) If MMS conducts a review or audit and determines that you have 
improperly determined a transportation allowance authorized by this 
subpart, then you will be required to pay any additional royalties, plus 
interest determined in accordance with 30 CFR 218.54. Alternatively, you 
may be entitled to a credit, but you will not receive any interest on 
your overpayment.

[64 FR 43515, Aug. 10, 1999, as amended at 73 FR 15891, Mar. 26, 2008]



Sec. 206.178  How do I determine a transportation allowance?

    (a) Determining a transportation allowance under an arm's-length 
contract. (1) This paragraph explains how to determine your allowance if 
you have an arm's-length transportation contract.
    (i) If you have an arm's-length contract for transportation of your 
production, the transportation allowance is the reasonable, actual costs 
you incur for transporting the unprocessed gas, residue gas and/or gas 
plant products under that contract. Paragraphs (a)(1)(ii) and (iii) of 
this section provide a limited exception. You have the burden of 
demonstrating that your contract is arm's-length. Your allowances also 
are subject to paragraph (e) of this section. You are required to submit 
to MMS a copy of your arm's-length transportation contract(s) and all 
subsequent amendments to the contract(s) within 2 months of the date MMS 
receives your report which claims the allowance on the Form MMS-2014.
    (ii) When either MMS or a tribe conducts reviews and audits, they 
will examine whether or not the contract reflects more than the 
consideration actually transferred either directly or indirectly from 
you to the transporter of the transportation. If the contract reflects 
more than the total consideration, then MMS may require that the 
transportation allowance be determined under paragraph (b) of this 
section.
    (iii) If MMS determines that the consideration paid under an arm's-
length transportation contract does not reflect the value of the 
transportation because of misconduct by or between the contracting 
parties, or because you otherwise have breached your duty to the lessor 
to market the production for the mutual benefit of you and the lessor, 
then MMS will require that the transportation allowance be determined 
under paragraph (b) of this section. In these circumstances, MMS will 
notify you and give you an opportunity to provide written information 
justifying your transportation costs.
    (2) This paragraph explains how to allocate the costs to each 
product if your arm's-length transportation contract includes more than 
one product in a gaseous phase and the transportation costs attributable 
to each product cannot be determined from the contract.
    (i) If your arm's-length transportation contract includes more than 
one product in a gaseous phase and the

[[Page 127]]

transportation costs attributable to each product cannot be determined 
from the contract, the total transportation costs must be allocated in a 
consistent and equitable manner to each of the products transported. To 
make this allocation, use the same proportion as the ratio that the 
volume of each product (excluding waste products which have no value) 
bears to the volume of all products in the gaseous phase (excluding 
waste products which have no value). Except as provided in this 
paragraph, you cannot take an allowance for the costs of transporting 
lease production that is not royalty bearing without MMS approval, or 
without lessor approval on tribal leases.
    (ii) As an alternative to paragraph (a)(2)(i) of this section, you 
may propose to MMS a cost allocation method based on the values of the 
products transported. MMS will approve the method if we determine that 
it meets one of the two following requirements:
    (A) The methodology in paragraph (a)(2)(i) of this section cannot be 
applied; and
    (B) Your proposal is more reasonable than the methodology in 
paragraph (a)(2)(i) of this section.
    (3) This paragraph explains how to allocate costs to each product if 
your arm's-length transportation contract includes both gaseous and 
liquid products and the transportation costs attributable to each cannot 
be determined from the contract.
    (i) If your arm's-length transportation contract includes both 
gaseous and liquid products and the transportation costs attributable to 
each cannot be determined from the contract, you must propose an 
allocation procedure to MMS. You may use the transportation allowance 
determined in accordance with your proposed allocation procedure until 
MMS decides whether to accept your cost allocation.
    (ii) You are required to submit all relevant data to support your 
allocation proposal. MMS will then determine the gas transportation 
allowance based upon your proposal and any additional information MMS 
deems necessary.
    (4) If your payments for transportation under an arm's-length 
contract are not based on a dollar per unit price, you must convert 
whatever consideration is paid to a dollar value equivalent for the 
purposes of this section.
    (5) Where an arm's-length sales contract price includes a reduction 
for a transportation factor, MMS will not consider the transportation 
factor to be a transportation allowance. You may use the transportation 
factor to determine your gross proceeds for the sale of the product. 
However, the transportation factor may not exceed 50 percent of the base 
price of the product without MMS approval.
    (b) Determining a transportation allowance under a non-arm's-length 
or no contract. (1) This paragraph explains how to determine your 
allowance if you have a non-arm's-length transportation contract or no 
contract.
    (i) When you have a non-arm's-length transportation contract or no 
contract, including those situations where you perform transportation 
services for yourself, the transportation allowance is based upon your 
reasonable, allowable, actual costs for transportation as provided in 
this paragraph.
    (ii) All transportation allowances deducted under a non-arm's-length 
or no contract situation are subject to monitoring, review, audit, and 
adjustment. You must submit the actual cost information to support the 
allowance to MMS on Form MMS-4295, Gas Transportation Allowance Report, 
within 3 months after the end of the 12-month period to which the 
allowance applies. However, MMS may approve a longer time period. MMS 
will monitor the allowance deductions to ensure that deductions are 
reasonable and allowable. When necessary or appropriate, MMS may require 
you to modify your actual transportation allowance deduction.
    (2) This paragraph explains what actual transportation costs are 
allowable under a non-arm's-length contract or no contract situation. 
The transportation allowance for non-arm's-length or no-contract 
situations is based upon your actual costs for transportation during the 
reporting period. Allowable costs include operating and maintenance 
expenses, overhead, and either depreciation and a return on 
undepreciated capital investment (in accordance with paragraph 
(b)(2)(iv)(A) of this section), or a cost equal to the

[[Page 128]]

initial depreciable investment in the transportation system multiplied 
by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this 
section. Allowable capital costs are generally those costs for 
depreciable fixed assets (including costs of delivery and installation 
of capital equipment) that are an integral part of the transportation 
system.
    (i) Allowable operating expenses include operations supervision and 
engineering, operations labor, fuel, utilities, materials, ad valorem 
property taxes, rent, supplies, and any other directly allocable and 
attributable operating expense that you can document.
    (ii) Allowable maintenance expenses include maintenance of the 
transportation system, maintenance of equipment, maintenance labor, and 
other directly allocable and attributable maintenance expenses that you 
can document.
    (iii) Overhead directly attributable and allocable to the operation 
and maintenance of the transportation system is an allowable expense. 
State and Federal income taxes and severance taxes and other fees, 
including royalties, are not allowable expenses.
    (iv) You may use either depreciation with a return on undepreciated 
capital investment or a return on depreciable capital investment. After 
you have elected to use either method for a transportation system, you 
may not later elect to change to the other alternative without MMS 
approval.
    (A) To compute depreciation, you may elect to use either a straight-
line depreciation method based on the life of equipment or on the life 
of the reserves that the transportation system services, or a unit of 
production method. Once you make an election, you may not change methods 
without MMS approval. A change in ownership of a transportation system 
will not alter the depreciation schedule that the original transporter/
lessee established for purposes of the allowance calculation. With or 
without a change in ownership, a transportation system may be 
depreciated only once. Equipment may not be depreciated below a 
reasonable salvage value. To compute a return on undepreciated capital 
investment, you will multiply the undepreciated capital investment in 
the transportation system by the rate of return determined under 
paragraph (b)(2)(v) of this section.
    (B) To compute a return on depreciable capital investment, you will 
multiply the initial capital investment in the transportation system by 
the rate of return determined under paragraph (b)(2)(v) of this section. 
No allowance will be provided for depreciation. This alternative will 
apply only to transportation facilities first placed in service after 
March 1, 1988.
    (v) The rate of return is the industrial rate associated with 
Standard and Poor's BBB rating. The rate of return is the monthly 
average rate as published in Standard and Poor's Bond Guide for the 
first month of the reporting period for which the allowance is 
applicable and is effective during the reporting period. The rate must 
be redetermined at the beginning of each subsequent transportation 
allowance reporting period that is determined under paragraph (b)(4) of 
this section.
    (3) This paragraph explains how to allocate transportation costs to 
each product and transportation system.
    (i) The deduction for transportation costs must be determined based 
on your cost of transporting each product through each individual 
transportation system. If you transport more than one product in a 
gaseous phase, the allocation of costs to each of the products 
transported must be made in a consistent and equitable manner. The 
allocation should be in the same proportion that the volume of each 
product (excluding waste products that have no value) bears to the 
volume of all products in the gaseous phase (excluding waste products 
that have no value). Except as provided in this paragraph, you may not 
take an allowance for transporting a product that is not royalty bearing 
without MMS approval.
    (ii) As an alternative to the requirements of paragraph (b)(3)(i) of 
this section, you may propose to MMS a cost allocation method based on 
the values of the products transported. MMS will approve the method upon 
determining that it meets one of the two following requirements:

[[Page 129]]

    (A) The methodology in paragraph (b)(3)(i) of this section cannot be 
applied; and
    (B) Your proposal is more reasonable than the method in paragraph 
(b)(3)(i) of this section.
    (4) Your transportation allowance under this paragraph (b) must be 
determined based upon a calendar year or other period if you and MMS 
agree to an alternative.
    (5) If you transport both gaseous and liquid products through the 
same transportation system, you must propose a cost allocation procedure 
to MMS. You may use the transportation allowance determined in 
accordance with your proposed allocation procedure until MMS issues its 
determination on the acceptability of the cost allocation. You are 
required to submit all relevant data to support your proposal. MMS will 
then determine the transportation allowance based upon your proposal and 
any additional information MMS deems necessary.
    (c) Using the alternative transportation calculation when you have a 
non-arm's-length or no contract. (1) As an alternative to computing your 
transportation allowance under paragraph (b) of this section, you may 
use as the transportation allowance 10 percent of your gross proceeds 
but not to exceed 30 cents per MMBtu.
    (2) Your election to use the alternative transportation allowance 
calculation in paragraph (c)(1) of this section must be made at the 
beginning of a month and must remain in effect for an entire calendar 
year. Your first election will remain in effect until the end of the 
succeeding calendar year, except for elections effective January 1 that 
will be effective only for that calendar year.
    (d) Reporting your transportation allowance. (1) If MMS requests, 
you must submit all data used to determine your transportation 
allowance. The data must be provided within a reasonable period of time 
that MMS will determine.
    (2) You must report transportation allowances as a separate entry on 
Form MMS-2014. MMS may approve a different reporting procedure on 
allottee leases, and with lessor approval on tribal leases.
    (e) Adjusting incorrect allowances. If for any month the 
transportation allowance you are entitled to is less than the amount you 
took on Form MMS-2014, you are required to report and pay additional 
royalties due, plus interest computed under 30 CFR 218.54 from the first 
day of the first month you deducted the improper transportation 
allowance until the date you pay the royalties due. If the 
transportation allowance you are entitled to is greater than the amount 
you took on Form MMS-2014 for any royalties during the reporting period, 
you are entitled to a credit. No interest will be paid on the 
overpayment.
    (f) Determining allowable costs for transportation allowances. 
Lessees may include, but are not limited to, the following costs in 
determining the arm's-length transportation allowance under paragraph 
(a) of this section or the non-arm's-length transportation allowance 
under paragraph (b) of this section:
    (1) Firm demand charges paid to pipelines. You must limit the 
allowable costs for the firm demand charges to the applicable rate per 
MMBtu multiplied by the actual volumes transported. You may not include 
any losses incurred for previously purchased but unused firm capacity. 
You also may not include any gains associated with releasing firm 
capacity. If you receive a payment or credit from the pipeline for 
penalty refunds, rate case refunds, or other reasons, you must reduce 
the firm demand charge claimed on the Form MMS-2014. You must modify the 
Form MMS-2014 by the amount received or credited for the affected 
reporting period.
    (2) Gas supply realignment (GSR) costs. The GSR costs result from a 
pipeline reforming or terminating supply contracts with producers to 
implement the restructuring requirements of FERC orders in 18 CFR part 
284.
    (3) Commodity charges. The commodity charge allows the pipeline to 
recover the costs of providing service.
    (4) Wheeling costs. Hub operators charge a wheeling cost for 
transporting gas from one pipeline to either the same or another 
pipeline through a market center or hub. A hub is a connected manifold 
of pipelines through

[[Page 130]]

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 the pipeline's curtailment or operational orders issued to 
protect the operational integrity of the pipeline.
    (4) Intra-hub transfer fees. These are fees you pay to hub operators 
for administrative services (e.g., title transfer tracking) necessary to 
account for the sale of gas within a hub.
    (5) Other nonallowable costs. Any cost you incur for services you 
are required to provide at no cost to the lessor.
    (h) Other transportation cost determinations. You must follow the 
provisions of this section to determine transportation costs when 
establishing value using either a net-back valuation procedure or any 
other procedure that allows deduction of actual transportation costs.

[64 FR 43515, Aug. 10, 1999, as amended at 73 FR 15891, Mar. 26, 2008]

                          Processing Allowances



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

[[Page 131]]

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.
    (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.

[[Page 132]]

    (3) If your arm's-length processing contract includes more than one 
gas plant product and the processing costs attributable to each product 
cannot be determined from the contract, you must propose an allocation 
procedure to MMS. You may use your proposed allocation procedure until 
MMS issues its determination. You are required to submit all relevant 
data to support your proposal. MMS will then determine the processing 
allowance based upon your proposal and any additional information MMS 
deems necessary. You may not take a processing allowance for the costs 
of processing lease production that is not royalty-bearing.
    (4) If your payments for processing under an arm's-length contract 
are not based on a dollar per unit price, you must convert whatever 
consideration is paid to a dollar value equivalent for the purposes of 
this section.
    (b) Determining a processing allowance if you have a non-arm's-
length contract or no contract. (1) This paragraph applies if you have a 
non-arm's-length processing contract or no contract, including those 
situations where you perform processing for yourself.
    (i) If you have a non-arm's-length contract or no contract, the 
processing allowance is based upon your reasonable actual costs of 
processing as provided in paragraph (b)(2) of this section.
    (ii) All processing allowances deducted under a non-arm's-length or 
no-contract situation are subject to monitoring, review, audit, and 
adjustment. You must submit the actual cost information to support the 
allowance to MMS on Form MMS-4109, Gas Processing Allowance Summary 
Report, within 3 months after the end of the 12-month period for which 
the allowance applies. MMS may approve a longer time period. MMS will 
monitor the allowance deduction to ensure that deductions are reasonable 
and allowable. When necessary or appropriate, MMS may require you to 
modify your processing allowance.
    (2) The processing allowance for non-arm's-length or no-contract 
situations is based upon your actual costs for processing during the 
reporting period. Allowable costs include operating and maintenance 
expenses, overhead, and either depreciation and a return on 
undepreciated capital investment (in accordance with paragraph 
(b)(2)(iv)(A) of this section), or a cost equal to the initial 
depreciable investment in the processing plant multiplied by a rate of 
return in accordance with paragraph (b)(2)(iv)(B) of this section. 
Allowable capital costs are generally those costs for depreciable fixed 
assets (including costs of delivery and installation of capital 
equipment) that are an integral part of the processing plant.
    (i) Allowable operating expenses include operations supervision and 
engineering, operations labor, fuel, utilities, materials, ad valorem 
property taxes, rent, supplies, and any other directly allocable and 
attributable operating expense that the lessee can document.
    (ii) Allowable maintenance expenses include maintenance of the 
processing plant, maintenance of equipment, maintenance labor, and other 
directly allocable and attributable maintenance expenses that you can 
document.
    (iii) Overhead directly attributable and allocable to the operation 
and maintenance of the processing plant is an allowable expense. State 
and Federal income taxes and severance taxes, including royalties, are 
not allowable expenses.
    (iv) You may use either depreciation with a return on undepreciable 
capital investment or a return on depreciable capital investment. After 
you elect to use either method for a processing plant, you may not later 
elect to change to the other alternative without MMS approval.
    (A) To compute depreciation, you may elect to use either a straight-
line depreciation method based on the life of equipment or on the life 
of the reserves that the processing plant services, or a unit-of-
production method. Once you make an election, you may not change methods 
without MMS approval. A change in ownership of a processing plant will 
not alter the depreciation schedule that the original processor/lessee 
established for purposes of the allowance calculation. However, for 
processing plants you or your affiliate purchase that do not have a 
previously claimed MMS depreciation schedule, you may treat the

[[Page 133]]

processing plant as a newly installed facility for depreciation 
purposes. A processing plant may be depreciated only once, regardless of 
whether there is a change in ownership. Equipment may not be depreciated 
below a reasonable salvage value. To compute a return on undepreciated 
capital investment, you must multiply the undepreciable capital 
investment in the processing plant by the rate of return determined 
under paragraph (b)(2)(v) of this section.
    (B) To compute a return on depreciable capital investment, you must 
multiply the initial capital investment in the processing plant by the 
rate of return determined under paragraph (b)(2)(v) of this section. No 
allowance will be provided for depreciation. This alternative will apply 
only to plants first placed in service after March 1, 1988.
    (v) The rate of return is the industrial rate associated with 
Standard and Poor's BBB rating. The rate of return is the monthly 
average rate as published in Standard and Poor's Bond Guide for the 
first month for which the allowance is applicable. The rate must be 
redetermined at the beginning of each subsequent calendar year.
    (3) Your processing allowance under this paragraph (b) must be 
determined based upon a calendar year or other period if you and MMS 
agree to an alternative.
    (4) The processing allowance for each gas plant product must be 
determined based on your reasonable and actual cost of processing the 
gas. You must base your allocation of costs to each gas plant product 
upon generally accepted accounting principles. You may not take an 
allowance for the costs of processing lease production that is not 
royalty-bearing.
    (c) Reporting your processing allowance. (1) If MMS requests, you 
must submit all data used to determine your processing allowance. The 
data must be provided within a reasonable period of time, as MMS 
determines.
    (2) You must report gas processing allowances as a separate entry on 
the Form MMS-2014. MMS may approve a different reporting procedure for 
allottee leases, and with lessor approval on tribal leases.
    (d) Adjusting incorrect processing allowances. If for any month the 
gas processing allowance you are entitled to is less than the amount you 
took on Form MMS-2014, you are required to pay additional royalties, 
plus interest computed under 30 CFR 218.54 from the first day of the 
first month you deducted a processing allowance until the date you pay 
the royalties due. If the processing allowance you are entitled is 
greater than the amount you took on Form MMS-2014, you are entitled to a 
credit. However, no interest will be paid on the overpayment.
    (e) Other processing cost determinations. You must follow the 
provisions of this section to determine processing costs when 
establishing value using either a net-back valuation procedure or any 
other procedure that requires deduction of actual processing costs.

[64 FR 43515, Aug. 10, 1999, as amended at 73 FR 15891, Mar. 26, 2008]



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

[[Page 134]]

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
    (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).

[[Page 135]]

    Contract means any oral or written agreement, including amendments 
or revisions thereto, between two or more persons and enforceable by law 
that with due consideration creates an obligation.
    Gross proceeds (for royalty payment purposes) means the total monies 
and other consideration accruing to a coal lessee for the production and 
disposition of the coal produced. Gross proceeds includes, but is not 
limited to, payments to the lessee for certain services such as 
crushing, sizing, screening, storing, mixing, loading, treatment with 
substances including chemicals or oils, and other preparation of the 
coal to the extent that the lessee is obligated to perform them at no 
cost to the Federal Government. Gross proceeds, as applied to coal, also 
includes but is not limited to reimbursements for royalties, taxes or 
fees, and other reimbursements. Tax reimbursements are part of the gross 
proceeds accruing to a lessee even though the Federal royalty interest 
may be exempt from taxation. Monies and other consideration, including 
the forms of consideration identified in this paragraph, to which a 
lessee is contractually or legally entitled but which it does not seek 
to collect through reasonable efforts are also part of gross proceeds.
    Lease means any contract, profit-share arrangement, joint venture, 
or other agreement issued or approved by the United States for a Federal 
coal resource under a mineral leasing law that authorizes exploration 
for, development or extraction of, or removal of coal--or the land 
covered by that authorization, whichever is required by the context.
    Lessee means any person to whom the United States issues a lease, 
and any person who has been assigned an obligation to make royalty or 
other payments required by the lease. This includes any person who has 
an interest in a lease as well as an operator or payor who has no 
interest in the lease but who has assumed the royalty payment 
responsibility.
    Like-quality coal means coal that has similar chemical and physical 
characteristics.
    Marketable condition means coal that is sufficiently free from 
impurities and otherwise in a condition that it will be accepted by a 
purchaser under a sales contract typical for that area.
    Mine means an underground or surface excavation or series of 
excavations and the surface or underground support facilities that 
contribute directly or indirectly to mining, production, preparation, 
and handling of lease products.
    Net-back method means a method for calculating market value of coal 
at the lease or mine. Under this method, costs of transportation, 
washing, handling, etc., are deducted from the ultimate proceeds 
received for the coal at the first point at which reasonable values for 
the coal may be determined by a sale pursuant to an arm's-length 
contract or by comparison to other sales of coal, to ascertain value at 
the mine.
    Net output means the quantity of washed coal that a washing plant 
produces.
    Netting is the deduction of an allowance from the sales value by 
reporting a one line net sales value, instead of correctly reporting the 
deduction as a separate line item on the Form MMS-4430.
    Person means by individual, firm, corporation, association, 
partnership, consortium, or joint venture.
    Sales type code means the contract type or general disposition 
(e.g., arm's-length or non-arm's-length) of production from the lease. 
The sales type code applies to the sales contract, or other disposition, 
and not to the arm's-length or non-arm's-length nature of a 
transportation or washing allowance.
    Spot market price means the price received under any sales 
transaction when planned or actual deliveries span a short period of 
time, usually not exceeding one year.

[54 FR 1523, Jan. 13, 1989, as amended at 55 FR 35433, Aug. 30, 1990; 61 
FR 5479, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999; 66 FR 45769, Aug. 
30, 2001; 73 FR 15891, Mar. 26, 2008]



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

[[Page 136]]

date, and approved OMB control numbers are identified in 30 CFR 210--
Forms and Reports.

[73 FR 15891, Mar. 26, 2008]



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 will 
be reported on appropriate forms required under 30 CFR part 210--Forms 
and Reports.

[54 FR 1523, Jan. 13, 1989, as amended at 57 FR 52720, Nov. 5, 1992; 66 
FR 45769, Aug. 30, 2001; 73 FR 15891, Mar. 26, 2008]



Sec. 206.255  Point of royalty determination.

    (a) For all leases subject to this subpart, royalty shall be 
computed on the basis of the quantity and quality of Federal coal in 
marketable condition measured at the point of royalty measurement as 
determined jointly by BLM and MMS.
    (b) Coal produced and added to stockpiles or inventory does not 
require payment of royalty until such coal is later used, sold, or 
otherwise finally disposed of. MMS may ask BLM to increase the lease 
bond to protect the lessor's interest when BLM determines that 
stockpiles or inventory become excessive so as to increase the risk of 
degradation of the resource.
    (c) The lessee shall pay royalty at a rate specified in the lease at 
the time the coal is used, sold, or otherwise finally disposed of, 
unless otherwise provided for at Sec. 206.256(d) of this subpart.

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



Sec. 206.256  Valuation standards for cents-per-ton leases.

    (a) This section is applicable to coal leases on Federal lands which 
provide for the determination of royalty on a cents-per-ton (or other 
quantity) basis.
    (b) The royalty for coal from leases subject to this section shall 
be based on the dollar rate per ton prescribed in the lease. That dollar 
rate shall be applicable to the actual quantity of coal used, sold, or 
otherwise finally disposed of, including coal which is avoidably lost as 
determine by BLM pursuant to 43 CFR part 3400.
    (c) For leases subject to this section, there shall be no allowances 
for transportation, removal of impurities, coal washing, or any other 
processing or preparation of the coal.
    (d) When a coal lease is readjusted pursuant to 43 CFR part 3400 and 
the royalty valuation method changes from a cents-per-ton basis to an ad 
valorem basis, coal which is produced

[[Page 137]]

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 to a contract which the lessee 
demonstrates, to MMS's satisfaction, were not part of the total 
consideration paid for the purchase of coal production.
    (c)(1) The value of coal from leases subject to this section and 
which is not sold pursuant to an arm's-length contract shall be 
determined in accordance with this section.
    (2) If the value of the coal cannot be determined pursuant to 
paragraph (b) of this section, then the value shall be determined 
through application of other valuation criteria. The criteria shall be 
considered in the following order, and the value shall be based upon the 
first applicable criterion:
    (i) The gross proceeds accruing to the lessee pursuant to a sale 
under its non-arm's-length contract (or other disposition of produced 
coal by other than an arm's-length contract), provided that those gross 
proceeds are within the range of the gross proceeds derived from, or 
paid under, comparable arm's-length contracts between buyers and sellers 
neither of whom is affiliated with the lessee for sales, purchases, or 
other dispositions of like-quality coal produced in the area. In 
evaluating the

[[Page 138]]

comparability of arm's-length contracts for the purposes of these 
regulations, the following factors shall be considered: Price, time of 
execution, duration, market or markets served, terms, quality of coal, 
quantity, and such other factors as may be appropriate to reflect the 
value of the coal;
    (ii) Prices reported for that coal to a public utility commission;
    (iii) Prices reported for that coal to the Energy Information 
Administration of the Department of Energy;
    (iv) Other relevant matters including, but not limited to, published 
or publicly available spot market prices, or information submitted by 
the lessee concerning circumstances unique to a particular lease 
operation or the saleability of certain types of coal;
    (v) If a reasonable value cannot be determined using paragraphs 
(c)(2) (i), (ii), (iii), or (iv) of this section, then a net-back method 
or any other reasonable method shall be used to determine value.
    (3) When the value of coal is determined pursuant to paragraph 
(c)(2) of this section, that value determination shall be consistent 
with the provisions contained in paragraph (b)(5) of this section.
    (d)(1) Where the value is determined pursuant to paragraph (c) of 
this section, that value does not require MMS's prior approval. However, 
the lessee shall retain all data relevant to the determination of 
royalty value. Such data shall be subject to review and audit, and MMS 
will direct a lessee to use a different value if it determines that the 
reported value is inconsistent with the requirements of these 
regulations.
    (2) Any Federal lessee will make available upon request to the 
authorized MMS or State representatives, to the Inspector General of the 
Department of the Interior or other persons authorized to receive such 
information, arm's-length sales value and sales quantity data for like-
quality coal sold, purchased, or otherwise obtained by the lessee from 
the area.
    (3) A lessee shall notify MMS if it has determined value pursuant to 
paragraphs (c)(2) (ii), (iii), (iv), or (v) of this section. The 
notification shall be by letter to the Associate Director for Minerals 
Revenue Management of his/her designee. The letter shall identify the 
valuation method to be used and contain a brief description of the 
procedure to be followed. The notification required by this section is a 
one-time notification due no later than the month the lessee first 
reports royalties on the Form MMS-4430 using a valuation method 
authorized by paragraphs (c)(2) (ii), (iii), (iv), or (v) of this 
section, and each time there is a change in a method under paragraphs 
(c)(2) (iv) or (v) of this section.
    (e) If MMS determines that a lessee has not properly determined 
value, the lessee shall be liable for the difference, if any, between 
royalty payments made based upon the value it has used and the royalty 
payments that are due based upon the value established by MMS. The 
lessee shall also be liable for interest computed pursuant to 30 CFR 
218.202. If the lessee is entitled to a credit, MMS will provide 
instructions for the taking of that credit.
    (f) The lessee may request a value determination from MMS. In that 
event, the lessee shall propose to MMS a value determination method, and 
may use that method in determining value for royalty purposes until MMS 
issues its decision. The lessee shall submit all available data relevant 
to its proposal. The MMS shall expeditiously determine the value based 
upon the lessee's proposal and any additional information MMS deems 
necessary. That determination shall remain effective for the period 
stated therein. After MMS issues its determination, the lessee shall 
make the adjustments in accordance with paragraph (e) of this section.
    (g) Notwithstanding any other provisions of this section, under no 
circumstances shall the value for royalty purposes be less than the 
gross proceeds accruing to the lessee for the disposition of produced 
coal less applicable provisions of paragraph (b)(5) of this section and 
less applicable allowances determined pursuant to 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

[[Page 139]]

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 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.

[[Page 140]]

The lessee shall have the burden of demonstrating that its contract is 
arm's-length. MMS' prior approval is not required before a lessee may 
deduct costs incurred under an arm's-length contract. The lessee must 
claim a washing allowance by reporting it as a separate line entry on 
the Form MMS-4430.
    (2) In conducting reviews and audits, MMS will examine whether the 
contract reflects more than the consideration actually transferred 
either directly or indirectly from the lessee to the washer for the 
washing. If the contract reflects more than the total consideration 
paid, then the MMS may require that the washing allowance be determined 
in accordance with paragraph (b) of this section.
    (3) If the MMS determines that the consideration paid pursuant to an 
arm's-length washing contract does not reflect the reasonable value of 
the washing because of misconduct by or between the contracting parties, 
or because the lessee otherwise has breached its duty to the lessor to 
market the production for the mutual benefit of the lessee and the 
lessor, then MMS shall require that the washing allowance be determined 
in accordance with paragraph (b) of this section. When MMS determines 
that the value of the washing may be unreasonable, MMS will notify the 
lessee and give the lessee an opportunity to provide written information 
justifying the lessee's washing costs.
    (4) Where the lessee's payments for washing under an arm's-length 
contract are not based on a dollar-per-unit basis, the lessee shall 
convert whatever consideration is paid to a dollar value equivalent. 
Washing allowances shall be expressed as a cost per ton of coal washed.
    (b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length contract or has no contract, including those situations 
where the lessee performs washing for itself, the washing allowance will 
be based upon the lessee's reasonable actual costs. All washing 
allowances deducted under a non-arm's-length or no contract situation 
are subject to monitoring, review, audit, and possible future 
adjustment. The lessee must claim a washing allowance by reporting it as 
a separate line entry on the Form MMS-4430. When necessary or 
appropriate, MMS may direct a lessee to modify its estimated or actual 
washing allowance.
    (2) The washing allowance for non-arm's-length or no contract 
situations shall be based upon the lessee's actual costs for washing 
during the reported period, including operating and maintenance 
expenses, overhead, and either depreciation and a return on 
undepreciated capital investment in accordance with paragraph (b)(2)(iv) 
(A) of this section, or a cost equal to the depreciable investment in 
the wash plant multiplied by the rate of return in accordance with 
paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are 
generally those for depreciable fixed assets (including costs of 
delivery and installation of capital equipment) which are an integral 
part of the wash plant.
    (i) Allowable operating expenses include: Operations supervision and 
engineering; operations labor; fuel; utilities; materials; ad valorem 
property taxes, rent; supplies; and any other directly allocable and 
attributable operating expense which the lessee can document.
    (ii) Allowable maintenance expenses include: Maintenance of the wash 
plant; maintenance of equipment; maintenance labor; and other directly 
allocable and attributable maintenance expenses which the lessee can 
document.
    (iii) Overhead attributable and allocable to the operation and 
maintenance of the wash plant is an allowable expense. State and Federal 
income taxes and severance taxes, including royalities, are not 
allowable expenses.
    (iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this 
section. After a lessee has elected to use either method for a wash 
plant, the lessee may not later elect to change to the other alternative 
without approval of the MMS.
    (A) To compute depreciation, the lessee may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the wash plant services, whichever is 
appropriate, or a unit of production method. After an election is

[[Page 141]]

made, the lessee may not change methods without MMS approval. A change 
in ownership of a wash plant shall not alter the depreciation schedule 
established by the original operator/lessee for purposes of the 
allowance calculation. With or without a change in ownership, a wash 
plant shall be depreciated only once. Equipment shall not be depreciated 
below a reasonable salvage value.
    (B) The MMS shall allow as a cost an amount equal to the allowable 
capital investment in the wash plant multiplied by the rate of return 
determined pursuant to paragraph (b)(2)(v) of this section. No allowance 
shall be provided for depreciation. This alternative shall apply only to 
plants first placed in service or acquired after March 1, 1989.
    (v) The rate of return must be the industrial rate associated with 
Standard and Poor's BBB rating. The rate of return must be the monthly 
average rate as published in Standard and Poor's Bond Guide for the 
first month for which the allowance is applicable. The rate must be 
redetermined at the beginning of each subsequent calendar year.
    (3) The washing allowance for coal shall be determined based on the 
lessee's reasonable and actual cost of washing the coal. The lessee may 
not take an allowance for the costs of washing lease production that is 
not royalty bearing.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) The 
lessee must notify MMS of an allowance based on incurred costs by using 
a separate line entry on the Form MMS-4430.
    (ii) The MMS may require that a lessee submit arm's-length washing 
contracts and related documents. Documents shall be submitted within a 
reasonable time, as determined by MMS.
    (2) Non-arm's-length or no contract. (i) The lessee must notify MMS 
of an allowance based on the incurred costs by using a separate line 
entry on the Form MMS-4430.
    (ii) For new washing facilities or arrangements, the lessee's 
initial washing deduction shall include estimates of the allowable coal 
washing costs for the applicable period. Cost estimates shall be based 
upon the most recently available operations data for the washing system 
or, if such data are not available, the lessee shall use estimates based 
upon industry data for similar washing systems.
    (iii) Upon request by MMS, the lessee shall submit all data used to 
prepare the allowance deduction. The data shall be provided within a 
reasonable period of time, as determined by MMS.
    (d) Interest and assessments. (1) If a lessee nets a washing 
allowance on the Form MMS-4430, then the lessee shall be assessed an 
amount up to 10 percent of the allowance netted not to exceed $250 per 
lease sales type code per sales period.
    (2) If a lessee erroneously reports a washing allowance which 
results in an underpayment of royalties, interest shall be paid on the 
amount of that underpayment.
    (3) Interest required to be paid by this section shall be determined 
in accordance with 30 CFR 218.202.
    (e) Adjustments. (1) If the actual coal washing allowance is less 
than the amount the lessee has taken on Form MMS-4430 for each month 
during the allowance reporting period, the lessee shall pay additional 
royalties due plus interest computed under 30 CFR 218.202 from the date 
when the lessee took the deduction to the date the lessee repays the 
difference to MMS. If the actual washing allowance is greater than the 
amount the lessee has taken on Form MMS-4430 for each month during the 
allowance reporting period, the lessee shall be entitled to a credit 
without interest.
    (2) The lessee must submit a corrected Form MMS-4430 to reflect 
actual costs, together with any payment, in accordance with instructions 
provided by MMS.
    (f) Other washing cost determinations. The provisions of this 
section shall apply to determine washing costs when establishing value 
using a net-back valuation procedure or any other procedure that 
requires deduction of washing costs.

[54 FR 1523, Jan. 13, 1989, as amended at 57 FR 52720, Nov. 5, 1992; 61 
FR 5480, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999; 66 FR 45769, Aug. 
30, 2001; 73 FR 15891, Mar. 26, 2008]

[[Page 142]]



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]



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

[[Page 143]]

does not reflect the reasonable value of the transportation because of 
misconduct by or between the contracting parties, or because the lessee 
otherwise has breached its duty to the lessor to market the production 
for the mutual benefit of the lessee and the lessor, then MMS shall 
require that the transportation allowance be determined in accordance 
with paragraph (b) of this section. When MMS determines that the value 
of the transportation may be unreasonable, MMS will notify the lessee 
and give the lessee an opportunity to provide written information 
justifying the lessee's transportation costs.
    (4) Where the lessee's payments for transportation under an arm's-
length contract are not based on a dollar-per-unit basis, the lessee 
shall convert whatever consideration is paid to a dollar value 
equivalent for the purposes of this section.
    (b) Non-arm's-length or no contract--(1) If a lessee has a non-
arm's-length contract or has no contract, including those situations 
where the lessee performs transportation services for itself, the 
transportation allowance will be based upon the lessee's reasonable 
actual costs. All transportation allowances deducted under a non-arm's-
length or no contract situation are subject to monitoring, review, 
audit, and possible future adjustment. The lessee must claim a 
transportation allowance by reporting it as a separate line entry on the 
Form MMS-4430. When necessary or appropriate, MMS may direct a lessee to 
modify its estimated or actual transportation allowance deduction.
    (2) The transportation allowance for non-arm's-length or no-contract 
situations shall be based upon the lessee's actual costs for 
transportation during the reporting period, including operating and 
maintenance expenses, overhead, and either depreciation and a return on 
undepreciated capital investment in accordance with paragraph 
(b)(2)(iv)(A) of this section, or a cost equal to the depreciable 
investment in the transportation system multiplied by the rate of return 
in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable 
capital costs are generally those for depreciable fixed assets 
(including costs of delivery and installation of capital equipment) 
which are an integral part of the transportation system.
    (i) Allowable operating expenses include: Operations supervision and 
engineering; operations labor; fuel; utilities; materials; ad valorem 
property taxes; rent; supplies; and any other directly allocable and 
attributable operating expense which the lessee can document.
    (ii) Allowable maintenance expenses include: Maintenance of the 
transportation system; maintenance of equipment; maintenance labor; and 
other directly allocable and attributable maintenance expenses which the 
lessee can document.
    (iii) Overhead attributable and allocable to the operation and 
maintenance of the transportation system is an allowable expense. State 
and Federal income taxes and severance taxes and other fees, including 
royalties, are not allowable expenses.
    (iv) A lessee may use either paragraph (b)(2)(iv)(A) or paragraph 
(b)(2)(iv)(B) of this section. After a lessee has elected to use either 
method for a transportation system, the lessee may not later elect to 
change to the other alternative without approval of the MMS.
    (A) To compute depreciation, the lessee may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the transportation system services, 
whichever is appropriate, or a unit of production method. After an 
election is made, the lessee may not change methods without MMS 
approval. A change in ownership of a transportation system shall not 
alter the depreciation schedule established by the original transporter/
lessee for purposes of the allowance calculation. With or without a 
change in ownership, a transportation system shall be depreciated only 
once. Equipment shall not be depreciated below a reasonable salvage 
value.
    (B) The MMS shall allow as a cost an amount equal to the allowable 
capital investment in the transportation system multiplied by the rate 
of return determined pursuant to paragraph (b)(2)(B)(v) of this section. 
No allowance shall be provided for depreciation.

[[Page 144]]

This alternative shall apply only to transportation facilities first 
placed in service or acquired after March 1, 1989.
    (v) The rate of return must be the industrial rate associated with 
Standard and Poor's BBB rating. The rate of return must be the monthly 
average rate as published in Standard and Poor's Bond Guide for the 
first month for which the allowance is applicable. The rate must be 
redetermined at the beginning of each subsequent calendar year.
    (3) A lessee may apply to MMS for exception from the requirement 
that it compute actual costs in accordance with paragraphs (b)(1) and 
(b)(2) of this section. MMS will grant the exception only if the lessee 
has a rate for the transportation approved by a Federal agency or by a 
State regulatory agency (for Federal leases). MMS shall deny the 
exception request if it determines that the rate is excessive as 
compared to arm's-length transportation charges by systems, owned by the 
lessee or others, providing similar transportation services in that 
area. If there are no arm's-length transportation charges, MMS shall 
deny the exception request if:
    (i) No Federal or State regulatory agency costs analysis exists and 
the Federal or State regulatory agency, as applicable, has declined to 
investigate under MMS timely objections upon filing; and
    (ii) The rate significantly exceeds the lessee's actual costs for 
transportation as determined under this section.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) The 
lessee must notify MMS of an allowance based on incurred costs by using 
a separate line entry on the Form MMS-4430.
    (ii) The MMS may require that a lessee submit arm's-length 
transportation contracts, production agreements, operating agreements, 
and related documents. Documents shall be submitted within a reasonable 
time, as determined by MMS.
    (2) Non-arm's-length or no contract--(i) The lessee must notify MMS 
of an allowance based on the incurred costs by using a separate line 
entry on Form MMS-4430.
    (ii) For new transportation facilities or arrangements, the lessee's 
initial deduction shall include estimates of the allowable coal 
transportation costs for the applicable period. Cost estimates shall be 
based upon the most recently available operations data for the 
transportation system or, if such data are not available, the lessee 
shall use estimates based upon industry data for similar transportation 
systems.
    (iii) Upon request by MMS, the lessee shall submit all data used to 
prepare the allowance deduction. The data shall be provided within a 
reasonable period of time, as determined by MMS.
    (iv) If the lessee is authorized to use its Federal- or State-
agency-approved rate as its transportation cost in accordance with 
paragraph (b)(3) of this section, it shall follow the reporting 
requirements of paragraph (c)(1) of this section.
    (d) Interest and assessments. (1) If a lessee nets a transportation 
allowance on Form MMS-4430, the lessee shall be assessed an amount of up 
to 10 percent of the allowance netted not to exceed $250 per lease sales 
type code per sales period.
    (2) If a lessee erroneously reports a transportation allowance which 
results in an underpayment of royalties, interest shall be paid on the 
amount of that underpayment.
    (3) Interest required to be paid by this section shall be determined 
in accordance with 30 CFR 218.202.
    (e) Adjustments. (1) If the actual coal transportation allowance is 
less than the amount the lessee has taken on Form MMS-4430 for each 
month during the allowance reporting period, the lessee shall pay 
additional royalties due plus interest computed under 30 CFR 218.202 
from the date when the lessee took the deduction to the date the lessee 
repays the difference to MMS. If the actual transportation allowance is 
greater than amount the lessee has taken on Form MMS-4430 for each month 
during the allowance reporting period, the lessee shall be entitled to a 
credit without interest.
    (2) The lessee must submit a corrected Form MMS-4430 to reflect 
actual costs, together with any payments, in accordance with 
instructions provided by MMS.
    (f) Other transportation cost determinations. The provisions of this 
section

[[Page 145]]

shall apply to determine transportation costs when establishing value 
using a net-back valuation procedure or any other procedure that 
requires deduction of transportation costs.

[54 FR 1523, Jan. 13, 1989, as amended at 57 FR 41864, Sept. 14, 1992; 
57 FR 52720, Nov. 5, 1992; 61 FR 5481, Feb. 12, 1996; 64 FR 43288, Aug. 
10, 1999; 66 FR 45769, Aug. 30, 2001; 73 FR 15891, Mar. 26, 2008]



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 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.

[[Page 146]]



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.
    (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

[[Page 147]]

would extract and produce by themselves because they are worth less than 
75 percent of the value of the geothermal steam or because extraction 
and production would be too difficult.
    Byproduct recovery facility means a facility where byproducts are 
placed in marketable condition.
    Byproduct transportation allowance means an allowance for the 
reasonable, actual costs of moving byproducts to a point of sale or 
delivery off the lease, unit area, or communitized area, or away from a 
byproduct recovery facility. The byproduct transportation allowance does 
not include gathering costs. You must report a byproduct transportation 
allowance as a separate discrete field on the Form MMS-2014.
    Class I lease means:
    (1) A lease that BLM issued before August 8, 2005, for which the 
lessee has not converted the royalty rate terms under 43 CFR 3212.25; or
    (2) A lease that BLM issued in response to an application that was 
pending on August 8, 2005, for which the lessee has not made an election 
under 43 CFR 3200.8(b).
    Class II lease means:
    A lease that BLM issued after August 8, 2005, except for a lease 
issued in response to an application that was pending on August 8, 2005, 
for which the lessee does not make an election under 43 CFR 3200.8(b).
    Class III lease means:
    A lease that BLM issued before August 8, 2005, for which the lessee 
has converted to the royalty rate or direct use fee terms under 43 CFR 
3212.25.
    Commercial production or generation of electricity means generation 
of electricity that is sold or is subject to sale, including the 
electricity or energy that is reasonably required to produce the 
resource used in production of electricity for sale or to convert 
geothermal energy into electrical energy for sale.
    Contract means any oral or written agreement, including amendments 
or revisions thereto, between two or more persons and enforceable by law 
that with due consideration creates an obligation.
    Deduction means a subtraction the lessee uses to determine the value 
of geothermal resources produced from a Class I lease that the lessee 
uses to generate electricity.
    Delivered electricity means the amount of electricity in kilowatt-
hours delivered to the purchaser.
    Direct use means the utilization of geothermal resources for 
commercial, residential, agricultural, public facilities, or other 
energy needs, other than the commercial production or generation of 
electricity.
    Direct use facility means a facility that uses the heat or other 
energy of the geothermal resource for direct use purposes.
    Electrical facility means a power plant or other facility that uses 
a geothermal resource to generate electricity.
    Field means the land surface vertically projected over a subsurface 
geothermal reservoir encompassing at least the outermost boundaries of 
all geothermal accumulations known to be within that reservoir. 
Geothermal fields are usually given names and their official boundaries 
are often designated by regulatory agencies in the respective States in 
which the fields are located.
    Gathering means the movement of lease production from the wellhead 
to the point of utilization.
    Generating deduction means a deduction for the lessee's reasonable, 
actual costs of generating plant tailgate electricity.
    Geothermal resources means:
    (1) All products of geothermal processes, including indigenous 
steam, hot water, and hot brines;
    (2) Steam and other gases, hot water, and hot brines resulting from 
water, gas, or other fluids artificially introduced into geothermal 
formations;
    (3) Heat or other associated energy found in geothermal formations; 
and
    (4) Any byproducts.
    Gross proceeds (for royalty payment purposes) means the total monies 
and other consideration accruing to a geothermal lessee for the sale of 
electricity or geothermal resource. Gross proceeds includes, but is not 
limited to:
    (1) Payments to the lessee for certain services such as effluent 
injection, field operation and maintenance, drilling or workover of 
wells, or field gathering to the extent that the lessee is obligated

[[Page 148]]

to perform such functions at no cost to the Federal Government;
    (2) Reimbursements for production taxes and other taxes. Tax 
reimbursements are part of gross proceeds accruing to a lessee even 
though the Federal royalty interest may be exempt from taxation; and
    (3) Any monies and other consideration, including the forms of 
consideration identified in this paragraph, to which a lessee is 
contractually or legally entitled but which it does not seek to collect 
through reasonable efforts.
    Lease means a geothermal lease issued under the authority of the 
GSA, unless the context indicates otherwise.
    Lessee (you) means any person to whom the United States issues a 
geothermal lease, and any person who has been assigned an obligation to 
make royalty, fee, or other payments required by the lease. This 
includes any person who has an interest in a geothermal lease as well as 
an operator or payor who has no interest in the lease but who has 
assumed the royalty, fee, or other payment responsibility. This also 
includes any affiliate of the lessee that uses the geothermal resource 
to generate electricity, in a direct use process, or to recover 
byproducts, or any affiliate that sells or transports lease production.
    Marketable condition means lease products that are sufficiently free 
from impurities and otherwise in a condition that they will be accepted 
by a purchaser under a sales contract typical for the disposition from 
the field or area of such lease products.
    Person means any individual, firm, corporation, association, 
partnership, consortium, or joint venture (when established as a 
separate entity).
    Plant parasitic electricity means electricity used to operate a 
power plant that is used for commercial production or generation of 
electricity.
    Plant tailgate electricity means the amount of electricity in 
kilowatt-hours generated by a power plant exclusive of plant parasitic 
electricity, but inclusive of any electricity generated by the power 
plant and returned to the lease for lease operations. Plant tailgate 
electricity should be measured at, or calculated for, the high voltage 
side of the transformer in the plant switchyard.
    Point of utilization means the power plant or direct use facility in 
which the geothermal resource is utilized.
    Public purpose means a program carried out by a State, tribal, or 
local government for the purpose of providing facilities or services for 
the benefit of the public in connection with, but not limited to, public 
health, safety or welfare, other than the commercial generation of 
electricity. Use of lands or facilities for habitation, cultivation, 
trade or manufacturing is permissible only when necessary for and 
integral to (i.e., an essential part of) the public purpose.
    Public safety or welfare means a program carried out or promoted by 
a public agency for public purposes involving, directly or indirectly, 
protection, safety, and law enforcement activities, and the criminal 
justice system of a given political area. Public safety or welfare may 
include, but is not limited to, programs carried out by:
    (1) Public police departments;
    (2) Sheriffs' offices;
    (3) The courts;
    (4) Penal and correctional institutions (including juvenile 
facilities);
    (5) State and local civil defense organizations; and
    (6) Fire departments and rescue squads (including volunteer fire 
departments and rescue squads supported in whole or in part with public 
funds).
    Reasonable alternative fuel means a conventional fuel (such as coal, 
oil, gas, or wood) that would normally be used as a source of heat in 
direct use operations.
    Secretary means the Secretary of the Interior or any person duly 
authorized to exercise the powers vested in that office.
    Transmission deduction means a deduction for the lessee's reasonable 
actual costs incurred to wheel or transmit the electricity from the 
lessee's power plant to the purchaser's delivery point.
    Wheeling means the transmission of electricity from a power plant to 
the point of delivery.

[[Page 149]]



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 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

[[Page 150]]

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

[[Page 151]]

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.
    (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;

[[Page 152]]

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

[[Page 153]]

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 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:

[[Page 154]]



                                             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;
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

[[Page 155]]

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 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

[[Page 156]]

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;
    (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.

[[Page 157]]

    (d) Allowable operating expenses include:
    (1) Operations supervision and engineering;
    (2) Operations labor;
    (3) Fuel;
    (4) Utilities;
    (5) Materials;
    (6) Ad valorem property taxes;
    (7) Rent;
    (8) Supplies; and
    (9) Any other directly allocable and attributable operating expense 
that you can document.
    (e) Allowable maintenance expenses include:
    (1) Maintenance of the transportation system;
    (2) Maintenance of equipment;
    (3) Maintenance labor; and
    (4) Other directly allocable and attributable maintenance expenses 
that you can document.
    (f) Overhead directly attributable and allocable to the operation 
and maintenance of the transportation system is an allowable expense. 
State and Federal income taxes and severance taxes and other fees, 
including royalties, are not allowable expenses.
    (g) To compute costs associated with capital investment, a lessee 
may use either paragraphs (h) and (i) or paragraph (j) of this section. 
After a lessee has elected to use either method for a transportation 
system, the lessee may not later elect to change to the other 
alternative without MMS approval.
    (h)(1) To compute depreciation, you must use a straight-line 
depreciation method based on either the life of the equipment or the 
life of the geothermal project which the transportation system services. 
After you choose the basis for depreciation, you may not change that 
basis without MMS approval. You may not depreciate equipment below a 
reasonable salvage value.
    (2) A change in ownership of a transportation system does not alter 
the depreciation schedule established by the original lessee-owner for 
purposes of computing transportation costs.
    (3) With or without a change in ownership, you may depreciate a 
transportation system only once.
    (i) To calculate a return on undepreciated capital investment, 
multiply the remaining undepreciated capital balance as of the beginning 
of the period for which you are calculating the transportation allowance 
by the rate of return provided in paragraph (k) of this section.
    (j) To compute a return on capital investment in the transportation 
system, the allowed cost will be the amount equal to the allowable 
capital investment in the transportation system multiplied by the rate 
of return determined pursuant to paragraph (k) of this section. There is 
no allowance for depreciation.
    (k) The rate of return must be the industrial rate associated with 
Standard & Poor's BBB rating. The BBB rate must be the monthly average 
rate as published in Standard & Poor's Bond Guide for the first month 
for which the allowance is applicable. You must redetermine the rate at 
the beginning of each subsequent calendar year.
    (l)(1) For new transportation facilities or arrangements, base your 
initial deduction on estimates of allowable byproduct transportation 
costs for the applicable period. Use the most recently available 
operations data for the transportation system or, if such data are not 
available, use estimates based on data for similar transportation 
systems.
    (2) When actual cost information is available, you must amend your 
prior Form MMS-2014 reports to reflect actual byproduct transportation 
cost deductions for each month for which you reported and paid based on 
estimated byproduct transportation costs. You must pay any additional 
royalties due (together with interest computed under 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:

[[Page 158]]

    (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 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

[[Page 159]]

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 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

[[Page 160]]

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.
    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

[[Page 161]]

under common control with another person. For purposes of this subpart, 
based on the instruments of ownership of the voting securities of an 
entity, or based on other forms of ownership: ownership in excess of 50 
percent constitutes control; ownership of 10 through 50 percent creates 
a presumption of control; and ownership of less than 10 percent creates 
a presumption of noncontrol which MMS may rebut if it demonstrates 
actual or legal control, including the existence of interlocking 
directorates. Notwithstanding any other provisions of this subpart, 
contracts between relatives, either by blood or by marriage, are not 
arm's-length contracts. MMS may require the lessee to certify ownership 
control. To be considered arm's-length for any production month, a 
contract must meet the requirements of this definition for that 
production month, as well as when the contract was executed.
    Audit means a review, conducted in accordance with generally 
accepted accounting and auditing standards, of royalty payment 
compliance activities of lessees or other interest holders who pay 
royalties, rents, or bonuses on Indian leases.
    BIA means the Bureau of Indian Affairs of the Department of the 
Interior.
    BLM means the Bureau of Land Management of the Department of the 
Interior.
    Coal means coal of all ranks from lignite through anthracite.
    Coal washing means any treatment to remove impurities from coal. 
Coal washing may include, but is not limited to, operations such as 
flotation, air, water, or heavy media separation; drying; and related 
handling (or combination thereof).
    Contract means any oral or written agreement, including amendments 
or revisions thereto, between two or more persons and enforceable by law 
that with due consideration creates an obligation.
    Gross proceeds (for royalty payment purposes) means the total monies 
and other consideration accruing to a coal lessee for the production and 
disposition of the coal produced. Gross proceeds includes, but is not 
limited to, payments to the lessee for certain services such as 
crushing, sizing, screening, storing, mixing, loading, treatment with 
substances including chemicals or oils, and other preparation of the 
coal to the extent that the lessee is obligated to perform them at no 
cost to the Indian lessor. Gross proceeds, as applied to coal, also 
includes but is not limited to reimbursements for royalties, taxes or 
fees, and other reimbursements. Tax reimbursements are part of the gross 
proceeds accruing to a lessee even though the Indian royalty interest 
may be exempt from taxation. Monies and other consideration, including 
the forms of consideration identified in this paragraph, to which a 
lessee is contractually or legally entitled but which it does not seek 
to collect through reasonable efforts are also part of gross proceeds.
    Indian allottee means any Indian for whom land or an interest in 
land is held in trust by the United States or who holds title subject to 
Federal restriction against alienation.
    Indian Tribe means any Indian Tribe, band, nation, pueblo, 
community, rancheria, colony, or other group of Indians for which any 
land or interest in land is held in trust by the United States or which 
is subject to Federal restriction against alienation.
    Lease means any contract, profit-share arrangement, joint venture, 
or other agreement issued or approved by the United States for an Indian 
coal resource under a mineral leasing law that authorizes exploration 
for, development or extraction of, or removal of coal--or the land 
covered by that authorization, whichever is required by the context.
    Lessee means any person to whom the Indian Tribe or an Indian 
allottee issues a lease, and any person who has been assigned an 
obligation to make royalty or other payments required by the lease. This 
includes any person who has an interest in a lease as well as an 
operator or payor who has no interest in the lease but who has assumed 
the royalty payment responsibility.
    Like-quality coal means coal that has similar chemical and physical 
characteristics.
    Marketable condition means coal that is sufficiently free from 
impurities and otherwise in a condition that it will be

[[Page 162]]

accepted by a purchaser under a sales contract typical for that area.
    Mine means an underground or surface excavation or series of 
excavations and the surface or underground support facilities that 
contribute directly or indirectly to mining, production, preparation, 
and handling of lease products.
    MMS means the Minerals Management Service of the Department of the 
Interior.
    Net-back method means a method for calculating market value of coal 
at the lease or mine. Under this method, costs of transportation, 
washing, handling, etc., are deducted from the ultimate proceeds 
received for the coal at the first point at which reasonable values for 
the coal may be determined by a sale pursuant to an arm's-length 
contract or by comparison to other sales of coal, to ascertain value at 
the mine.
    Net output means the quantity of washed coal that a washing plant 
produces.
    Person means by individual, firm, corporation, association, 
partnership, consortium, or joint venture.
    Sales type code means the contract type or general disposition 
(e.g., arm's-length or non-arm's-length) of production from the lease. 
The sales type code applies to the sales contract, or other disposition, 
and not to the arm's-length or non-arm's-length nature of a 
transportation or washing allowance.
    Spot market price means the price received under any sales 
transaction when planned or actual deliveries span a short period of 
time, usually not exceeding one year.

[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999; 73 
FR 15891, Mar. 26, 2008]



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 (of 2,000 pounds 
each) by methods prescribed by the BLM. Coal quantity information will 
be reported on appropriate forms required under 30 CFR part 210--Forms 
and Reports.

[61 FR 5481, Feb. 12, 1996, as amended at 66 FR 45769, Aug. 30, 2001; 73 
FR 15892, Mar. 26, 2008]



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

[[Page 163]]

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 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

[[Page 164]]

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

[[Page 165]]

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 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

[[Page 166]]

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 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.

[[Page 167]]

MMS will monitor the allowance deduction to ensure that deductions are 
reasonable and allowable. When necessary or appropriate, MMS may direct 
a lessee to modify its actual washing allowance.
    (2) The washing allowance for non-arm's-length or no contract 
situations shall be based upon the lessee's actual costs for washing 
during the reported period, including operating and maintenance 
expenses, overhead, and either depreciation and a return on 
undepreciated capital investment in accordance with paragraph 
(b)(2)(iv)(A) of this section, or a cost equal to the depreciable 
investment in the wash plant multiplied by the rate of return in 
accordance with paragraph (b)(2)(iv)(B) of this section. Allowable 
capital costs are generally those for depreciable fixed assets 
(including costs of delivery and installation of capital equipment) 
which are an integral part of the wash plant.
    (i) Allowable operating expenses include: Operations supervision and 
engineering; operations labor; fuel; utilities; materials; ad valorem 
property taxes; rent; supplies; and any other directly allocable and 
attributable operating expense which the lessee can document.
    (ii) Allowable maintenance expenses include: Maintenance of the wash 
plant; maintenance of equipment; maintenance labor; and other directly 
allocable and attributable maintenance expenses which the lessee can 
document.
    (iii) Overhead attributable and allocable to the operation and 
maintenance of the wash plant is an allowable expense. State and Federal 
income taxes and severance taxes, including royalties, are not allowable 
expenses.
    (iv) A lessee may use either paragraph (b)(2)(iv)(A) or 
(b)(2)(iv)(B) of this section. After a lessee has elected to use either 
method for a wash plant, the lessee may not later elect to change to the 
other alternative without approval of MMS.
    (A) To compute depreciation, the lessee may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the wash plant services, whichever is 
appropriate, or a unit of production method. After an election is made, 
the lessee may not change methods without MMS approval. A change in 
ownership of a wash plant shall not alter the depreciation schedule 
established by the original operator/lessee for purposes of the 
allowance calculation. With or without a change in ownership, a wash 
plant shall be depreciated only once. Equipment shall not be depreciated 
below a reasonable salvage value.
    (B) MMS shall allow as a cost an amount equal to the allowable 
capital investment in the wash plant multiplied by the rate of return 
determined pursuant to paragraph (b)(2)(v) of this section. No allowance 
shall be provided for depreciation. This alternative shall apply only to 
plants first placed in service or acquired after March 1, 1989.
    (v) The rate of return shall be the industrial rate associated with 
Standard and Poor's BBB rating. The rate of return shall be the monthly 
average rate as published in Standard and Poor's Bond Guide for the 
first month of the reporting period for which the allowance is 
applicable and shall be effective during the reporting period. The rate 
shall be redetermined at the beginning of each subsequent washing 
allowance reporting period (which is determined pursuant to paragraph 
(c)(2) of this section).
    (3) The washing allowance for coal shall be determined based on the 
lessee's reasonable and actual cost of washing the coal. The lessee may 
not take an allowance for the costs of washing lease production that is 
not royalty bearing.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) With the 
exception of those washing allowances specified in paragraphs (c)(1)(v) 
and (c)(1)(vi) of this section, the lessee shall submit page one of the 
initial Form MMS-4292 prior to, or at the same time, as the washing 
allowance determined pursuant to an arm's-length contract is reported on 
Form MMS-4430, Solid Minerals Production and Royalty Report. A Form MMS-
4292 received by the end of the month that the Form MMS-4430 is due 
shall be considered to be received timely.

[[Page 168]]

    (ii) The initial Form MMS-4292 shall be effective for a reporting 
period beginning the month that the lessee is first authorized to deduct 
a washing allowance and shall continue until the end of the calendar 
year, or until the applicable contract or rate terminates or is modified 
or amended, whichever is earlier.
    (iii) After the initial reporting period and for succeeding 
reporting periods, lessees must submit page one of Form MMS-4292 within 
3 months after the end of the calendar year, or after the applicable 
contract or rate terminates or is modified or amended, whichever is 
earlier, unless MMS approves a longer period (during which period the 
lessee shall continue to use the allowance from the previous reporting 
period).
    (iv) MMS may require that a lessee submit arm's-length washing 
contracts and related documents. Documents shall be submitted within a 
reasonable time, as determined by MMS.
    (v) Washing allowances which are based on arm's-length contracts and 
which are in effect at the time these regulations become effective will 
be allowed to continue until such allowances terminate. For the purposes 
of this section, only those allowances that have been approved by MMS in 
writing shall qualify as being in effect at the time these regulations 
become effective.
    (vi) MMS may establish, in appropriate circumstances, reporting 
requirements that are different from the requirements of this section.
    (2) Non-arm's-length or no contract. (i) With the exception of those 
washing allowances specified in paragraphs (c)(2)(v) and (c)(2)(vii) of 
this section, the lessee shall submit an initial Form MMS-4292 prior to, 
or at the same time as, the washing allowance determined pursuant to a 
non-arm's-length contract or no contract situation is reported on Form 
MMS-4430, Solid Minerals Production and Royalty Report. A Form MMS-4292 
received by the end of the month that the Form MMS-4430 is due shall be 
considered to be timely received. The initial reporting may be based on 
estimated costs.
    (ii) The initial Form MMS-4292 shall be effective for a reporting 
period beginning the month that the lessee first is authorized to deduct 
a washing allowance and shall continue until the end of the calendar 
year, or until the washing under the non-arm's-length contract or the no 
contract situation terminates, whichever is earlier.
    (iii) For calendar-year reporting periods succeeding the initial 
reporting period, the lessee shall submit a completed Form MMS-4292 
containing the actual costs for the previous reporting period. If coal 
washing is continuing, the lessee shall include on Form MMS-4292 its 
estimated costs for the next calendar year. The estimated coal washing 
allowance shall be based on the actual costs for the previous period 
plus or minus any adjustments which are based on the lessee's knowledge 
of decreases or increases which will affect the allowance. Form MMS-4292 
must be received by MMS within 3 months after the end of the previous 
reporting period, unless MMS approves a longer period (during which 
period the lessee shall continue to use the allowance from the previous 
reporting period).
    (iv) For new wash plants, the lessee's initial Form MMS-4292 shall 
include estimates of the allowable coal washing costs for the applicable 
period. Cost estimates shall be based upon the most recently available 
operations data for the plant, or if such data are not available, the 
lessee shall use estimates based upon industry data for similar coal 
wash plants.
    (v) Washing allowances based on non-arm's-length or no contract 
situations which are in effect at the time these regulations become 
effective will be allowed to continue until such allowances terminate. 
For the purposes of this section, only those allowances that have been 
approved by MMS in writing shall qualify as being in effect at the time 
these regulations become effective.
    (vi) Upon request by MMS, the lessee shall submit all data used by 
the lessee to prepare its Forms MMS-4292. The data shall be provided 
within a reasonable period of time, as determined by MMS.
    (vii) MMS may establish, in appropriate circumstances, reporting 
requirements which are different from the requirements of this section.

[[Page 169]]

    (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.



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

[[Page 170]]

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 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

[[Page 171]]

lessee. MMS will monitor the allowance deductions to ensure that 
deductions are reasonable and allowable. When necessary or appropriate, 
MMS may direct a lessee to modify its estimated or actual transportation 
allowance deduction.
    (2) The transportation allowance for non-arm's-length or no contract 
situations shall be based upon the lessee's actual costs for 
transportation during the reporting period, including operating and 
maintenance expenses, overhead, and either depreciation and a return on 
undepreciated capital investment in accordance with paragraph 
(b)(2)(iv)(A) of this section, or a cost equal to the depreciable 
investment in the transportation system multiplied by the rate of return 
in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable 
capital costs are generally those for depreciable fixed assets 
(including costs of delivery and installation of capital equipment) 
which are an integral part of the transportation system.
    (i) Allowable operating expenses include: Operations supervision and 
engineering; operations labor; fuel; utilities; materials; ad valorem 
property taxes; rent; supplies; and any other directly allocable and 
attributable operating expense which the lessee can document.
    (ii) Allowable maintenance expenses include: Maintenance of the 
transportation system; maintenance of equipment; maintenance labor; and 
other directly allocable and attributable maintenance expenses which the 
lessee can document.
    (iii) Overhead attributable and allocable to the operation and 
maintenance of the transportation system is an allowable expense. State 
and Federal income taxes and severance taxes and other fees, including 
royalties, are not allowable expenses.
    (iv) A lessee may use either paragraph (b)(2)(iv)(A) or paragraph 
(b)(2)(iv)(B) of this section. After a lessee has elected to use either 
method for a transportation system, the lessee may not later elect to 
change to the other alternative without approval of MMS.
    (A) To compute depreciation, the lessee may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the transportation system services, 
whichever is appropriate, or a unit of production method. After an 
election is made, the lessee may not change methods without MMS 
approval. A change in ownership of a transportation system shall not 
alter the depreciation schedule established by the original transporter/
lessee for purposes of the allowance calculation. With or without a 
change in ownership, a transportation system shall be depreciated only 
once. Equipment shall not be depreciated below a reasonable salvage 
value.
    (B) MMS shall allow as a cost an amount equal to the allowable 
capital investment in the transportation system multiplied by the rate 
of return determined pursuant to paragraph (b)(2)(B)(v) of this section. 
No allowance shall be provided for depreciation. This alternative shall 
apply only to transportation facilities first placed in service or 
acquired after March 1, 1989.
    (v) The rate of return shall be the industrial rate associated with 
Standard and Poor's BBB rating. The rate of return shall be the monthly 
average as published in Standard and Poor's Bond Guide for the first 
month of the reporting period of which the allowance is applicable and 
shall be effective during the reporting period. The rate shall be 
redetermined at the beginning of each subsequent transportation 
allowance reporting period (which is determined pursuant to paragraph 
(c)(2) of this section).
    (3) A lessee may apply to MMS for exception from the requirement 
that it compute actual costs in accordance with paragraphs (b)(1) and 
(b)(2) of this section. MMS will grant the exception only if the lessee 
has a rate for the transportation approved by a Federal agency for 
Indian leases. MMS shall deny the exception request if it determines 
that the rate is excessive as compared to arm's-length transportation 
charges by systems, owned by the lessee or others, providing similar 
transportation services in that area. If there are no arm's-length 
transportation charges, MMS shall deny the exception request if:

[[Page 172]]

    (i) No Federal regulatory agency cost analysis exists and the 
Federal regulatory agency has declined to investigate pursuant to MMS 
timely objections upon filing; and
    (ii) The rate significantly exceeds the lessee's actual costs for 
transportation as determined under this section.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) With the 
exception of those transportation allowances specified in paragraphs 
(c)(1)(v) and (c)(1)(vi) of this section, the lessee shall submit page 
one of the initial Form MMS-4293 prior to, or at the same time as, the 
transportation allowance determined pursuant to an arm's-length contract 
is reported on Form MMS-4430, Solid Minerals Production and Royalty 
Report.
    (ii) The initial Form MMS-4293 shall be effective for a reporting 
period beginning the month that the lessee is first authorized to deduct 
a transportation allowance and shall continue until the end of the 
calendar year, or until the applicable contract or rate terminates or is 
modified or amended, whichever is earlier.
    (iii) After the initial reporting period and for succeeding 
reporting periods, lessees must submit page one of Form MMS-4293 within 
3 months after the end of the calendar year, or after the applicable 
contract or rate terminates or is modified or amended, whichever is 
earlier, unless MMS approves a longer period (during which period the 
lessee shall continue to use the allowance from the previous reporting 
period). Lessees may request special reporting procedures in unique 
allowance reporting situations, such as those related to spot sales.
    (iv) MMS may require that a lessee submit arm's-length 
transportation contracts, production agreements, operating agreements, 
and related documents. Documents shall be submitted within a reasonable 
time, as determined by MMS.
    (v) Transportation allowances that are based on arm's-length 
contracts and which are in effect at the time these regulations become 
effective will be allowed to continue until such allowances terminate. 
For the purposes of this section, only those allowances that have been 
approved by MMS in writing shall qualify as being in effect at the time 
these regulations become effective.
    (vi) MMS may establish, in appropriate circumstances, reporting 
requirements that are different from the requirements of this section.
    (2) Non-arm's-length or no contract. (i) With the exception of those 
transportation allowances specified in paragraphs (c)(2)(v) and 
(c)(2)(vii) of this section, the lessee shall submit an initial Form 
MMS-4293 prior to, or at the same time as, the transportation allowance 
determined pursuant to a non-arm's-length contract or no contract 
situation is reported on Form MMS-4430, Solid Minerals Production and 
Royalty Report. The initial report may be based on estimated costs.
    (ii) The initial Form MMS-4293 shall be effective for a reporting 
period beginning the month that the lessee first is authorized to deduct 
a transportation allowance and shall continue until the end of the 
calendar year, or until the transportation under the non-arm's-length 
contract or the no contract situation terminates, whichever is earlier.
    (iii) For calendar-year reporting periods succeeding the initial 
reporting period, the lessee shall submit a completed Form MMS-4293 
containing the actual costs for the previous reporting period. If the 
transportation is continuing, the lessee shall include on Form MMS-4293 
its estimated costs for the next calendar year. The estimated 
transportation allowance shall be based on the actual costs for the 
previous reporting period plus or minus any adjustments that are based 
on the lessee's knowledge of decreases or increases that will affect the 
allowance. Form MMS-4293 must be received by MMS within 3 months after 
the end of the previous reporting period, unless MMS approves a longer 
period (during which period the lessee shall continue to use the 
allowance from the previous reporting period).
    (iv) For new transportation facilities or arrangements, the lessee's 
initial Form MMS-4293 shall include estimates of the allowable 
transportation costs for the applicable period. Cost estimates shall be 
based upon the most recently available operations data for

[[Page 173]]

the transportation system, or, if such data are not available, the 
lessee shall use estimates based upon industry data for similar 
transportation systems.
    (v) Non-arm's-length contract or no contract-based transportation 
allowances that are in effect at the time these regulations become 
effective will be allowed to continue until such allowances terminate. 
For purposes of this section, only those allowances that have been 
approved by MMS in writing shall qualify as being in effect at the time 
these regulations become effective.
    (vi) Upon request by MMS, the lessee shall submit all data used to 
prepare its Form MMS-4293. The data shall be provided within a 
reasonable period of time, as determined by MMS.
    (vii) MMS may establish, in appropriate circumstances, reporting 
requirements that are different from the requirements of this section.
    (viii) If the lessee is authorized to use its Federal-agency-
approved rate as its transportation cost in accordance with paragraph 
(b)(3) of this section, it shall follow the reporting requirements of 
paragraph (c)(1) of this section.
    (3) MMS may establish reporting dates for individual lessees 
different than those specified in this paragraph in order to provide 
more effective administration. Lessees will be notified as to any change 
in their reporting period.
    (4) Transportation allowances must be reported as a separate line 
item on Form MMS-4430, unless MMS approves a different reporting 
procedure.
    (d) Interest assessments for incorrect or late reports and failure 
to report. (1) If a lessee deducts a transportation allowance on its 
Form MMS-4430 without complying with the requirements of this section, 
the lessee shall be liable for interest on the amount of such deduction 
until the requirements of this section are complied with. The lessee 
also shall repay the amount of any allowance which is disallowed by this 
section.
    (2) If a lessee erroneously reports a transportation allowance which 
results in an underpayment of royalties, interest shall be paid on the 
amount of that underpayment.
    (3) Interest required to be paid by this section shall be determined 
in accordance with 30 CFR 218.202.
    (e) Adjustments. (1) If the actual transportation allowance is less 
than the amount the lessee has taken on Form MMS-4430 for each month 
during the allowance form reporting period, the lessee shall be required 
to pay additional royalties due plus interest, computed pursuant to 30 
CFR 218.202, retroactive to the first month the lessee is authorized to 
deduct a transportation allowance. If the actual transportation 
allowance is greater than the amount the lessee has estimated and taken 
during the reporting period, the lessee shall be entitled to a credit, 
without interest.
    (2) The lessee must submit a corrected Form MMS-4430 to reflect 
actual costs, together with any payment, in accordance with instructions 
provided by MMS.
    (f) Other transportation cost determinations. The provisions of this 
section shall apply to determine transportation costs when establishing 
value using a net-back valuation procedure or any other procedure that 
requires deduction of transportation costs.

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



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

[[Page 174]]

with Sec. 206.456(h) of this subpart, the lessee shall notify MMS that 
such processing is occurring or will occur. The value of that production 
shall be determined as follows:
    (a) A value established for the feedstock coal in marketable 
condition by application of the provisions of Sec. 206.456(c)(2) (i) 
through (iv) of this subpart; or,
    (b) In the event that a value cannot be established in accordance 
with paragraph (a) of this section, then the value of production will be 
determined in accordance with Sec. 206.456(c)(2)(v) of this subpart and 
the value shall be the lessee's gross proceeds accruing from the 
disposition of the enhanced product, reduced by MMS-approved processing 
costs and procedures including a rate of return on investment equal to 
two times the Standard and Poor's BBB bond rate applicable under Sec. 
206.458(b)(2)(v) of this subpart.

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



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



                      Subpart A_General Provisions

Sec.
207.1 Required recordkeeping.
207.2 Definitions.
207.3 Contracts made pursuant to new form leases.
207.4 Contracts made pursuant to old form leases.
207.5 Contract and sales agreement retention.

Subpart B--Oil, Gas and OCS Sulfur, General [Reserved]

Subpart C--Federal and Indian Oil [Reserved]

Subpart D--Federal and Indian Gas [Reserved]

Subpart E--Solid Minerals, General [Reserved]

Subpart F--Coal [Reserved]

Subpart G--Other Solid Minerals [Reserved]

Subpart H--Geothermal Resources [Reserved]

Subpart I--OCS Sulfur [Reserved]

    Authority: 5 U.S.C. 301 et seq.; 25 U.S.C. 396 et seq.; 25 U.S.C. 
396a et seq.; 25 U.S.C. 2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 
351 et seq.; 30 U.S.C. 1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 
3716 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et 
seq.; and 43 U.S.C. 1801 et seq.

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



                      Subpart A_General Provisions



Sec. 207.1  Required recordkeeping.

    (a) The information collection and recordkeeping requirements 
contained in this part have been approved by OMB under 44 U.S.C. 3501 et 
seq. and assigned OMB Clearance Number 1010-0061. The information 
collected will be used to determine a proper transportation allowance 
for the cost of transporting royalty oil from the lease to a delivery 
point remote from the lease. The information is required in order to 
obtain a benefit and is collected in accordance with the Federal Oil and 
Gas Royalty Management Act of 1982, 30 U.S.C. 1701 et seq.
    (b) Public reporting burden is estimated to average 30 minutes per 
year for each record keeper to maintain copies of sales contracts, 
agreements, or other documents relevant to the valuation of production. 
Send any comments regarding this burden estimate or any other aspect of 
this requirement to the Information Collection Clearance Officer, 
Minerals Management Service, 381 Elden Street, Herndon, VA 22070, and to 
the Office of Information and Regulatory Affairs, Office of Management 
and Budget, Paperwork Reduction Project 1010-0061, Washington, DC 20503.

[57 FR 41864, Sept. 14, 1992, as amended at 58 FR 64901, Dec. 10, 1994]



Sec. 207.2  Definitions.

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

[[Page 175]]



Sec. 207.3  Contracts made pursuant to new form leases.

    On November 29, 1950 (15 FR 8585), a new lease form was adopted 
(Form 4-1158, 15 FR 8585) containing provisions whereby the lessee 
agrees that nothing in any contract or other arrangement made for the 
sale or disposal of oil, gas, natural gasoline, and other products of 
the leased land, shall be construed as modifying any of the provisions 
of the lease, including, but not limited to, provisions relating to gas 
waste, taking royalty-in-kind, and the method of computing royalties due 
as based on a minimum valuation and in accordance with the oil and gas 
valuation regulations. A contract or agreement pursuant to a lease 
containing such provisions may be made without obtaining prior approval 
of the United States as lessor, but must be retained as provided in 
Sec. 207.5 of this subpart.



Sec. 207.4  Contracts made pursuant to old form leases.

    (a) Old form leases are those containing provisions prohibiting 
sales or disposal of oil, gas, natural gasoline, and other products of 
the lease except in accordance with a contract or other arrangement 
approved by the Secretary of the Interior, or by the Director of the 
Minerals Management Service or his/her representative. A contract or 
agreement made pursuant to an old form lease may be made without 
obtaining approval if the contract or agreement contains either the 
substance of or is accompanied by the stipulation set forth in paragraph 
(b) of this section, signed by the seller (lessee or operator).
    (b) The stipulation, the substance of which must be included in the 
contract, or be made the subject matter of a separate instrument 
properly identifying the leases affected thereby, is as follows:

    It is hereby understood and agreed that nothing in the written 
contract or in any approval thereof shall be construed as affecting any 
of the relations between the United States and its lessee, particularly 
in matters of gas waste, taking royalty in kind, and the method of 
computing royalties due as based on a minimum valuation and in 
accordance with the terms and provisions of the oil and gas valuation 
regulations applicable to the lands covered by said contract.



Sec. 207.5  Contract and sales agreement retention.

    Copies of all sales contracts, posted price bulletins, etc., and 
copies of all agreements, other contracts, or other documents which are 
relevant to the valuation of production are to be maintained by the 
lessee and made available upon request during normal working hours to 
authorized MMS, State or Indian representatives, other MMS or BLM 
officials, auditors of the General Accounting Office, or other persons 
authorized to receive such documents, or shall be submitted to MMS 
within a reasonable period of time, as determined by MMS. Any oral sales 
arrangement negotiated by the lessee must be placed in written form and 
retained by the lessee. Records shall be retained in accordance with 30 
CFR part 212.

Subpart B--Oil, Gas, and OCS Sulfur, General [Reserved]

Subpart C--Federal and Indian Oil [Reserved]

Subpart D--Federal and Indian Gas [Reserved]

Subpart E--Solid Minerals, General [Reserved]

Subpart F--Coal [Reserved]

Subpart G--Other Solid Minerals [Reserved]

Subpart H--Geothermal Resources [Reserved]

Subpart I--OCS Sulfur [Reserved]



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



                       Subpart A_General Provisons

Sec.
208.1 General.
208.2 Definitions.
208.3 Information collection.
208.4 Royalty oil sales to eligible refiners.
208.5 Notice of royalty oil sale.
208.6 General application procedures.
208.7 Determination of eligibility.

[[Page 176]]

208.8 Transportation and delivery.
208.9 Agreements.
208.10 Notices.
208.11 Surety requirements.
208.12 Payment requirements.
208.13 Reporting requirements.
208.14 Civil and criminal penalties.
208.15 Audits.
208.16 How to appeal a contracting officer's decision that you receive.
208.17 Suspensions for national emergencies.

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

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



                      Subpart A_General Provisions



Sec. 208.1  General.

    The regulations in this part govern the sale of royalty oil by the 
United States to eligible refiners. The regulations apply to royalty oil 
from leases on Federal lands onshore and on the Outer Continental Shelf 
(OCS).



Sec. 208.2  Definitions.

    Allotment means the quantity of royalty oil that DOI determines is 
available to each eligible refiner that has applied for a portion of the 
total volume of royalty oil offered in a given royalty oil sale.
    Application means the formal written request to DOI on Form MMS-4070 
by an eligible refiner interested in purchasing a quantity of royalty 
oil from the approximate volume announced by DOI in a given ``Notice of 
Availability of Royalty Oil.''
    Area or Region means the geographic territory having Federal oil and 
gas leases over which MMS has jurisdiction, unless the context in which 
those words are used indicates that a different meaning is intended.
    Contracting officer means the Director, his or her delegate, or the 
person designated under a royalty oil purchase contract.
    Contracting officer's decision means an MMS order or decision that a 
contracting officer issues under this part to a purchaser of oil under a 
royalty oil purchase contract.
    Delivery point means the point where the lessor, in accordance with 
lease terms, directs the lessee to deliver royalty oil to a purchaser. 
Title to the royalty oil, or to the quantity thereof in a commingled 
stream, passes from the Federal Government to the purchaser at this 
designated point, which is specified in the royalty oil contract. For 
onshore leases, the delivery point will be on or adjacent to the lease, 
except as provided in Sec. 208.8(a) of this part. In instances where an 
onshore delivery point is designated for offshore royalty oil, such 
point generally will be the first onshore point where the price of the 
oil, including transportation costs, can be determined and where the 
purchaser can either exchange or take delivery of the oil. The 
Government does not guarantee physical access to the oil at such point.
    Director means the Director of MMS, who is responsible for its 
overall direction, or his or her delegate(s).
    DOI means the Department of the Interior, including the Secretary or 
his or her delegate(s).
    Eligible refiner means a refiner of crude oil that meets the 
following criteria for eligibility to purchase royalty oil:
    (1) For the purchase of royalty oil from onshore leases, it means a 
refiner that qualifies as a small and independent refiner as those terms 
are defined in sections 3(3) and 3(4) of the Emergency Petroleum 
Allocation Act, 15 U.S.C. 751 et seq., except that the time period for 
determination contained in section 3(3)(A) would be the calendar quarter 
immediately preceding the date of the applicable ``Notice of 
Availability of Royalty Oil.'' A refiner that, together with all persons 
controlled by, in control of, under common control with, or otherwise 
affiliated with the refiner, inputs a volume of domestic crude oil from 
its own production exceeding 30 percent of its total refinery input of 
crude oil is ineligible to participate in royalty oil sales under this 
part. Crude oil received in exchange for such refiner's own production 
is considered to be that refiner's own production for purposes of this 
section.
    (2) For the purchase of royalty oil from leases on the OCS, it means 
a refiner that qualifies as a small business enterprise under the rules 
of the Small

[[Page 177]]

Business Administration (13 CFR part 121).
    Entitlement means the volume of royalty oil from the Federal 
Government's share of production from a Federal lease which a purchaser 
is entitled to receive under a royalty oil contract.
    Exchange agreement means a written agreement between the purchaser 
and another person for the exchange of royalty oil purchased under this 
part for other oil on a volume or equivalent value basis.
    Fair market value means the value of oil--(1) Computed at a unit 
price equivalent to the average unit price at which oil was sold 
pursuant to a lease during the period for which any royalty or net 
profit share is accrued or reserved to the United States pursuant to 
such lease, or
    (2) If there were no such sales, or if the Secretary finds that 
there were an insufficient number of such sales to equitably determine 
such value, computed at the average unit price at which oil was sold 
pursuant to other leases in the same region of the OCS during such 
period, or
    (3) If there were no sales of oil from such region during such 
period, or if the Secretary finds that there are an insufficient number 
of such sales to equitably determine such value, at an appropriate price 
determined by the Secretary.
    Federal lease means a contractual agreement with the Federal 
Government which authorizes the exploration, development, and production 
of oil and gas on Federal lands onshore or on the OCS.
    Interim sale means a sale conducted as a result of substantial 
additional royalty oil becoming available in a specific area prior to 
the scheduled expiration date of royalty oil contracts in effect for 
that area.
    Lessee means any person to whom the United States issues a lease, or 
any person who has been assigned an obligation to make royalty or other 
payments required by the lease.
    MMS means the Minerals Management Service of the Department of the 
Interior.
    Notice of Availability of Royalty Oil means a notice published by 
DOI in the Federal Register (and in other printed media when 
appropriate, such as a newspaper or magazine of general or specialized 
circulation) to advise interested parties of the availability of royalty 
oil for purchase by eligible refiners and the approximate volume of 
royalty oil available to the applicants.
    OCS means the Outer Continental Shelf, as defined in 43 U.S.C. 
1331(a).
    OCSLA means the Outer Continental Shelf Lands Act (43 U.S.C. 1331 et 
seq., as amended by 43 U.S.C. 1801 et seq.).
    Oil means a mixture of hydrocarbons that existed in the liquid phase 
in natural underground reservoirs and remains liquid at atmospheric 
pressure after passing through surface separating facilities and is 
marketed or used as such. Condensate recovered in lease separators or 
field facilities is considered to be oil.
    Operator means any person, including a lessee, who has control of or 
who manages operations on an oil and gas lease site on Federal onshore 
lands or on the OCS.
    Payor means any person responsible for reporting royalties from a 
Federal lease or leases on Form MMS-2014.
    Person means any individual, firm, corporation, association, 
partnership, consortium, or joint venture.
    Preference eligible refiner means an eligible refiner with at least 
one operating refinery which is located within the area designated as 
the preference eligible area in the ``Notice of Availability of Royalty 
Oil.'' A refiner may be deemed to be a preference eligible refiner if it 
owns a refinery located in the preference eligible area which is not 
operational if the refiner meets the requirements of Sec. 208.7(g) of 
this part.
    Purchaser means anyone who acquires royalty oil sold by DOI under 
the Federal Government's Royalty-in-Kind (RIK) Program and who has a 
contractual obligation under an agreement to purchase royalty oil.
    Reallocation means an offering of royalty oil previously allocated 
in a specific sale but subsequently turned back to MMS. A reallocation 
would only be made if substantial amounts of royalty oil are turned 
back.
    Refined petroleum product means gasoline, kerosene, distillates 
(including Number 2 fuel oil), refined lubricating oils, or diesel fuel.

[[Page 178]]

    Royalty oil means that amount of oil that DOI takes in kind in 
partial or full satisfaction of a lessee's royalty or net profit share 
obligations as determined by whatever lease interest the lessee holds 
under an applicable mineral leasing law.
    Secretary means the Secretary of the Department of the Interior or 
his/her delegate(s).
    Section 6 lease means an oil and gas lease originally issued by any 
State and currently maintained in effect pursuant to section 6 of the 
OCSLA.
    Section 8 lease means an oil and gas lease originally issued by the 
United States pursuant to section 8 of the OCSLA.

[52 FR 41913, Oct. 30, 1987; 52 FR 45528, Nov. 30, 1987, as amended at 
58 FR 64901, Dec. 10, 1993; 64 FR 26251, May 13, 1999]



Sec. 208.3  Information collection.

    The information collection requirements contained in this part have 
been approved by OMB under 44 U.S.C. 3501 et seq. The form, filing date, 
and approved OMB clearance number are identified in 30 CFR 210.10.

[58 FR 64901, Dec. 10, 1993]



Sec. 208.4  Royalty oil sales to eligible refiners.

    (a) Determination to take royalty oil in kind. The Secretary may 
evaluate crude oil market conditions from time to time. The evaluation 
will include, among other things, the availability of crude oil and the 
crude oil requirements of the Federal Government, primarily those 
requirements concerning matters of national interest and defense. The 
Secretary will review these items and will determine whether eligible 
refiners have access to adequate supplies of crude oil and whether such 
oil is available to eligible refiners at equitable prices. Such 
determinations may be made on a regional basis. The determination by the 
Secretary shall be published in the Federal Register concurrent with or 
included in the ``Notice of Availability of Royalty Oil'' required by 30 
CFR 208.5.
    (b) Sale to eligible refiners. (1) Upon a determination by the 
Secretary under paragraph (a) of this section that eligible refiners do 
not have access to adequate supplies of crude oil at equitable prices, 
the Secretary, at his or her discretion, may elect to take in kind some 
or all of the royalty oil accruing to the United States from oil and gas 
leases on Federal lands onshore and on the OCS. The Secretary may 
authorize MMS to offer royalty oil for sale to eligible refiners only 
for use in their refineries and not for resale (other than under an 
exchange agreement).
    (2) All sales of royalty oil from onshore leases will be priced at 
the royalty value that would have been determined for that oil pursuant 
to 30 CFR part 206 had the royalties been paid in value rather than 
taken in kind. All sales of royalty oil from OCS leases will be priced 
at the fair market value of the oil including associated transportation 
costs to the designated delivery point, if applicable.
    (3) An eligible refiner must have a representative at a sale in 
order to participate. The Secretary may, at his or her discretion, 
establish purchase limitations and withhold any royalty oil from any 
offering.
    (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]

[[Page 179]]



Sec. 208.5  Notice of royalty oil sale.

    If the Secretary decides to take royalty oil in kind for sale to 
eligible refiners, MMS will issue a ``Notice of Availability of Royalty 
Oil'' specifying the manner in which the sale is to be effected, the 
approximate quantity of royalty oil to be offered, information required 
in applications, the closing date for the receipt of applications for 
royalty oil, and other general administrative details concerning the 
application, allocation, and contract award process for the royalty oil. 
The Notice will describe generally the terms under which the royalty oil 
contracts will be awarded and will specify which applicants will be 
deemed preference eligible refiners in the sale proceedings. The Notice 
will also contain guidelines for reallocation procedures in the event 
substantial quantities of royalty oil sold in that specific sale are 
subsequently turned back to MMS. Only those purchasers that hold ongoing 
contracts from that specific sale will be allowed to participate in any 
reallocation, which would be voluntary, and then only if they continue 
to meet eligibility requirements as set forth in 30 CFR 208.2 and 208.7. 
If a reallocation is held prior to the effective date of the contracts 
as specified in the ``Notice of Availability of Royalty Oil'', all 
eligible refiners that selected a lease or leases in that specific sale 
would be allowed to participate, pursuant to the procedures in the 
Notice.



Sec. 208.6  General application procedures.

    (a) To apply for the purchase of royalty oil, an applicant must file 
a Form MMS-4070 with MMS in accordance with instructions provided in the 
``Notice of Availability of Royalty Oil'' and in accordance with any 
instructions issued by MMS for completion of Form MMS-4070. The 
applicant will be required to submit a letter of intent from a qualified 
financial institution stating that it would be granted surety coverage 
for the royalty oil for which it is applying, or other such proof of 
surety coverage, as deemed acceptable by MMS. The letter of intent must 
be submitted with a completed Form MMS-4070.
    (b) In addition to any other application requirements specified in 
the Notice, the following information is required on Form MMS-4070 at 
the time of application:
    (1) Name and address of the applicant, the location of the 
applicant's refinery or refineries, and disclosure of the applicant's 
affiliation with any other persons.
    (2) The capacity of the applicant's refineries in barrels of crude 
oil throughput per calendar day and a tabulation for the past 12 months 
of oil processed for each refinery, identified as to source (from own 
production or from other sources).
    (3) Identification of any Government royalty oil contracts under 
which the applicant is currently receiving royalty oil.
    (4) Identification of the locations (area/region and State) where 
the applicant proposes to purchase royalty 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

[[Page 180]]

given priority in the allocation procedures in sales and subsequent 
reallocations of royalty oil.
    (d) No eligible refiner shall be awarded contracts for volumes of 
royalty oil that, when added to volumes of other Federal royalty oil 
being received, are in excess of 60 percent of the combined refinery 
capacity of that refiner.
    (e) The MMS may exclude any section 6 lease from a royalty oil sale.
    (f) If two or more eligible refiners are related through common 
ownership or control or otherwise affiliated, only one of them shall be 
entitled to an allotment of royalty oil from a specific sale.
    (g) Any applicant whose refinery is not in operation during the 60-
day period prior to the date of the royalty oil sale shall not be 
entitled to participate in the sale unless such applicant self-certifies 
and demonstrates to the satisfaction of MMS that it will begin 
operations by the first month in which oil becomes available under a 
royalty oil contract. If operations do not begin by that month, MMS will 
terminate the contract.
    (h) Applicants or purchasers that have delinquent balances with MMS 
as of the date of a royalty oil sale or subsequent reallocation will not 
be allowed to participate in that sale or reallocation. If a person 
which is controlled by, in control of, under common control with, or 
otherwise affiliated with an applicant or purchaser has such delinquent 
balances, the applicant or purchaser will not be allowed to participate 
in a royalty oil sale or reallocation. To the extent a purchaser or 
affiliated person has appealed a billing and posted a surety instrument 
in accordance with the contract terms and applicable MMS regulations or 
other law, the balance shall not be considered delinquent.
    (i) A purchaser must meet the eligibility criteria on the date of 
contract issuance. However, a change in a purchaser's eligibility status 
during the term of the contract will not affect the purchaser's right to 
continue that contract until its term expires, including any extensions 
thereof.

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



Sec. 208.8  Transportation and delivery.

    (a) The lessee shall deliver royalty oil from onshore leases to the 
purchaser at a point on or adjacent to the lease pursuant to the terms 
of the lease. If the purchaser does not have access to its onshore 
royalty oil entitlement at facilities on or adjacent to the lease, the 
operator of the lease must designate an alternate delivery point at no 
additional cost to the purchaser or the Government. The purchaser must 
have physical access to the oil at the alternate delivery point and such 
point must be approved by MMS.
    (b) The lessee shall deliver royalty oil from section 8 offshore 
leases issued after September 1969 at a delivery point to be designated 
by MMS. The lessee shall deliver royalty oil from section 8 offshore 
leases issued before October 1969 or from section 6 leases at a delivery 
point to be designated by the 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

[[Page 181]]

connections or other facilities designated by MMS. If the lessee is 
unable to provide the royalty portion of actual production from the 
lease, the lessee must provide crude oil to the purchaser which is 
equivalent in volume or value to the royalty oil to which the purchaser 
is entitled. The lessee will deliver the royalty oil to the purchaser 
during normal operating hours and in reasonable quantities and 
intervals. The lessee will make available and the purchaser will accept 
delivery of the royalty oil entitlement no later than the last day of 
the calendar month immediately following the calendar month in which the 
oil was produced. Failure to accept deliveries shall constitute grounds 
for the termination of the contract.
    (d) Upon termination of deliveries under a royalty oil contract, the 
transportation allowance and delivery point designation authorized by 
this section no longer will remain in effect.



Sec. 208.9  Agreements.

    (a) A purchaser must submit to MMS two copies of any written third-
party agreements, or two copies of a full written explanation of any 
oral third-party agreements, relating to the method and costs of 
delivery of royalty oil, or crude oil exchanged for the royalty oil, 
from the point of delivery under the contract to the purchaser's 
refinery. In addition, the purchaser must submit copies of agreements 
pertaining to quality differentials which may occur between leases and 
delivery points.
    (b) A purchaser may not sell royalty oil which it purchases pursuant 
to this part except for purposes of an exchange for other crude oil on a 
volume or equivalent value basis.
    (c) Royalty oil purchased under this part, or crude oil received in 
exchange for such royalty oil, must be processed into refined petroleum 
products in the purchaser's refinery.



Sec. 208.10  Notices.

    (a) The MMS shall notify each operator, by certified mail, of the 
Secretary's decision to take royalty oil in kind. This notice shall be 
mailed at least 45 days in advance of the effective date of delivery and 
will specify delivery points for offshore oil for OCS leases issued 
after September 1969.
    (b) Deliveries of royalty oil may be partially terminated only with 
the written approval of the Director, MMS.
    (c) Before terminating the delivery of royalty oil taken in kind, 
MMS, if possible, will notify each operator by certified mail of the 
change in requirements at least 30 days in advance of the effective 
date.
    (d) After MMS notification that royalty oil will be taken in kind, 
the operator shall be responsible for notifying each working interest on 
the Federal lease. As soon as practicable after the date of each royalty 
oil sale, MMS will publish in the Federal Register a notice of the 
leases from which royalty oil will be taken, the purchasers of the 
royalty oil, and the leases from which royalty oil deliveries will be 
discontinued on terminated contracts.
    (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.

[[Page 182]]

    (b) If a letter of credit is furnished as the surety instrument, it 
must be effective for a 9-month period beginning the first day the 
royalty oil contract is effective, with a clause providing for automatic 
renewal monthly for a new 9-month period. The purchaser or its surety 
company may elect not to renew the letter of credit at any monthly 
anniversary date, but must notify MMS of its intent not to renew at 
least 30 days prior to the anniversary date. The MMS may grant the 
purchaser 45 days to obtain a new surety instrument. If no replacement 
surety instrument is provided, MMS will terminate the contract effective 
at least 6 months prior to the expiration date of the letter of credit. 
Notwithstanding the above provisions, the letter of credit also may 
contain a clause providing for automatic termination 6 months after the 
royalty oil contract terminates. If a certificate of deposit is 
furnished as the surety instrument, it must be effective for the life of 
the contract plus 6 months after the royalty oil contract terminates.
    (c) For the purposes of this section, an ``MMS-specified surety 
instrument'' means either: an MMS-specified surety bond, an MMS-
specified irrevocable letter of credit, or a financial institution book-
entry certificate of deposit.
    (d) The ``MMS-specified surety instrument'' shall be in a form 
specified by MMS instructions or approved by MMS. A bond must be issued 
by a qualified surety company that has been approved by the Department 
of the Treasury. An irrevocable letter of credit or a certificate of 
deposit must be from a financial institution acceptable to MMS. The MMS 
will use a bank rating service to determine whether a financial 
institution has an acceptable rating to provide a surety instrument 
deemed adequate to indemnify the Government from loss or damage.
    (e) All surety instruments must be in a form acceptable to MMS and 
must include such other specific requirements as MMS may require 
adequately to protect the Government's interests.

[58 FR 64901, Dec. 10, 1993]



Sec. 208.12  Payment requirements.

    (a) All payments to MMS by a purchaser of royalty oil will be due on 
the date and at the location specified in the contract, or, if there is 
no contractual provision, as specified by MMS. The purchaser shall 
tender all payments to MMS in accordance with 30 CFR 218.51. Payments 
made by a payor pursuant to the requirements of paragraph (b) of this 
section and Sec. 208.13 also shall be tendered in accordance with 30 
CFR 218.51.
    (b)(1) Payments from a purchaser of royalty oil not received by MMS 
when due, or that portion of the payment less than the full amount due, 
will be subject to a late payment charge equivalent to an interest 
assessment on the amount past due for the number of days that the 
payment is late at the underpayment rate applicable under section 6621 
of the Internal Revenue Code of 1954.
    (2) The MMS may assess interest to a payor for any underpayments 
which are the result of the payor's late or 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

[[Page 183]]

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

      Subpart B_Royalty Reports_Oil, Gas, and Geothermal Resources

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

                Subpart C_Production Reports_Oil and Gas

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

  Subpart D_Special-Purpose Forms and Reports_Oil, Gas, and Geothermal 
                                Resources

210.150 What is the purpose of this subpart?
210.151 What reports must I submit to claim an excess allowance?
210.152 What reports must I submit to claim allowances on an Indian 
          lease?
210.153 What reports must I submit for Indian gas valuation purposes?
210.154 What documents or other information must I submit for Federal 
          oil valuation purposes?

[[Page 184]]

210.155 What reports must I submit for Federal onshore stripper oil 
          properties?
210.156 What reports must I submit for net profit share leases?
210.157 What reports must I submit to suspend an MMS order under appeal?
210.158 What reports must I submit to designate someone to make my 
          royalty payments?

         Subpart E_Production and Royalty Reports_Solid Minerals

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

Subpart F--Coal [Reserved]

Subpart G--Other Solid Minerals [Reserved]

                     Subpart H_Geothermal Resources

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

Subpart I--OCS Sulfur [Reserved]

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



                      Subpart A_General Provisions

    Source: 73 FR 15892, Mar. 26, 2008, unless otherwise noted.



Sec. 210.01  What is the purpose of this subpart?

    This subpart identifies information collections required by the 
Minerals Management Service (MMS), Minerals Revenue Management (MRM), in 
the normal course of operations. This information is submitted by 
various parties associated with Federal and Indian leases such as 
lessees, designees, and operators. The information collected meets the 
MMS congressionally mandated accounting and auditing responsibilities 
relating to Federal and Indian minerals revenue management. Information 
collected regarding production, royalties, and other payments due the 
Government from activities on leased Federal or Indian land is 
authorized by the Federal Oil and Gas Royalty Management Act of 1982, as 
amended (30 U.S.C. 1701 et seq.), as well as 43 U.S.C. 1334 and 30 
U.S.C. 189, 359, 396, and 396d for oil and gas production; and by 30 
U.S.C. 189, 359, 396, and 396d for solid minerals production.



Sec. 210.02  To whom do these regulations apply?

    The regulations apply to any person, referred to in this subpart as 
``you,'' ``your,'' or ``reporter/payor,'' who is a lessee under any 
Federal or Indian lease for any mineral or who is assigned or assumes an 
obligation to report data or make payment to MMS. The term reporter/
payor may include lessees, designees, operators, purchasers, reporters, 
other payors, and working interest owners, but is not restricted to 
these parties. This section does not affect the liability to pay and 
report royalties as established by other regulations, laws, and the 
lease terms.



Sec. 210.10  What are the OMB-approved information collections?

    The information collection requirements identified in this subpart 
have been approved by the Office of Management and Budget (OMB) under 44 
U.S.C. 3501 et seq. Detailed information about each information 
collection request (ICR), including CFR citations, is included on the 
MMS Web site at http://www.mrm.mms.gov/Laws--R--D/FRNotices/
FRNotices.htm. The ICRs and associated MMS form numbers, if applicable, 
are listed below:

------------------------------------------------------------------------
   OMB control number and short title     Form or information collected
------------------------------------------------------------------------
1010-0073, 30 CFR Part 220, Net Profit   No form for the following
 Share Payment.                           collection:
                                          Net profit
                                          share payment information.

[[Page 185]]

 
1010-0087, 30 CFR Parts 227, 228, and    No forms for the following
 229, Delegation to States and            collections:
 Cooperative Activities with States and   Written
 Indian Tribes.                           delegation proposal to perform
                                          auditing and investigative
                                          activities.
                                          Request for
                                          cooperative agreement and
                                          subsequent requirements.
1010-0090, 30 CFR Part 216, Stripper     Form MMS-4377, Stripper Royalty
 Royalty Rate Reduction Notification.     Rate Reduction Notification.
1010-0103, 30 CFR Parts 202 and 206,     Form MMS-4109, Gas Processing
 Indian Oil and Gas Valuation.            Allowance Summary Report.
                                         Form MMS-4295, Gas
                                          Transportation Allowance
                                          Report.
                                         Form MMS-4110, Oil
                                          Transportation Allowance
                                          Report.
                                         Form MMS-4411, Safety Net
                                          Report.
                                         Form MMS-4410, Accounting for
                                          Comparison [Dual Accounting].
                                         Form MMS-4393, Request to
                                          Exceed Regulatory Allowance
                                          Limitation.\1\
1010-0107, 30 CFR Part 218, Collection   Form MMS-4425, Designation Form
 of Monies Due the Federal Government.    for Royalty Payment
                                          Responsibility.
                                         No forms for the following
                                          collections:
                                          Cross-lease
                                          netting documentation.
                                          Indian
                                          recoupment approval.
1010-0119, 30 CFR Part 208, Royalty in   Form MMS-4070, Application for
 Kind (RIK) Oil and Gas.                  the Purchase of Royalty Oil.
                                         Form MMS-4071, Letter of Credit
                                          (RIK).
                                         Form MMS-4072, Royalty-in-Kind
                                          Contract Surety Bond.
                                         No form for the following
                                          collection:
                                          Royalty oil
                                          sales to eligible refiners.
1010-0120, 30 CFR Parts 202, 206, 210,   Form MMS 4430, Solid Minerals
 212, 217, and 218, Solid Minerals and    Production and Royalty Report.
 Geothermal Collections.                 Form 4292, Coal Washing
                                          Allowance Report.
                                         Form 4293, Coal Transportation
                                          Allowance Report.
                                         No forms for the following
                                          collections:
                                          Facility
                                          data--solid minerals.
                                          Sales
                                          contracts--solid minerals.
                                          Sales
                                          summaries--solid minerals.
1010-0122, 30 CFR Part 243, Suspensions  Form MMS-4435, Administrative
 Pending Appeal and Bonding.              Appeal Bond.
                                         Form MMS-4436, Letter of
                                          Credit.
                                         Form MMS-4437, Assignment of
                                          Certificate of Deposit.
                                         No forms for the following
                                          collections:
                                          Self
                                          bonding.
                                          U.S.
                                          Treasury securities.
1010-0136, 30 CFR Parts 202 and 206,     Form MMS-4393, Request to
 Federal Oil and Gas Valuation.           Exceed Regulatory Allowance
                                          Limitation.\1\
                                         No form for the following
                                          collection:
                                          Federal oil
                                          valuation support information.
1010-0139, 30 CFR Parts 210 and 216,     Form MMS-4054 (Parts A, B, and
 Production Accounting.                   C), Oil and Gas Operations
                                          Report.
                                         Form MMS-4058, Production
                                          Allocation Schedule Report.
1010-0140, 30 CFR Part 210, Forms and    Form MMS-2014, Report of Sales
 Reports.                                 and Royalty Remittance.
1010-0155, 30 CFR Part 204,              No form for the following
 Alternatives for Marginal Properties.    collection:
                                          Notification
                                          and relief request for
                                          accounting and auditing
                                          relief.
1010-0162, CFO Act of 1992, Accounts     No form for the following
 Receivable Confirmations.                collection:
                                          Accounts
                                          receivable confirmations.
------------------------------------------------------------------------
\1\ Form MMS-4393 is used for both Federal and Indian oil and gas
  leases. The form resides with ICR 1010-0136, but the burden hours for
  Indian leases are included in ICR 1010-0103.


[73 FR 15892, Mar. 26, 2008, as amended at 73 FR 58875, Oct. 8, 2008]



Sec. 210.20  What if I disagree with the burden hour estimates?

    Burden hour estimates are included on the MMS Web site at http://
www.mrm.mms.gov/Laws--R--D/FRNotices/FRNotices.htm. Send comments on the 
accuracy of these burden estimates or suggestions on reducing the burden 
to the Minerals Management Service, Attention: Information Collection 
Clearance Officer (OMB Control Number 1010-XXXX [insert appropriate OMB 
control number]), Mail Stop 5438, 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.

[73 FR 15892, Mar. 26, 2008, as amended at 74 FR 46907, Sept. 14, 2009]

[[Page 186]]



Sec. 210.21  How do I report my taxpayer identification number?

    (a) Before paying or reporting to MMS, you must obtain a payor code 
(see the MMS Minerals Revenue Reporter Handbook, which is available on 
the Internet at http://www.mrm.mms.gov/ReportingServices/PDFDocs/
RevenueHandbook.pdf; also see Sec. 210.56 for further information on 
how to obtain a handbook). At the time you request a payor code, you 
must provide your Employer Identification Number (EIN) by submitting:
    (1) An IRS Form W-9; or
    (2) An equivalent certification containing:
    (i) Your name;
    (ii) The name of your business, if different from your name;
    (iii) The form of your business entity; for example, a sole 
proprietorship, corporation, or partnership;
    (iv) The address of your business;
    (v) The EIN of your business; and
    (vi) A signed and dated certification that you are a U.S. citizen or 
resident alien and that the EIN number provided is correct.
    (b) If you are already paying or reporting to MMS but do not have an 
EIN, MMS may request that you submit an IRS Form W-9 or equivalent 
certification containing the information required under paragraph (a)(2) 
of this section.
    (c) The collection of this data is not subject to the provisions of 
the Paperwork Reduction Act because only information necessary to 
identify the respondent [5 CFR 1320.3(h)] is required.
    (d) The EIN you provide to MMS under paragraph (a) of this section:
    (1) Means the taxpayer identification number (TIN) of an individual 
or other person (whether or not an employer), which is assigned under 26 
U.S.C. 6011(b), or a corresponding version of prior law, or under 26 
U.S.C. 6109;
    (2) Must contain nine digits separated by a hyphen as follows: 00-
0000000; and
    (3) May not be a Social Security Number.



Sec. 210.30  What are my responsibilities as a reporter/payor?

    Each reporter/payor must submit accurate, complete, and timely 
information to MMS according to the requirements in this part. If you 
discover an error in a previous report, you must file an accurate and 
complete amended report within 30 days of your discovery of the error. 
If you do not comply, MMS may assess civil penalties under 30 CFR part 
241.



Sec. 210.40  Will MMS keep the information I provide confidential?

    The MMS will treat information obtained under this part as 
confidential to the extent permitted by law as specified at 43 CFR part 
2.



      Subpart B_Royalty Reports_Oil, Gas, and Geothermal Resources

    Source: 73 FR 15892, Mar. 26, 2008, unless otherwise noted.



Sec. 210.50  What is the purpose of this subpart?

    The purpose of this subpart is to explain royalty reporting 
requirements when energy and mineral resources are removed from Federal 
and Indian oil and gas and geothermal leases and federally approved 
agreements. This includes leases and agreements located onshore and on 
the Outer Continental Shelf (OCS).



Sec. 210.51  Who must submit royalty reports?

    (a) Any person who pays royalty to MMS must submit royalty reports 
to MMS.
    (b) Before you pay or report to MMS, you must obtain a payor code. 
To obtain a payor code, refer to the MMS Minerals Revenue Reporter 
Handbook for instructions and MMS contact information (also see Sec. 
210.56 for information on how to obtain a handbook).



Sec. 210.52  What royalty reports must I submit?

    You must submit a completed Form MMS-2014, Report of Sales and 
Royalty Remittance, to MMS with:
    (a) All royalty payments; and
    (b) Rents on nonproducing leases, where specified in the lease.

[[Page 187]]



Sec. 210.53  When are my royalty reports and payments due?

    (a) Completed Forms MMS-2014 for royalty payments and the associated 
payments are due by the end of the month following the production month 
(see also Sec. 218.50).
    (b) Completed Forms MMS-2014 for rental payments, where applicable, 
and the associated payments are due as specified by the lease terms (see 
also Sec. 218.50).
    (c) You may submit reports and payments early.



Sec. 210.54  Must I submit this royalty report electronically?

    (a) You must submit Form MMS-2014 electronically unless you qualify 
for an exception under Sec. 210.55(a).
    (b) You must use one of the following electronic media types, unless 
MMS instructs you differently:
    (1) Electronic Data Interchange (EDI)--The direct computer-to-
computer interchange of data using standards set forth by the X12 
American National Standards Institute (ANSI) Accredited Standards 
Committee (ASC). The interchange uses the services of a third party with 
which either party may contract.
    (2) Web-based reporting--Reporters/payors may enter report data 
directly or upload files using the MMS electronic web form located at 
http://www.mrmreports.net. The uploaded files must be in one of the 
following formats: the American Standard Code for Information 
Interchange (ASCII) or Comma Separated Values (CSV) formats. External 
files created by the sender must be in the proprietary ASCII and CSV 
file layout formats defined by MMS. These external files can be 
generated from a reporter's system application.
    (c) Refer to our electronic reporting guidelines in the MMS Minerals 
Revenue Reporter Handbook, for the most current reporting options, 
instructions, and security measures. The handbook may be found on our 
Internet Web site or you may call your MMS customer service 
representative (see Sec. 210.56 for further information on how to 
obtain a handbook).



Sec. 210.55  May I submit this royalty report manually?

    (a) The MMS will allow you to submit Form MMS-2014 manually if:
    (1) You have never reported to MMS before. You have 3 months from 
the date your first report is due to begin reporting electronically;
    (2) You report only rent, minimum royalty, or other annual 
obligations on Form MMS-2014; or
    (3) You are a small business, as defined by the U.S. Small Business 
Administration, and you have no computer.
    (b) If you meet the qualifications under paragraph (a) of this 
section, you may submit your form manually to MMS by:
    (1) U.S. Postal Service regular or express mail addressed to 
Minerals Management Service, P.O. Box 5810, Denver, Colorado 80217-5810; 
or
    (2) Special courier or overnight mail addressed to Minerals 
Management Service, Building 85, Room A-614, Denver Federal Center, West 
6th Ave. and Kipling Blvd., Denver, Colorado 80225.



Sec. 210.56  Where can I find more information on how to complete the royalty report?

    (a) Specific guidance on how to prepare and submit Form MMS-2014 is 
contained in the MMS Minerals Revenue Reporter Handbook. The handbook is 
available on our Internet Web site at http://www.mrm.mms.gov/
ReportingServices/Handbooks/Handbks.htm or from MMS at P.O. Box 5760, 
Denver, Colorado 80217-5760.
    (b) Reporters/payors should refer to the handbook for specific 
guidance on royalty reporting requirements. If you require additional 
information, you should contact MMS at the above address. A customer 
service telephone number is also listed in our handbook.
    (c) You may find Form MMS-2014 on our Internet Web site at http://
www.mrm.mms.gov/ReportingServices/Forms/AFSOil--Gas.htm, or you may 
request the form from MMS at P.O. Box 5760, Denver, Colorado 80217-5760.



Sec. 210.60  What definitions apply to this subpart?

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

[[Page 188]]



                Subpart C_Production Reports_Oil and Gas

    Source: 73 FR 15892, Mar. 26, 2008, unless otherwise noted.



Sec. 210.100  What is the purpose of this subpart?

    The purpose of this subpart is to explain production reporting 
requirements when energy and mineral resources are removed from Federal 
and Indian oil and gas leases and federally approved agreements. This 
includes leases and unit and communitization agreements located onshore 
and on the Outer Continental Shelf (OCS).



Sec. 210.101  Who must submit production reports?

    (a) If you operate a Federal or Indian oil and gas lease or 
federally approved unit or communitization agreement, you must submit 
production reports.
    (b) Before reporting production to MMS, you must obtain an operator 
number. To obtain an operator number, refer to the MMS Minerals 
Production Reporter Handbook for instructions and MMS contact 
information (also see Sec. 210.106 for information on how to obtain a 
handbook).



Sec. 210.102  What production reports must I submit?

    (a) Form MMS-4054, Oil and Gas Operations Report. If you operate a 
Federal or Indian onshore or OCS oil and gas lease or federally approved 
unit or communitization agreement that contains one or more wells that 
are not permanently plugged or abandoned, you must submit Form MMS-4054 
to MMS:
    (1) You must submit Form MMS-4054 for each well for each calendar 
month, beginning with the month in which you complete drilling, unless:
    (i) You have only test production from a drilling well; or
    (ii) The MMS tells you in writing to report differently.
    (2) You must continue reporting until:
    (i) The Bureau of Land Management (BLM) or MMS approves all wells as 
permanently plugged or abandoned or the lease or unit or communitization 
agreement is terminated; and
    (ii) You dispose of all inventory.
    (b) Form MMS-4058, Production Allocation Schedule Report. If you 
operate an offshore facility measurement point (FMP) handling production 
from a Federal oil and gas lease or federally approved unit agreement 
that is commingled (with approval) with production from any other source 
prior to measurement for royalty determination, you must file Form MMS-
4058.
    (1) You must submit Form MMS-4058 for each calendar month beginning 
with the month in which you first handle production covered by this 
section.
    (2) Form MMS-4058 is not required whenever all of the following 
conditions are met:
    (i) All leases involved are Federal leases;
    (ii) All leases have the same fixed royalty rate;
    (iii) All leases are operated by the same operator;
    (iv) The facility measurement device is operated by the same person 
as the leases/agreements;
    (v) Production has not been previously measured for royalty 
determination; and
    (vi) The production is not subsequently commingled and measured for 
royalty determination at an FMP for which Form MMS-4058 is required 
under this part.



Sec. 210.103  When are my production reports due?

    (a) The MMS must receive your completed Forms MMS-4054 and MMS-4058 
by the 15th day of the second month following the month for which you 
are reporting.
    (b) A report is considered received when it is delivered to MMS by 4 
p.m. mountain time at the addresses specified in Sec. 210.105. Reports 
received after 4 p.m. mountain time are considered received the 
following business day.



Sec. 210.104  Must I submit these production reports electronically?

    (a) You must submit Forms MMS-4054 and MMS-4058 electronically 
unless you qualify for an exception under Sec. 210.105.
    (b) You must use one of the following electronic media types, unless 
MMS instructs you differently:

[[Page 189]]

    (1) Electronic Data Interchange (EDI)--The direct computer-to-
computer interchange of data using standards set forth by the X12 
American National Standards Institute (ANSI) Accredited Standards 
Committee (ASC). The interchange uses the services of a third party with 
which either party may contract.
    (2) Web-based reporting--Reporters/payors may enter report data 
directly or upload files using the MMS electronic Web form located at 
http://www.mrmreports.net. The uploaded files must be in one of the 
following formats: the American Standard Code for Information 
Interchange (ASCII) or Comma Separated Values (CSV) formats. External 
files created by the sender must be in the proprietary ASCII and CSV 
file layout formats defined by MMS. These external files can be 
generated from a reporter's system application.
    (c) Refer to our electronic reporting guidelines in the MMS Minerals 
Production Reporter Handbook for the most current reporting options, 
instructions, and security measures. The handbook may be found on our 
Internet Web site or you may call your MMS customer service 
representative (see Sec. 210.106 for further information on how to 
obtain a handbook).



Sec. 210.105  May I submit these production reports manually?

    (a) The MMS will allow you to submit Forms MMS-4054 and MMS-4058 
manually if:
    (1) You have never reported to MMS before. You have 3 months from 
the day your first report is due to begin reporting electronically; and
    (2) You are a small business, as defined by the U.S. Small Business 
Administration, and you have no computer.
    (b) If you meet the qualifications under paragraph (a) of this 
section, you may submit your forms manually to MMS by:
    (1) U.S. Postal Service regular or express mail addressed to 
Minerals Management Service, P.O. Box 17110, Denver, Colorado 80217-
0110; or
    (2) Special courier or overnight mail addressed to Minerals 
Management Service, Building 85, Room A-614, Denver Federal Center, West 
6th Ave. and Kipling Blvd., Denver, Colorado 80225.



Sec. 210.106  Where can I find more information on how to complete these production reports?

    (a) Specific guidance on how to prepare and submit production 
reports to MMS is contained in the MMS Minerals Production Reporter 
Handbook. The handbook is available on our Internet Web site at http://
www.mrm.mms.gov/ReportingServices/Handbooks/Handbks.htm or from MMS at 
P.O. Box 17110, Denver, Colorado 80217-0110.
    (b) Production reporters should refer to the handbook for specific 
guidance on production reporting requirements. If you require additional 
information, you should contact MMS at the above address. A customer 
service telephone number is also listed in our handbook.
    (c) You may find Forms MMS-4054 and MMS-4058 on our Internet Web 
site at http://www.mrm.mms.gov/ReportingServices/Forms/PAASOff.htm, or 
you may request the forms from MMS at P.O. Box 17110, Denver, Colorado 
80217-0110.



  Subpart D_Special-Purpose Forms and Reports_Oil, Gas, and Geothermal 
                                Resources

    Source: 73 FR 15892, Mar. 26, 2008, unless otherwise noted.



Sec. 210.150  What is the purpose of this subpart?

    This subpart identifies specific special-purpose reports and 
provides general information, reporting options, and reporting 
addresses. See Sec. 210.10 for a complete listing of all information 
collections, including forms and references for specific information 
collections.



Sec. 210.151  What reports must I submit to claim an excess allowance?

    (a) General. If you are a lessee, you must submit Form MMS-4393, 
Request to Exceed Regulatory Allowance Limitation, to request approval 
from MMS to exceed prescribed transportation and processing allowance 
limits on

[[Page 190]]

Federal oil and gas leases and prescribed transportation allowance 
limits on Indian oil and gas leases under part 206 of this chapter.
    (b) Reporting options. You may find Form MMS-4393 on our Web site at 
http://www.mrm.mms.gov/ReportingServices/Forms/AFSOil--Gas.htm. You may 
also request the form from MMS at P.O. Box 25165, MS 392B2, Denver, 
Colorado 80217-0165.
    (c) Reporting address. Submit completed Form MMS-4393 as follows:
    (1) Complete and submit the form electronically as an e-mail 
attachment;
    (2) Send the form by U.S. Postal Service regular or express mail 
addressed to Minerals Management Service, P.O. Box 25165, MS 392B2, 
Denver, Colorado 80217-0165; or
    (3) Deliver the form to MMS by special courier or overnight mail 
addressed to Minerals Management Service, Building 85, Room A-614, MS 
392B2, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, 
Colorado 80225.



Sec. 210.152  What reports must I submit to claim allowances on an Indian lease?

    (a) General. You must submit three additional forms to MMS to claim 
transportation or processing allowances on Indian oil and gas leases:
    (1) You must submit Form MMS-4110, Oil Transportation Allowance 
Report, to claim an allowance for expenses incurred by a reporter/payor 
to transport oil from the lease site to a point remote from the lease 
where value is determined under Sec. 206.55 of this chapter.
    (2) You must submit Form MMS-4109, Gas Processing Allowance Summary 
Report, to claim an allowance for the reasonable, actual costs of 
removing hydrocarbon and nonhydrocarbon elements or compounds from a gas 
stream under Sec. 206.180 of this chapter.
    (3) You must submit Form MMS-4295, Gas Transportation Allowance 
Report, to claim an allowance for the reasonable, actual costs of 
transporting gas from the lease to the point of first sale under Sec. 
206.178 of this chapter.
    (b) Reporting options. You may submit Forms MMS-4110, MMS-4109, and 
MMS-4295 manually. You may find the forms on our Internet Web site at 
http://www.mrm.mms.gov/ReportingServices/Forms/AFSOil--Gas.htm, or you 
may request the forms from MMS at P.O. Box 25165, MS 396B2, Denver, 
Colorado 80217-0165.
    (c) Reporting address. You may submit completed Forms MMS-4110, MMS-
4109, and MMS-4295 by:
    (1) U.S. Postal Service regular or express mail addressed to 
Minerals Management Service, P.O. Box 25165, MS 396B2, Denver, Colorado 
80217-0165; or
    (2) Special courier or overnight mail addressed to Minerals 
Management Service, Building 85, Room A-614, MS 396B2, Denver Federal 
Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.



Sec. 210.153  What reports must I submit for Indian gas valuation purposes?

    (a) General. For Indian gas valuation, under certain conditions 
under Sec. 206.172 of this chapter, lessees must submit the following 
forms:
    (1) Form MMS-4410, Accounting for Comparison (Dual Accounting), Part 
A or Part B; and/or
    (2) Form MMS-4411, Safety Net Report.
    (b) Reporting options. You must submit Forms MMS-4410 and MMS-4411 
manually. You may find the forms on our Internet Web site at http://
www.mrm.mms.gov/ReportingServices/Forms/AFSOil--Gas.htm or request forms 
from MMS at P.O. Box 25165, MS 396B2, Denver, Colorado 80217-0165.
    (c) Reporting address. You must submit completed Forms MMS-4410 and 
MMS-4411 by:
    (1) U.S. Postal Service regular or express mail addressed to 
Minerals Management Service, P.O. Box 25165, MS 396B2, Denver, Colorado 
80217-0165; or
    (2) Special courier or overnight mail addressed to Minerals 
Management Service, Building 85, Room A-614, MS 396B2, Denver Federal 
Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.



Sec. 210.154  What documents or other information must I submit for Federal oil valuation purposes?

    (a) General. The MMS may require you to submit documents or other 
information to MMS to support your

[[Page 191]]

valuation of Federal oil under part 206 as part of audit compliance.
    (b) Reporting options. You must submit the documents or other 
information manually.
    (c) Reporting address. You must submit required documents or other 
information by:
    (1) U.S. Postal Service regular or express mail addressed to 
Minerals Management Service, P.O. Box 25165, MS 392B2, Denver, Colorado 
80217-0165; or
    (2) Special courier or overnight mail addressed to Minerals 
Management Service, Building 85, Room A-614, MS 392B2, Denver Federal 
Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.



Sec. 210.155  What reports must I submit for Federal onshore stripper oil properties?

    (a) General. Operators who have been granted a reduced royalty rate 
by the Bureau of Land Management (BLM) under 43 CFR 3103.4-2 must submit 
Form MMS-4377, Stripper Royalty Rate Reduction Notification, under 43 
CFR 3103.4-2(b)(3).
    (b) Reporting options. You may find Form MMS-4377 on our Internet 
Web site at http://www.mrm.mms.gov/ReportingServices/Forms/AFSOil--
Gas.htm or request the form from MMS at P.O. Box 17110, Denver, Colorado 
80217-0110. You may file the form:
    (1) Electronically by filling the form out in electronic format and 
submitting it to MMS as an e-mail attachment; or
    (2) Manually by filling out the form and submitting it by:
    (i) U.S. Postal Service regular or express mail addressed to 
Minerals Management Service, P.O. Box 25165, MS 392B2, Denver, Colorado 
80217-0165; or
    (ii) Special courier or overnight mail addressed to Minerals 
Management Service, Building 85, Room A-614, MS 392B2, Denver Federal 
Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.



Sec. 210.156  What reports must I submit for net profit share leases?

    (a) General. After entering into a net profit share lease (NPSL) 
agreement, a lessee must report under part 220 of this chapter.
    (b) Reporting options. You must submit the required report manually.
    (c) Reporting address. You must submit the required documents by:
    (1) U.S. Postal Service regular or express mail addressed to 
Minerals Management Service, P.O. Box 25165, MS 382B2, Denver, Colorado 
80217-0165; or
    (2) Special courier or overnight mail addressed to Minerals 
Management Service, Building 85, Room A-614, MS 382B2, Denver Federal 
Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.



Sec. 210.157  What reports must I submit to suspend an MMS order under appeal?

    (a) General. Reporters/payors or other recipients of MMS Minerals 
Revenue Management (MRM) orders who appeal an order may be required to 
post a bond or other surety, under part 243 of this chapter. The MMS 
accepts the following surety types: Form MMS-4435, Administrative Appeal 
Bond; Form MMS-4436, Letter of Credit; Form MMS-4437, Assignment of 
Certificate of Deposit; Self-bonding; and U.S. Treasury Securities.
    (b) Reporting options. You must submit these forms and other 
documents manually. You may find the forms and other documents under 
Surety Instrument Posting Instructions on our Internet Web site at 
http://www.mrm.mms.gov/Law--R--D/FRNotices/ICR0122.htm.
    (c) Reporting address. You may submit the required forms and other 
documents as specified in the Surety Instrument Posting Instructions or 
by:
    (1) U.S. Postal Service regular or express mail addressed to 
Minerals Management Service, P.O. Box 25165, MS 370B2, Denver, Colorado 
80217-0165;
    (2) Special courier or overnight mail addressed to Minerals 
Management Service, Building 85, Room A-614, MS 370B2, Denver Federal 
Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.

[[Page 192]]



Sec. 210.158  What reports must I submit to designate someone to make my royalty payments?

    (a) General. You must submit Form MMS-4425, Designation Form for 
Royalty Payment Responsibility, if you want to designate a person to 
make royalty payments on your behalf under Sec. 218.52.
    (b) Reporting options. You must submit Form MMS-4425 manually. You 
may find the form on our Internet Web site at http://www.mrm.mms.gov/
ReportingServices/Forms/AFSOil--Gas.htm or request the form from MMS at 
P.O. Box 5760, Denver, Colorado 80217-5760.
    (c) Reporting address. You must submit completed Form MMS-4425 by:
    (1) U.S. Postal Service regular or express mail addressed to 
Minerals Management Service, P.O. Box 25165, MS 357B1, Denver, Colorado 
80217-0165; or
    (2) Special courier or overnight mail addressed to Minerals 
Management Service, Building 85, Room A-614, MS 357B1, Denver Federal 
Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.



         Subpart E_Production and Royalty Reports_Solid Minerals

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



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--
    (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

[[Page 193]]

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.
    (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.
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 194]]

    (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 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).

[[Page 195]]



Sec. 210.205  What reports must I submit to claim allowances on Indian coal leases?

    General. You must submit the following MMS forms to claim a 
transportation or washing allowance, as applicable, on Indian coal 
leases:
    (1) Form MMS-4292, Coal Washing Allowance Report, to claim an 
allowance for the reasonable, actual costs incurred to wash coal under 
Sec. 206.458 of this chapter.
    (2) Form MMS-4293, Coal Transportation Allowance Report, to claim an 
allowance for the reasonable, actual costs of transporting coal to a 
sales point or a washing facility remote from the mine or lease under 
Sec. 206.461 of this chapter.
    (b) Reporting options. You must submit the forms manually. You may 
find the forms on our Internet Web site at http://www.mrm.mms.gov/
ReportingServices/Forms/AFSSol--Min.htm or request forms from MMS at 
P.O. Box 25165, MS 390B2, Denver, Colorado 80217-0165.
    (c) Reporting address. You must submit completed Forms MMS-4292 and 
MMS-4293 by:
    (1) U.S. Postal Service regular or express mail addressed to 
Minerals Management Service, P.O. Box 25165, MS 390B2, Denver, Colorado 
80217-0165; or
    (2) Special courier or overnight mail addressed to Minerals 
Management Service, Building 85, Room A-614, MS 390B2, Denver Federal 
Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.

[73 FR 15897, Mar. 26, 2008]



Sec. 210.206  Will I need to submit additional documents or evidence to MMS?

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

[66 FR 45771, Aug. 30, 2001. Redesignated at 73 FR 15897, Mar. 26, 2008]



Sec. 210.207  How will information submissions be kept confidential?

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

[66 FR 45771, Aug. 30, 2001. Redesignated at 73 FR 15897, Mar. 26, 2008]

Subpart F--Coal [Reserved]

Subpart G--Other Solid Minerals [Reserved]



                     Subpart H_Geothermal Resources

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



Sec. 210.350  Definitions.

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



Sec. 210.351  Required recordkeeping.

    Information required by MMS shall be filed using the forms 
prescribed in this subpart, which are available from MMS. Records may be 
maintained on microfilm, microfiche, or other recorded media that are 
easily reproducible and readable. See subpart H of 30 CFR part 212.



Sec. 210.352  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]

[[Page 196]]



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 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).

[[Page 197]]

    (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]



                     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

[[Page 198]]

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 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 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.

[[Page 199]]



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.



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.

[[Page 200]]

Subpart H--Indian Lands [Reserved]



PART 218_COLLECTION OF MONIES AND PROVISION FOR GEOTHERMAL CREDITS AND INCENTIVES--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.

                     Subpart C_Oil and Gas, Onshore

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

                 Subpart D_Oil, Gas and Sulfur, Offshore

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

                    Subpart E_Solid Minerals_General

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

                     Subpart F_Geothermal Resources

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

Subpart G--Indian Lands [Reserved]

              Subpart H_Service of Official Correspondence

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

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

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



                      Subpart A_General Provisions



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 
for geothermal, solid minerals, and Indian oil and gas leases.
    (b) An assessment of an amount not to exceed $10 per day may be 
charged for each incorrectly completed report

[[Page 201]]

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

[49 FR 37346, Sept. 21, 1984. Redesignated and amended at 51 FR 15767, 
Apr. 28, 1986; 52 FR 27546, July 22, 1987; 52 FR 37452, Oct. 7, 1987; 57 
FR 52720, Nov. 5, 1992; 59 FR 38906, Aug. 1, 1994; 66 FR 45773, Aug. 30, 
2001; 73 FR 15897, Mar. 26, 2008]



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) The MMS may assess an amount not to exceed $250 when the amount 
of a payment submitted by a reporter/payor for geothermal, solid 
minerals, and Indian oil and gas leases is not equivalent in amount to 
the total of individual line items on the associated Form MMS-2014, Form 
MMS-4430, or a bill document, unless MMS has authorized the difference 
in amount.
    (b) The MMS may assess an amount not to exceed $250 for each payment 
for geothermal, solid minerals, and Indian oil and gas leases submitted 
by a reporter/payor that cannot be automatically applied to the 
associated Form MMS-2014, Form MMS-4430, or a bill document because of 
inadequate or erroneous information submitted by the reporter/payor.
    (c) For purposes of this section, inadequate or erroneous 
information is defined as:
    (1) Absent or incorrect payor-assigned document number, required to 
be identified by the reporter/payor in Block 4 on Form MMS-2014 
(document 4 number), or the reuse of the same incorrect payor-assigned 
document 4 number in a subsequent reporting period.
    (2) Absent or incorrect bill document invoice number (to include the 
three-character alpha prefix and the nine-digit number) or the payor-
assigned document 4 number required to be identified by the reporter/
payor on the associated payment document, or the reuse of the same 
incorrect payor-assigned document 4 number in a subsequent reporting 
period.
    (3) Absent or incorrect name of the administering Bureau of Indian 
Affairs Agency/Area office; or the word ``allotted'' or the tribe name 
on payment documents remitted to MMS for an Indian tribe or allottee. If 
the payment is made by EFT, the reporter/payor must identify the tribe/
allottee on the EFT message by a pre-established five-digit code.
    (4) Absent or incorrect MMS-assigned payor code on a payment 
document.
    (5) Absent or incorrect identification on a payment document.
    (d) For purposes of this section, the term ``Form MMS-2014'' 
includes submission of reports of royalty information, such as Form MMS-
4430.
    (e) For purposes of this section, a bill document is defined as any 
invoice that MMS has issued for assessments, late-payment interest 
charges, or other amount owed. A payment document is defined as a check 
or wire transfer message.
    (f) The amount of the assessment to be imposed pursuant to 
paragraphs (a) and (b) of this section shall be established periodically 
by MMS. The assessment amount will be based on MMS' experience with 
costs and improper reporting and/or payment as specified in this 
section. The MMS will publish a Notice in the Federal Register of the 
assessment amount to be applied with the effective date.

[58 FR 45438, Aug. 30, 1993, as amended at 73 FR 15897, Mar. 26, 2008]

[[Page 202]]



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) Invoices will be issued and payable as final collection actions. 
Payments made on an invoice are due as specified by the invoice.
    (c) All payments to MMS are due as specified and are not deferred or 
suspended by reason of an appeal having been filed unless such deferral 
or suspension is approved in writing by an authorized MMS official.
    (d)(1) Notwithstanding the provisions of paragraph (a) of this 
section and corresponding lease terms and 30 CFR 210.52, the due date 
for submittal of royalty payments and Reports of Sales and Royalty 
Remittance (Form MMS-2014) for the production months of July, August, 
September, and October 2005 for Federal offshore and onshore oil and gas 
leases by oil and gas lessees or royalty payors who make the 
certification required under paragraph (d)(2) of this section is 
extended until January 3, 2006.
    (2) The extended due dates in paragraph (d)(1) of this section will 
apply to royalty payments and Reports of Sales and Royalty Remittance 
(Form MMS-2014) by any lessee or royalty payor who certifies that a 
hurricane that struck the Gulf of Mexico coast of the United States in 
August or September 2005 disrupted the lessee's or payor's

[[Page 203]]

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; 
73 FR 15898, Mar. 26, 2008]



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 (three-alpha and nine-numeric characters).
    Payment--Any monies for royalty, bonus, rental, late payment charge, 
assessment, penalty, or other money sent to MMS.
    Person--Any individual, firm, corporation, association, partnership, 
consortium, or joint venture (when established as a separate entity). 
The term does not include Federal agencies.
    Report--Form MMS-2014, Report of Sales and Royalty Remittance.
    RIK--Royalty in kind.
    (b) General instructions. You must make all payments to MMS 
electronically to the extent it is cost effective and practical. If you 
pay money to MMS or to an Indian tribe or allottee, you must follow 
these procedures:
    (1) If MMS instructs you to use EFT, you must use EFT for all 
payments to MMS and/or a tribe.
    (2) Contact MMS before using EFT. MMS will provide you with EFT 
payment instructions.
    (3) Separate any payments on a Federal lease from any payments on an 
Indian lease.
    (4) If you are not required to use EFT, use one of the following 
types of payment documents. MMS prefers that you use these payment 
documents in the order presented:
    (i) Commercial check drawn on a solvent bank;
    (ii) Certified check;
    (iii) Cashier's check;
    (iv) Money order;
    (v) Bank draft drawn on a solvent bank; or
    (vi) Federal Reserve check.
    (5) You must include your payor code on all payments.
    (6) You must pay in U.S. dollars.
    (c) How to complete a non-EFT payment. (1) Make any payment on a 
Federal lease payable to: ``Department of the Interior-Minerals 
Management Service'' or ``DOI-MMS.''
    (2) For an Indian allottee payment, send a separate payment for each 
Bureau of Indian Affairs (BIA) agency or

[[Page 204]]

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

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

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

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

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

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

    (f) How to prepare and what to include on your payment document. (1) 
For Form MMS-2014 payments, you must include both your payor code and 
your payor-assigned document number.
    (2) For invoice payments, including RIK invoice payments, you must 
include both your payor code and invoice document identification.
    (3) For bonus payments:
    (i) For one-fifth bonus payments for offshore oil, gas, and sulphur 
leases, follow the instructions in the Notice of Lease Offering.
    (ii) For payment of the four-fifths bonus for an offshore lease, use 
EFT and follow the instructions in Sec. 218.155(c).
    (iii) For the successful bidder's bonus in the competitive sale of a 
coal, geothermal, or offshore mineral (other than oil, gas or sulfur) 
lease, follow the instructions and terms of the Notice of Competitive 
Lease Sale.
    (iv) For installment payments of deferred bonuses, you must use EFT.
    (4) If you are paying a lease rental you must:
    (i) See 30 CFR 218.155(c) for instructions on how to pay first-year 
rentals of an offshore oil, gas, or sulfur lease;
    (ii) See the Notice of Lease Offering for instructions on how to pay 
first-year rentals other than those covered in paragraph (f)(4)(i) of 
this section.
    (iii) Include the MMS Courtesy Notice, when provided, or write your 
payor code and government-assigned lease number on the payment document 
when paying a rental that is not reported on Form MMS-2014 and not paid 
by EFT.
    (g) When is a payment to MMS due? (1) All payments are due to MMS at 
the time law, regulation, or lease terms require unless MMS approves a 
change according to 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.

[[Page 205]]

    (3) If you use EFT to send your payment, it is due in the MMS 
account by the payment due date. You are responsible for your actions or 
your bank's actions that cause a late or incorrect payment. You will not 
be held responsible for mechanical or system failures of EFT payments.
    (h) What happens if payments are late or overdue? (1) If MMS 
receives your payment late, MMS will impose a late-payment interest 
charge under 30 CFR 218.54.
    (2) If you do not pay an amount you owe, MMS may assess civil 
penalties under part 241 of this chapter or other applicable 
regulations.

[62 FR 19498, Apr. 22, 1997, as amended at 66 FR 45773, Aug. 30, 2001; 
67 FR 19112, Apr. 18, 2002; 73 FR 15898, Mar. 26, 2008]



Sec. 218.52  How does a lessee designate a Designee?

    (a) If you are a lessee under 30 U.S.C. 1702(7), and you want to 
designate a person to make all or part of the payments due under a lease 
on your behalf under 30 U.S.C. 1712(a), you must notify MMS or the 
applicable delegated state in writing of such designation by submitting 
Form MMS-4425, Designation Form for Royalty Payment Responsibility. Your 
notification for each lease must include the following:
    (1) The lease number for the lease;
    (2) The type of products you make payments for e.g., oil, gas.
    (3) The type of payments you are responsible for e.g., royalty, 
minimum royalty, rental.
    (4) Whether you are:
    (i) A lessee of record (record title owner) in the lease; or
    (ii) An operating rights owner (working interest owner) in the 
lease, and the percentage of your operating rights ownership in the 
lease;
    (5) The name, address, Taxpayer Identification Number (TIN), and 
phone number of your Designee;
    (6) The name, address, and phone number of the individual to contact 
for the person you named in paragraph (a)(5) of this section;
    (7) Your TIN;
    (8) The date the designation is effective;
    (9) The date the designation terminates, if applicable, and
    (10) A copy of the written designation;
    (b) The person you designate under paragraph (a) of this section is 
your Designee under 30 U.S.C. 1701(24) and 30 U.S.C. 1712(a).
    (c) If you want to terminate a designation you made under paragraph 
(a) of this section, you must submit a revised Form MMS-4425 before the 
termination stating:
    (1) The date the designation is due to terminate; and
    (2) If you are not reporting and paying royalties and making other 
payments to MMS, a new designation under paragraph (a) of this section.
    (d) MMS may require you to provide notice when there is a change in 
the percentage of your record title or operating rights ownership.

[62 FR 42066, Aug. 5, 1997, as amended at 73 FR 15898, Mar. 26, 2008]



Sec. 218.53  Recoupment of overpayments on Indian mineral leases.

    (a) Whenever an overpayment is made under an Indian oil and gas 
lease, a payor may recoup the overpayment through a recoupment on Form 
MMS-2014 against the current month's royalties or other revenues owed on 
the same lease. However, for any month a payor may not recoup more than 
50 percent of the royalties or other revenues owed in that month under 
an individual allotted lease or more than 100 percent of the royalties 
or other revenues owed in that month under a tribal lease.
    (b) With written permission authorized by tribal statute or 
resolution, a payor may recoup an overpayment against royalties or other 
revenues owed in that month under other leases for which that tribe is 
the lessor. A copy of the tribe's written permission must be furnished 
to MMS pursuant to instructions for reporting recoupments in the MMS 
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,

[[Page 206]]

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]



                     Subpart C_Oil and Gas, Onshore



Sec. 218.100  Royalty and rental payments.

    (a) Payment of royalties and rentals. As specified under the 
provisions of the lease, the lessee shall submit all rental payments 
when due and shall pay in value or deliver in production all royalties 
in the amounts of value or production determined by MMS to be due.
    (b) If the lessor elects to take royalty in oil or gas, unless 
otherwise agreed upon, such royalty shall be delivered on the leasehold, 
by the lessee to the order of and without cost to the lessor, as 
instructed by the Associate Director.
    (c) Method of payment. The payor shall tender all payments in 
accordance with 30 CFR 218.51.

[47 FR 47773, Oct. 27, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, 
and amended at 52 FR 23815, June 25, 1987]



Sec. 218.101  Royalty and rental remittance (naval petroleum reserves).

    Remittance covering payments of royalty or rental on naval petroleum 
reserves must be accomplished by necessary identification information 
and sent direct to the Director, Naval Petroleum Reserves in California.

[47 FR 47773, Oct. 27, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983]



Sec. 218.102  Late payment or underpayment charges.

    (a) The failure to make timely or proper payments of any monies due 
pursuant to leases, permits, and contracts subject to these regulations 
will result in the collection by the MMS of the full amount past due 
plus a late payment charge. Exceptions to this late payment charge may 
be granted when estimated payments on minerals

[[Page 207]]

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 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]

[[Page 208]]



                 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.
(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.

[[Page 209]]



------------------------------------------------------------------------
    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 no rental or minimum royalty payments are required 
under paragraph (b) of this section, the prorated rentals or minimum 
royalties are due and payable as of the date the suspension period 
terminates. These amounts shall be computed and notice thereof given the 
lessee. The lessee shall pay the amount due within 30 days after receipt 
of such notice. The anniversary date of a lease shall not change by 
reason of any period of lease suspension or rental or royalty relief 
resulting therefrom.

[44 FR 38276, June 29, 1979; 44 FR 55380, Sept. 26, 1979. Redesignated 
and amended at 47 FR 47006, 47007, Oct. 22, 1982. Further redesignated 
at 48 FR 35641, Aug. 5, 1983 and amended at 51 FR 19063, May 27, 1986; 
54 FR 50616, Dec. 8, 1989; 64 FR 72775, Dec. 28, 1999; 73 FR 15898, Mar. 
26, 2008]



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

[[Page 210]]

payment with the bid will be included in the notice of each lease 
offering. EFT may be used as a method of payment for the one-fifth bonus 
bid amount.
    (2) Beginning with lease offerings held after February 1, 1984, the 
one-fifth bonus amount received from a high bidder shall be deposited 
into an escrow account created pursuant to an agreement between the 
Departments of the Interior and Treasury, pending acceptance or 
rejection of the bid. The one-fifth bonus funds will be invested in 
public debt securities. Investment of this amount by the U.S. Government 
does not indicate acceptance of the bid. The one-fifth bonus amounts 
submitted with bids other than the highest valid bid will be returned to 
respective bidders after bids are opened, recorded, and ranked. Return 
of such amounts will not affect the status, validity, or ranking of 
bids. The one-fifth bonus bid amount received from any high bidder and 
held by the Government pending acceptance or rejection, will be returned 
with actual interest earned, if the bid is subsequently rejected. The 
interest accrued during the period held in the account pending 
acceptance or rejection of the bid will accrue to the Government when 
the bid is accepted.
    (c) Payment of the four-fifths bonus bid amount and the first year's 
rental. Payment shall be made to MMS by EFT unless otherwise directed by 
the Secretary. The payment by EFT via the FRCS must be received by the 
Federal Reserve Bank of New York no later than noon, eastern standard 
time, on the 11th business day after receipt of the lease forms by the 
successful bidder. A ``business day'' is considered to be a day on which 
the OCS regional office issuing the lease is open for business. The 
lease will not be executed by the appropriate MMS official until payment 
is received. Failure to remit by EFT or as directed by the Secretary 
within the time specified above will result in forfeiture of the one-
fifth bonus bid amount and the lease will not be executed by the 
appropriate MMS official. Payors will not be held responsible for late 
payment due to actions beyond their control, such as mechanical or 
systems failure of FRCS or FDS. Payors will be held responsible for 
incorrect actions of their bank which result in late payments. A 2-day 
grace period will be allowed to make up a deficient payment, but a late 
payment charge will be assessed for this late payment and a penalty will 
also be assessed if appropriate. Late payment charges will be assessed 
in accordance with Subpart B of this part.
    (d) General. (1) Payors using the appropriate means of payment (EFT, 
check, etc.) may pay for multiple lease obligations with a single 
remittance but must ensure that the payment complies with subpart B of 
this part and the remittance advice adequately identifies the single 
payment. The format to be used for such identification will be provided 
by the MMS Accounting Center.
    (2) Where to pay.
    (3) The MMS mailing addresses for payments to MMS are specified in 
Sec. 218.51.
    (4) Payments received at the MMS addresses after 4 p.m. mountain 
time are considered received the following business day.
    (e) Miscellaneous payments. Payments shall be made to the manager of 
the appropriate Outer Continental Shelf field office by cash, check or 
bank draft payable to ``Department of the Interior--MMS'' for 
miscellaneous payments such as:
    (1) Pipeline rights-of-way application filing fees and rentals, 
pipeline accessory site rentals and application fees, and other related 
costs.
    (2) Filing and approval fees for transfers of interest in leases.

[49 FR 8605, Mar. 8, 1984, as amended at 52 FR 23815, June 25, 1987; 53 
FR 43201, Oct. 26, 1988; 57 FR 41868, Sept. 14, 1992; 62 FR 19499, Apr. 
22, 1997; 67 FR 19112, Apr. 18, 2002; 73 FR 15898, Mar. 26, 2008]



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]

[[Page 211]]



                    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 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

[[Page 212]]

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 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

[[Page 213]]

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]



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

[[Page 214]]

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:
    (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

[[Page 215]]

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.

                     Subpart D_Oil and Gas, Offshore

219.410 What does this subpart contain?
219.411 What definitions apply to this subpart?
219.412 How will the qualified OCS revenues be divided?
219.413 How will the coastal political subdivisions of Gulf producing 
          States share in the qualified OCS revenues?
219.414 How will MMS determine each Gulf producing State's share of the 
          qualified OCS revenues?
219.415 How will bonus and royalty credits affect revenues allocated to 
          Gulf producing States?
219.416 How will the qualified OCS revenues be allocated to coastal 
          political subdivisions within the Gulf producing States?
219.417 How will MMS disburse qualified OCS revenues to the coastal 
          political subdivisions if, during any fiscal year, there are 
          no applicable leased tracts in the 181 Area in the Eastern 
          Gulf of Mexico Planning Area?
219.418 When will funds be disbursed to Gulf producing States and 
          eligible coastal political subdivisions?

    Authority: Section 104, Pub. L. 97-451, 96 Stat. 2451 (30 U.S.C. 
1714), Pub. L. 109-432, Div C, Title I, 120 Stat. 3000.

    Source: 49 FR 37347, Sept. 21, 1984, unless otherwise noted.

[[Page 216]]

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 217]]



Sec. 219.105  Definitions.

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



                     Subpart D_Oil and Gas, Offshore

    Source: 73 FR 78629, Dec. 23, 2008, unless otherwise noted.



Sec. 219.410  What does this subpart contain?

    (a) The Gulf of Mexico Energy Security Act of 2006 (GOMESA) directs 
the Secretary of the Interior to disburse a portion of the rentals, 
royalties, bonus, and other sums derived from certain Outer Continental 
Shelf (OCS) leases in the Gulf of Mexico (GOM) to the States of Alabama, 
Louisiana, Mississippi, and Texas (collectively identified as the Gulf 
producing States); to eligible coastal political subdivisions within 
those States; and to the Land and Water Conservation Fund. Shared GOMESA 
revenues are reserved for the following purposes:
    (1) Projects and activities for the purposes of coastal protection, 
including conservation, coastal restoration, hurricane protection, and 
infrastructure directly affected by coastal wetland losses.
    (2) Mitigation of damage to fish, wildlife, or natural resources.
    (3) Implementation of a federally-approved marine, coastal, or 
comprehensive conservation management plan.
    (4) Mitigation of the impact of OCS activities through the funding 
of onshore infrastructure projects.
    (5) Planning assistance and administrative costs not-to-exceed 3 
percent of the amounts received.
    (b) This subpart sets forth the formula and methodology MMS will use 
to determine the amount of revenues to be disbursed and the amount to be 
allocated to each Gulf producing State and each eligible coastal 
political subdivision. For questions related to the revenue sharing 
provisions in this subpart, please contact: Chief, Financial Management, 
Minerals Revenue Management; P.O. Box 25165; Denver Federal Center, 
Building 85; MS-350B1; Denver, CO 80225-0165, or at (303) 231-3429.



Sec. 219.411  What definitions apply to this subpart?

    Terms in this subpart have the following meaning:
    181 Area means the area identified in map 15, page 58, of the 
Proposed Final Outer Continental Shelf Oil and Gas Leasing Program for 
1997-2002, dated August 1996, of the Minerals Management Service, 
available in the Office of the Director of the Minerals Management 
Service, excluding the area offered in OCS Lease Sale 181, held on 
December 5, 2001.
    181 Area in the Eastern Planning Area is comprised of the area of 
overlap of the two geographic areas defined as the ``181 Area'' and the 
``Eastern Planning Area.''
    181 South Area means any area--
    (1) Located--
    (i) South of the 181 Area;
    (ii) West of the Military Mission Line; and
    (iii) In the Central Planning Area;
    (2) Excluded from the Proposed Final Outer Continental Shelf Oil and 
Gas Leasing Program for 1997-2002, dated August 1996, of the Minerals 
Management Service; and
    (3) Included in the areas considered for oil and gas leasing, as 
identified in map 8, page 37, of the document entitled, Draft Proposed 
Program Outer Continental Shelf Oil and Gas Leasing Program 2007-2012, 
dated February 2006.
    Applicable leased tract means a tract that is subject to a lease 
under section 8 of the Outer Continental Shelf Lands Act for the purpose 
of drilling for, developing, and producing oil or natural gas resources, 
and is located fully or partially in either the 181 Area in the Eastern 
Planning Area, or in the 181 South Area.
    Central Planning Area means the Central Gulf of Mexico Planning Area 
of the Outer Continental Shelf, as designated in the document entitled, 
Draft Proposed Program Outer Continental Shelf Oil and Gas Leasing 
Program 2007-2012, dated February 2006.
    Coastal political subdivision means a political subdivision of a 
Gulf producing State any part of which political subdivision is--
    (1) Within the coastal zone (as defined in section 304 of the 
Coastal Zone Management Act of 1972 (16 U.S.C.

[[Page 218]]

1453)) of the Gulf producing State as of December 20, 2006; and
    (2) Not more than 200 nautical miles from the geographic center of 
any leased tract.
    Coastline means the line of ordinary low water along that portion of 
the coast which is in direct contact with the open sea and the line 
marking the seaward limit of inland waters. This is the same definition 
used in section 2 of the Submerged Lands Act (43 U.S.C. 1301).
    Distance means the minimum great circle distance.
    Eastern Planning Area means the Eastern Gulf of Mexico Planning Area 
of the Outer Continental Shelf, as designated in the document entitled, 
Draft Proposed Program Outer Continental Shelf Oil and Gas Leasing 
Program 2007-2012, dated February 2006.
    Gulf producing State means each of the States of Alabama, Louisiana, 
Mississippi, and Texas.
    Leased tract means any tract that is subject to a lease under 
section 6 or 8 of the Outer Continental Shelf Lands Act for the purpose 
of drilling for, developing, and producing oil or natural gas resources.
    Military Mission Line means the north-south line at 86[deg]41[min] 
W. longitude.
    Qualified OCS revenues mean--
    (1) The term qualified OCS revenues means, in the case of each of 
fiscal years 2007 through 2016, all rentals, royalties, bonus bids, and 
other sums received by the U.S. from leases entered into on or after 
December 20, 2006, located:
    (i) In the 181 Area in the Eastern Planning Area; and
    (ii) In the 181 South Area.
    (iii) For applicable leased tracts intersected by the planning area 
administrative boundary line (e.g., separating the GOM Central Planning 
Area from the Eastern Planning Area), only the percent of revenues 
equivalent to the percent of surface acreage in the 181 Area in the 
Eastern Planning Area will be considered qualified OCS revenues.
    (2) Exclusions to the term qualified OCS revenues include:
    (i) Revenues from the forfeiture of a bond or other surety securing 
obligations other than royalties;
    (ii) Civil penalties;
    (iii) Royalties taken by the Secretary in-kind and not sold;
    (iv) User fees; and
    (v) Lease revenues explicitly circumscribed from GOMESA revenue 
sharing by statute or appropriations law.



Sec. 219.412  How will the qualified OCS revenues be divided?

    For each of the fiscal years 2007 through 2016, 50 percent of the 
qualified OCS revenues will be placed in a special U.S. Treasury account 
from which 75 percent of the revenues will be disbursed to the Gulf 
producing States, and 25 percent will be disbursed to the Land and Water 
Conservation Fund. Each Gulf producing State will receive at least 10 
percent of the qualified OCS revenues available for allocation to the 
Gulf producing States each fiscal year.

       Revenue Distribution of Qualified OCS Revenues Under GOMESA
------------------------------------------------------------------------
                                                         Percentage of
                                                         qualified OCS
         Recipient of qualified OCS revenues                revenues
                                                           (percent)
------------------------------------------------------------------------
U.S. Treasury (General Fund).........................               50
Land and Water Conservation Fund.....................               12.5
Gulf Producing States................................               30
Gulf Producing State Coastal Political Subdivisions..                7.5
------------------------------------------------------------------------



Sec. 219.413  How will the coastal political subdivisions of Gulf producing States share in the qualified OCS revenues?

    Of the revenues allocated to a Gulf producing State, 20 percent will 
be distributed to the coastal political subdivisions within that State.



Sec. 219.414  How will MMS determine each Gulf producing State's share of the qualified OCS revenues?

    (a) The MMS will determine the geographic centers of each applicable 
leased tract and, using the great circle distance method, will determine 
the closest distance from the geographic centers of each applicable 
leased tract to each Gulf producing State's coastline.
    (b) Based on these distances, we will calculate the qualified OCS 
revenues to be disbursed to each Gulf producing State using the 
following procedure:

[[Page 219]]

    (1) For each Gulf producing State, we will calculate and total, over 
all applicable leased tracts, the mathematical inverses of the distances 
between the points on the State's coastline that are closest to the 
geographic centers of the applicable leased tracts and the geographic 
centers of the applicable leased tracts. For applicable leased tracts 
intersected by the planning area administrative boundary line, the 
geographic center used for the inverse distance determination will be 
the geographic center of the entire lease as if it were not intersected.
    (2) For each Gulf producing State, we will divide the sum of each 
State's inverse distances, from all applicable leased tracts, by the sum 
of the inverse distances from all applicable leased tracts across all 
four Gulf producing States. We will multiply the result by the amount of 
qualified OCS revenues to be shared as shown below. In the formulas, 
IAL, ILA, IMS, and ITX represent the sum of the inverses of the closest 
distances between Alabama, Louisiana, Mississippi, and Texas and all 
applicable leased tracts, respectively.

Alabama Share = (IAL / (IAL + ILA + IMS + ITX)) x Qualified OCS Revenues
Louisiana Share = (ILA / (IAL + ILA + IMS + ITX)) x Qualified OCS 
    Revenues
Mississippi Share = (IMS / (IAL + ILA + IMS + ITX)) x Qualified OCS 
    Revenues
Texas Share = (ITX / (IAL + ILA + IMS + ITX)) x Qualified OCS Revenues

    (3) If in any fiscal year, this calculation results in less than a 
10 percent allocation of the qualified OCS revenues to any Gulf 
producing State, we will recalculate the distribution. We will allocate 
10 percent of the qualified OCS revenues to the State and recalculate 
the other States' shares of the remaining qualified OCS revenues 
omitting the State receiving the 10 percent minimum share and its 10 
percent share from the calculation.



Sec. 219.415  How will bonus and royalty credits affect revenues allocated to Gulf producing States?

    If bonus and royalty credits issued under Section 104(c) of the Gulf 
of Mexico Energy Security Act are used to pay bonuses or royalties on 
leases in the 181 Area located in the Eastern Planning Area and the 181 
South Area, then there will be a corresponding reduction in qualified 
OCS revenues available for distribution.



Sec. 219.416  How will the qualified OCS revenues be allocated to coastal political subdivisions within the Gulf producing States?

    The MMS will disburse funds to the coastal political subdivisions in 
accordance with the following criteria:
    (a) Twenty-five percent of the qualified OCS revenues will be 
allocated to a Gulf producing State's coastal political subdivisions in 
the proportion that each coastal political subdivision's population 
bears to the population of all coastal political subdivisions in the 
producing State;
    (b) Twenty-five percent of the qualified OCS revenues will be 
allocated to a Gulf producing State's coastal political subdivisions in 
the proportion that each coastal political subdivision's miles of 
coastline bears to the number of miles of coastline of all coastal 
political subdivisions in the producing State. Except that, for the 
State of Louisiana, proxy coastline lengths for coastal political 
subdivisions without a coastline will be considered to be \1/3\ the 
average length of the coastline of all political subdivisions within 
Louisiana having a coastline.
    (c) Fifty percent of the revenues will be allocated to a Gulf 
producing State's coastal political subdivisions in amounts that are 
inversely proportional to the respective distances between the 
geographic center of each applicable leased tract and the point in each 
coastal political subdivision that is closest to the geographic center 
of each applicable leased tract. Except that, an applicable leased tract 
will be excluded from this calculation if any portion of the tract is 
located in a geographic area that was subject to a leasing moratorium on 
January 1, 2005, unless that tract was in production on that date.

[[Page 220]]



Sec. 219.417  How will MMS disburse qualified OCS revenues to the

coastal political subdivisions if, during any fiscal year, there are no applicable leased 
          tracts in the 181 Area in the Eastern Gulf of Mexico Planning 
          Area?

    If, during any fiscal year, there are no applicable leased tracts in 
the 181 Area in the Eastern Gulf of Mexico Planning Area, MMS will 
disburse funds to the coastal political subdivisions in accordance with 
the following criteria:
    (a) Fifty percent of the revenues will be allocated to a Gulf 
producing State's coastal political subdivisions in the proportion that 
each coastal political subdivision's population bears to the population 
of all coastal political subdivisions in the State; and
    (b) Fifty percent of the revenues will be allocated to a Gulf 
producing State's coastal political subdivisions in the proportion that 
each coastal political subdivision's miles of coastline bears to the 
number of miles of coastline of all coastal political subdivisions in 
the State. Except that, for the State of Louisiana, proxy coastline 
lengths for coastal political subdivisions without a coastline will be 
considered to be \1/3\ the average length of the coastline of all 
political subdivisions within Louisiana having a coastline.



Sec. 219.418  When will funds be disbursed to Gulf producing States and eligible coastal political subdivisions?

    (a) The MMS will disburse allocated funds in the fiscal year after 
MMS collects the qualified OCS revenues. For example, MMS will disburse 
funds in fiscal year 2010 from the qualified OCS revenues collected 
during fiscal year 2009.
    (b) We intend to disburse funds on or before March 31st of the year 
following the fiscal year of qualified OCS revenues.



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.

[[Page 221]]

    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.
    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.

[[Page 222]]

    NPSL project area means the NPSL tract, offshore facilities, and 
shore base facilities.
    NPSL property means the NPSL tract, and materiel and offshore 
facilities acquired for use in NPSL operations and that are installed 
and/or used on the NPSL tract.
    NPSL tract means a tract subject to an NPSL.
    OCS lease means a Federal lease for oil and gas issued under the 
OCSLA.
    OCS lease sale means the DOI proceeding by which leases for certain 
OCS tracts are offered for sale by competitive bidding and during which 
bids are received, announced, and recorded.
    Offshore facilities means platform and support systems located 
offshore that are necessary to conduct NPSL operations, e.g., oil and 
gas handling facilities, living quarters, offices, shops, cranes, 
electrical supply equipment and systems, fuel and water storage and 
piping, heliport, marine docking installations, communication 
facilities, and navigation aids.
    Outside party means any person who is not a lessee.
    Person means person as defined in part 260 of this chapter.
    Personal expenses means travel and other reasonable reimbursable 
expenses of lessee's employees.
    Production means all oil, gas, or other hydrocarbon products 
produced, removed, saved, or sold from the NPSL property. Gas and 
liquids of all kinds are included in production. Production includes the 
allocated share of production from a unit of which the NPSL is a part.
    Production revenue means the value of all production attributable to 
an NPSL property, which value is determined in accordance with 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,

[[Page 223]]

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.
    (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,

[[Page 224]]

maintenance of building and grounds (exclusive of fixing-up expenses), 
utilities, taxes, property insurance, etc., after settlement date of 
lease or date of new permanent residence are allowable.
    (ii) The combined total of costs listed in paragraphs (b)(4)(i) (C) 
through (D) of this section shall not exceed 8 percent of the sales 
price of the property sold.
    (iii) Section 220.013(g) specifies employee relocation expenses that 
are not allowable as a charge to NPSL operations.
    (5) Lessee's current costs of established plans for employee's group 
life insurance, hospitalization, pension, retirement, stock purchase, 
thrift, bonds, and other benefit plans of a like nature that are made 
available to all of lessee's employees on an equitable basis, applicable 
to lessee's labor cost chargeable to NPSL operations under paragraphs 
(b)(1) (i) and (ii) and (b)(2) of this section, are allowable. The 
amount of these charges shall be lessee's actual cost not to exceed 23 
percent of the total charges under paragraphs (b)(1) (i) and (ii) and 
(b)(2) except that the Director may from time to time establish a 
different maximum percentage.
    (6) Charges for expenses incurred under paragraphs (b)(2) through 
(b)(5) of this section may be made to NPSL accounts on a ``when and as 
paid'' basis or by a percentage assessment method. If the percentage 
assessment method is used, it shall be based upon the lessee's actual 
cost experience expressed as a percentage of costs chargeable under 
paragraphs (b)(1) (i) and (ii) and (b)(2) of this section. Under either 
method the lessee's own cost of administering the plans and paying the 
salaries and benefits defined in this paragraph shall be excluded. In 
determining actual cost experience of an employee benefit plan, any 
dividend or refunds received that are applicable to insurance or annuity 
policies shall be used to reduce the cost of such policies.
    (c) Materiel. (1) Materiel purchased or furnished by a lessee as 
NPSL property shall be charged or credited at amounts specified in 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

[[Page 225]]

the following conditions and limitations:
    (1) Contract services (including professional consulting services 
and contract services of technical personnel) that are entirely 
performed in the NPSL project area and benefit exclusively NPSL 
operations may be charged at the rates specified in the contract.
    (2) Contract services (including professional consulting services 
and contract services of technical personnel) that are entirely 
performed in the NPSL project area and benefit the NPSL operations and 
operations on other tracts must be allocated among all tracts benefited 
and only that portion representing services benefiting the NPSL tract 
charged to NPSL operations.
    (3) Contract services (including professional consulting services 
and contract services of technical personnel) that are performed at 
sites outside the NPSL project area may be charged to NPSL operations 
only if:
    (i) The contracted services charged to the NPSL operations benefit 
only the NPSL tract or support NPSL operations;
    (ii) The contract under which such services are provided deals 
exclusively with services benefiting the NPSL tract or NPSL operations, 
or the costs of the contract services which are applicable to the NPSL 
tract or NPSL operations are separately and specifically identified in 
the contract; and
    (iii) Services specified in the contract relate to the resolution of 
specific technical problems confronting NPSL operations, or specific 
engineering design problems related to equipment or facilities required 
for NPSL operations.
    (4) The cost of any contract service related to research and 
development is specifically excluded, as are contract services calling 
for feasibility studies not directly related to specific engineering 
design problems or alternatives for equipment and facilities required by 
NPSL operations.
    (f) Legal expenses. Expense of handling, investigating and settling 
litigation or claims, discharging of liens, payments of judgments and 
amounts paid for settlement of claims incurred in or resulting from NPSL 
operations, or necessary to protect or recover the NPSL property are 
allowable, except those costs listed in 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.

[[Page 226]]



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

[[Page 227]]

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 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:

[[Page 228]]

    (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 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:

[[Page 229]]

    (i) Condition A (new) materiel. (A) Tubular goods, except line pipe, 
shall be priced at the current market price in effect on date of 
movement on a minimum carload or barge load weight basis, regardless of 
quantity transferred, equalized to the lowest published price ``free on 
board'' (f.o.b.) railway receiving point or recognized barge terminal 
nearest the NPSL tract where such materiel is normally available.
    (B) Line pipe. (1) Movement of less than 30,000 pounds shall be 
priced at the current price in effect at date of movement, as listed by 
a reliable supply store nearest the NPSL tract where such materiel is 
normally available.
    (2) Movement of 30,000 pounds or more shall be priced under the 
provisions for tubular goods pricing in paragraph (a)(2)(i)(A) of this 
section.
    (C) Other materiel shall be priced at the current price in effect at 
date of movement, as listed by a reliable supply store or f.o.b. railway 
receiving point nearest the NPSL tract where such materiel is normally 
available.
    (ii) Condition B (good used) materiel. Materiel in sound and 
serviceable condition and suitable for reuse without reconditioning:
    (A) Materiel transferred to the NPSL project area shall be priced at 
75 percent of current Condition A price.
    (B) Materiel transferred from the NPSL project area shall be priced:
    (1) At 75 percent of current Condition A price, if the materiel was 
originally charged to NPSL operations as Condition A materiel, or
    (2) At 65 percent of current Condition A price, if the materiel was 
originally charged to NPSL operations as Condition B materiel at 75 
percent of current Condition A price.
    (iii) Conditions C and D (other used) materiel--(A) Condition C. 
Materiel that is not in sound and serviceable condition and not suitable 
for its original function until after reconditioning shall be priced at 
50 percent of current Condition A price.
    (B) Condition D. Materiel no longer suitable for its original 
purposes but suitable for some other purpose shall be priced on a basis 
commensurate with its use and comparable with that of materiel normally 
used for such other purpose. If the materiel has no alternative use it 
should be priced at prevailing prices as scrap.
    (iv) Obsolete materiel. Materiel that is serviceable and usable for 
its original function and has a value less than Condition A, B, or C 
materiel may be valued at a price agreed to by the Director. Such price 
should be the equivalent of the value of the service rendered by such 
materiel.
    (b) Pricing conditions. (1) Loading and unloading costs shall be 
charged at a rate of 15 cents per hundred weight, or such other rate as 
may be set by the Director, on all tubular goods movements, in lieu of 
loading/unloading costs sustained, when the actual hauling costs of such 
tubular goods is equalized under provisions of 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

[[Page 230]]

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 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]

[[Page 231]]



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 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

[[Page 232]]

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.
    (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

[[Page 233]]

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 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?

[[Page 234]]

                           Delegation Process

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

                          Existing Delegations

227.111 Do existing delegation agreements remain in effect?

                              Compensation

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

         States' Responsibilities To Perform Delegated Functions

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

                           Performance Review

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

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

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

                   Delegation of MMS Royalty Functions



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

[[Page 235]]

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 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

[[Page 236]]

you must submit a delegation proposal to the MMS Associate Director for 
Minerals Revenue Management. MMS will provide you with technical 
assistance and information to help you prepare your delegation proposal. 
Your proposal must contain the following minimum information:
    (a) The name and title of the State official authorized to submit 
the delegation proposal and execute the delegation agreement;
    (b) The name, address, and telephone number of the State contact for 
the proposal;
    (c) A copy of the legislation, State Attorney General opinion or 
other document that:
    (1) States which State entity or entities are responsible for 
performing delegated functions, and if more than one entity is delegated 
such responsibility, the position of the highest ranking State official 
having ultimate authority over the collection of royalties from leases 
on Federal lands within the State;
    (2) Demonstrates the State's authority to:
    (i) Accept a delegation from MMS; and
    (ii) Receive State or Federal appropriations to perform delegated 
functions;
    (d) The date you propose to begin performing delegated functions;
    (e) A detailed statement of the delegable functions that you propose 
to perform. For each function, describe the resources available in your 
State to perform each function, the procedures you will use to perform 
each function, and how you will assure that you will meet all Federal 
laws, lease terms, regulations and relevant performance standards. As 
evidence that you have or will have the resources to perform each 
delegable function, provide the following information:
    (1) A description of the personnel you have available to perform 
delegated functions, including:
    (i) How many persons you will assign full-time and part-time to each 
delegated function;
    (ii) The technical qualifications of the key personnel you will 
assign to each function, including academic field and degree, 
professional credentials, and quality and amount of experience with 
similar functions; and
    (iii) Whether these persons are currently State employees. If not, 
explain how you propose to hire these persons or obtain their services, 
and when you expect to have those persons available to perform delegated 
functions;
    (2) A description of the facilities you will use to perform 
delegated functions, including:
    (i) Whether you currently have the facilities in which you will 
physically locate the personnel and equipment you will need to perform 
the functions you propose to assume. If not, how you propose to acquire 
such facilities, and when you expect to have such facilities available; 
and
    (ii) How much office space is available;
    (3) Describe the equipment you will use to perform delegated 
functions, including:
    (i) Hardware and software you will use to perform each delegated 
function, including equipment for:
    (A) Document processing, including compatibility with MMS automated 
systems, electronic commerce capabilities, and data storage 
capabilities;
    (B) Accessing reference data;
    (C) Contacting production or royalty reporters;
    (D) Issuing demands;
    (E) Maintaining accounting records;
    (F) Performing automated verification;
    (G) Maintaining security of confidential and proprietary 
information; and
    (H) Providing data to other Federal agencies;
    (ii) Whether you currently have the equipment you will need to 
perform the functions you propose to assume. If not, how you propose to 
acquire such equipment and when you expect to have such equipment 
available;
    (f) Your estimates of the costs to fund the following resources 
necessary to perform the delegation:
    (1) Personnel, including hiring, employee salaries and benefits, 
travel and training;
    (2) Facilities, including acquisition, upgrades, operation, and 
maintenance; and
    (3) Equipment, including acquisition, operation, and maintenance;

[[Page 237]]

    (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 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:

[[Page 238]]

    (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.



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

[[Page 239]]

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.

                              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;

[[Page 240]]

    (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:
    (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

[[Page 241]]

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 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;

[[Page 242]]

    (c) Accept multiple forms of electronic media from reporters, as MMS 
specifies;
    (d) Timely transmit required production or royalty data to MMS and 
other affected Federal agencies;
    (e) Access well, lease, agreement, and reporter reference data from 
MMS and provide updated information to MMS;
    (f) For production reports, maintain adequate system software edits 
to ensure compliance with the provisions of 30 CFR part 210--Forms and 
Reports, the MMS Minerals Production Reporter Handbook, any interagency 
memorandum of understanding to which MMS is a party, and the Standards;
    (g) For royalty reports, maintain adequate system software edits to 
ensure compliance with the provisions of 30 CFR part 218, the Oil and 
Gas Payor Handbook, Volume II, ``Dear Payor'' letters, and the 
Standards; and
    (h) Comply with the procedures for appealed demands or orders, 
including meeting timeframes, supplying information, and using the 
appropriate format.

[62 FR 43084, Aug. 12, 1997, as amended at 67 FR 19112, Apr. 18, 2002; 
73 FR 15898, Mar. 26, 2008]



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;
    (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

[[Page 243]]

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.



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 p