[Title 30 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2007 Edition]
[From the U.S. Government Printing Office]
[[Page i]]
30
Parts 200 to 699
Revised as of July 1, 2007
Mineral Resources
________________________
Containing a codification of documents of general
applicability and future effect
As of July 1, 2007
With Ancillaries
Published by
Office of the Federal Register
National Archives and Records
Administration
A Special Edition of the Federal Register
[[Page ii]]
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[[Page iii]]
Table of Contents
Page
Explanation................................................. v
Title 30:
Chapter II--Minerals Management Service, Department
of the Interior 3
Chapter III--Board of Surface Mining and Reclamation
Appeals, Department of the Interior 597
Chapter IV--Geological Survey, Department of the
Interior 601
Finding Aids:
Material Approved for Incorporation by Reference........ 615
Table of CFR Titles and Chapters........................ 623
Alphabetical List of Agencies Appearing in the CFR...... 641
List of CFR Sections Affected........................... 651
[[Page iv]]
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Cite this Code: CFR
To cite the regulations in
this volume use title,
part and section number.
Thus, 30 CFR 201.100
refers to title 30, part
201, section 100.
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[[Page v]]
EXPLANATION
The Code of Federal Regulations is a codification of the general and
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Each volume of the Code is revised at least once each calendar year
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[[Page vi]]
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What if the material incorporated by reference cannot be found? If
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[[Page vii]]
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Raymond A. Mosley,
Director,
Office of the Federal Register.
July 1, 2007.
[[Page ix]]
THIS TITLE
Title 30--Mineral Resources is composed of three volumes. The parts
in these volumes are arranged in the following order: parts 1 to 199,
parts 200 to 699, and part 700 to End. The contents of these volumes
represent all current regulations codified under this title of the CFR
as of July 1, 2007.
For this volume, Cheryl E. Sirofchuck was Chief Editor. The Code of
Federal Regulations publication program is under the direction of
Frances D. McDonald, assisted by Ann Worley.
[[Page 1]]
TITLE 30--MINERAL RESOURCES
(This book contains parts 200 to 699)
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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)
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SUBCHAPTER A--MINERALS REVENUE MANAGEMENT
Part Page
201 General..................................... 5
202 Royalties................................... 5
203 Relief or reduction in royalty rates........ 14
204 Alternatives for marginal properties........ 44
206 Product valuation........................... 50
207 Sales agreements or contracts governing the
disposal of lease products.............. 162
208 Sale of Federal royalty oil................. 164
210 Forms and reports........................... 171
212 Records and files maintenance............... 183
215
Accounting and auditing standards [Reserved]
216 Production accounting....................... 185
217 Audits and inspections...................... 192
218 Collection of royalties, rentals, bonuses
and other monies due the Federal
Government and credits and incentives
due lessees............................. 194
219 Distribution and disbursement of royalties,
rentals, and bonuses.................... 211
220 Accounting procedures for determining net
profit share payment for Outer
Continental Shelf oil and gas leases.... 213
227 Delegation to States........................ 226
228 Cooperative activities with States and
Indian tribes........................... 238
229 Delegation to States........................ 241
230
Recoupments and refunds [Reserved]
232
Interest payments [Reserved]
233
Escrow and investments [Reserved]
234
Bonding--payment liability [Reserved]
241 Penalties................................... 249
242
Orders [Reserved]
[[Page 4]]
243 Suspensions pending appeal and bonding--
Minerals revenue management............. 254
SUBCHAPTER B--OFFSHORE
250 Oil and gas and sulphur operations in the
Outer Continental Shelf................. 260
251 Geological and geophysical (G & G)
explorations of the Outer Continental
Shelf................................... 461
252 Outer Continental Shelf (OCS) oil and gas
information program..................... 474
253 Oil spill financial responsibility for
offshore facilities..................... 479
254 Oil-spill response requirements for
facilities located seaward of the coast
line.................................... 493
256 Leasing of sulphur or oil and gas in the
Outer Continental Shelf................. 505
259 Mineral leasing: Definitions................ 533
260 Outer Continental Shelf oil and gas leasing. 534
270 Nondiscrimination in the Outer Continental
Shelf................................... 542
280 Prospecting for minerals other than oil,
gas, and sulfur on the Outer Continental
Shelf................................... 543
281 Leasing of minerals other than oil, gas, and
sulphur in the Outer Continental Shelf.. 555
282 Operations in the Outer Continental Shelf
for minerals other than oil, gas, and
sulphur................................. 568
SUBCHAPTER C--APPEALS
290 Appeals procedures.......................... 591
[[Page 5]]
SUBCHAPTER A_MINERALS REVENUE MANAGEMENT
PART 201_GENERAL--Table of Contents
Subpart A--General Provisions [Reserved]
Subpart B--Oil and Gas, General [Reserved]
Subpart C_Oil and Gas, Onshore
Sec.
201.100 Responsibilities of the Associate Director for Minerals Revenue
Management.
Subpart D--Oil, Gas and Sulphur, Offshore [Reserved]
Subpart E--Coal [Reserved]
Subpart F--Other Solid Minerals [Reserved]
Subpart G--Geothermal Resources [Reserved]
Subpart H--Indian Lands [Reserved]
Authority: The Act of February 25, 1920 (30 U.S.C. 181, et seq.), as
amended; the Act of May 21, 1930 (30 U.S.C. 301-306); the Mineral
Leasing Act for Acquired Lands (30 U.S.C. 351-359), as amended; the Act
of March 3, 1909 (25 U.S.C. 396), as amended; the National Environmental
Policy Act of 1969 (42 U.S.C. 4321, et seq.) as amended; the Act of May
11, 1938 (25 U.S.C. 396a-396q), as amended; the Act of February 28, 1891
(25 U.S.C. 397), as amended; the Act of May 29, 1924 (25 U.S.C. 398);
the Act of March 3, 1927 (25 U.S.C. 398a-398e); the Act of June 30, 1919
(25 U.S.C. 399), as amended; R.S. Sec. 441 (43 U.S.C. 1457), see also
Attorney General's Opinion of April 2, 1941 (40 Op. Atty. Gen. 41); the
Federal Property and Administrative Services Act of 1949 (40 U.S.C. 471,
et seq.), as amended; the National Environmental Policy Act of 1969 (42
U.S.C. 4321 et seq.), as amended; the Act of December 12, 1980 (Pub. L.
96-514, 94 Stat. 2964); the Combined Hydrocarbon Leasing Act of 1981
(Pub. L. 97-78, 95 Stat. 1070); the Outer Continental Shelf Lands Act
(43 U.S.C. 1331, et seq.), as amended; section 2 of Reorganization Plan
No. 3 of 1950 (64 stat. 1262); Secretarial Order No. 3071 of January 19,
1982, as amended; and Secretarial Order 3087, as amended.
Subpart A--General Provisions [Reserved]
Subpart B--Oil and Gas, General [Reserved]
Subpart C_Oil and Gas, Onshore
Sec. 201.100 Responsibilities of the Associate Director for Minerals Revenue
Management.
The Associate Director is responsible for the collection of certain
rents, royalties, and other payments; for the receipt of sales and
production reports; for determining royalty liability; for maintaining
accounting records; for any audits of the royalty payments and
obligations; and for any and all other functions relating to royalty
management on Federal and Indian oil and gas leases.
[47 FR 47768, Oct. 27, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983]
Subpart D--Oil, Gas and Sulphur, Offshore [Reserved]
Subpart E--Coal [Reserved]
Subpart F--Other Solid Minerals [Reserved]
Subpart G--Geothermal Resources [Reserved]
Subpart H--Indian Lands [Reserved]
PART 202_ROYALTIES--Table of Contents
Subpart A--General Provisions [Reserved]
Subpart B_Oil, Gas, and OCS Sulfur, General
Sec.
202.51 Scope and definitions.
202.52 Royalties.
202.53 Minimum royalty.
Subpart C_Federal and Indian Oil
202.100 Royalty on oil.
202.101 Standards for reporting and paying royalties.
[[Page 6]]
Subpart D_Federal Gas
202.150 Royalty on gas.
202.151 Royalty on processed gas.
202.152 Standards for reporting and paying royalties on gas.
Subpart E--Solid Minerals, General [Reserved]
Subpart F_Coal
202.250 Overriding royalty interest.
Subpart G--Other Solid Minerals [Reserved]
Subpart H_Geothermal Resources
202.350 Scope and definitions.
202.351 Royalties on geothermal resources.
202.352 Minimum royalty.
202.353 Measurement standards for reporting and paying royalties and
direct use fees.
Subpart I--OCS Sulfur [Reserved]
Subpart J_Gas Production from Indian Leases
202.550 How do I determine the royalty due on gas production?
202.551 How do I determine the volume of production for which I must pay
royalty if my lease is not in an approved Federal unit or
communitization agreement (AFA)?
202.552 How do I determine how much royalty I must pay if my lease is in
an approved Federal unit or communitization agreement (AFA)?
202.553 How do I value my production if I take more than my entitled
share?
202.554 How do I value my production that I do not take if I take less
than my entitled share?
202.555 What portion of the gas that I produce is subject to royalty?
202.556 How do I determine the value of avoidably lost, wasted, or
drained gas?
202.557 Must I pay royalty on insurance compensation for unavoidably
lost gas?
202.558 What standards do I use to report and pay royalties on gas?
Authority: 5 U.S.C. 301 et seq.; 25 U.S.C. 396 et seq., 396a et
seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et seq.;
1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq.; 1331 et seq., 1801
et seq.
Subpart A--General Provisions [Reserved]
Subpart B_Oil, Gas, and OCS Sulfur, General
Source: 53 FR 1217, Jan. 15, 1988, unless otherwise noted.
Sec. 202.51 Scope and definitions.
(a) This subpart is applicable to Federal and Indian (Tribal and
allotted) oil and gas leases (except leases on the Osage Indian
Reservation, Osage County, Oklahoma) and OCS sulfur leases.
(b) The definitions in subparts B, C, D, and E, of part 206 of this
title are applicable to subparts B, C, D, and J of this part.
[53 FR 1217, Jan. 15, 1988, as amended at 64 FR 43513, Aug. 10, 1999]
Sec. 202.52 Royalties.
(a) Royalties on oil, gas, and OCS sulfur shall be at the royalty
rate specified in the lease, unless the Secretary, pursuant to the
provisions of the applicable mineral leasing laws, reduces, or in the
case of OCS leases, reduces or eliminates, the royalty rate or net
profit share set forth in the lease.
(b) For purposes of this subpart, the use of the term royalty(ies)
includes the term net profit share(s).
Sec. 202.53 Minimum royalty.
For leases that provide for minimum royalty payments, the lessee
shall pay the minimum royalty as specified in the lease.
Subpart C_Federal and Indian Oil
Sec. 202.100 Royalty on oil.
(a) Royalties due on oil production from leases subject to the
requirements of this part, including condensate separated from gas
without processing, shall be at the royalty rate established by the
terms of the lease. Royalty shall be paid in value unless MMS requires
payment in-kind. When paid in value, the royalty due shall be the value,
for royalty purposes, determined pursuant to part 206 of this title
multiplied by the royalty rate in the lease.
(b)(1) All oil (except oil unavoidably lost or used on, or for the
benefit of, the lease, including that oil used off-lease for the benefit
of the lease when such off-lease use is permitted by the
[[Page 7]]
MMS or BLM, as appropriate) produced from a Federal or Indian lease to
which this part applies is subject to royalty.
(2) When oil is used on, or for the benefit of, the lease at a
production facility handling production from more than one lease with
the approval of the MMS or BLM, as appropriate, or at a production
facility handling unitized or communitized production, only that
proportionate share of each lease's production (actual or allocated)
necessary to operate the production facility may be used royalty-free.
(3) Where the terms of any lease are inconsistent with this section,
the lease terms shall govern to the extent of that inconsistency.
(c) If BLM determines that oil was avoidably lost or wasted from an
onshore lease, or that oil was drained from an onshore lease for which
compensatory royalty is due, or if MMS determines that oil was avoidably
lost or wasted from an offshore lease, then the value of that oil shall
be determined in accordance with 30 CFR part 206.
(d) If a lessee receives insurance compensation for unavoidably lost
oil, royalties are due on the amount of that compensation. This
paragraph shall not apply to compensation through self-insurance.
(e)(1) In those instances where the lessee of any lease committed to
a federally approved unitization or communitization agreement does not
actually take the proportionate share of the agreement production
attributable to its lease under the terms of the agreement, the full
share of production attributable to the lease under the terms of the
agreement nonetheless is subject to the royalty payment and reporting
requirements of this title. Except as provided in paragraph (e)(2) of
this section, the value, for royalty purposes, of production
attributable to unitized or communitized leases will be determined in
accordance with 30 CFR part 206. In applying the requirements of 30 CFR
part 206, the circumstances involved in the actual disposition of the
portion of the production to which the lessee was entitled but did not
take shall be considered as controlling in arriving at the value, for
royalty purposes, of that portion as though the person actually selling
or disposing of the production were the lessee of the Federal or Indian
lease.
(2) If a Federal or Indian lessee takes less than its proportionate
share of agreement production, upon request of the lessee MMS may
authorize a royalty valuation method different from that required by
paragraph (e)(1) of this section, but consistent with the purposes of
these regulations, for any volumes not taken by the lessee but for which
royalties are due.
(3) For purposes of this subchapter, all persons actually taking
volumes in excess of their proportionate share of production in any
month under a unitization or communitization agreement shall be deemed
to have taken ratably from all persons actually taking less than their
proportionate share of the agreement production for that month.
(4) If a lessee takes less than its proportionate share of agreement
production for any month but royalties are paid on the full volume of
its proportionate share in accordance with the provisions of this
section, no additional royalty will be owed for that lease for prior
periods when the lessee subsequently takes more than its proportionate
share to balance its account or when the lessee is paid a sum of money
by the other agreement participants to balance its account.
(f) For production from Federal and Indian leases which are
committed to federally-approved unitization or communitization
agreements, upon request of a lessee MMS may establish the value of
production pursuant to a method other than the method required by the
regulations in this title if: (1) The proposed method for establishing
value is consistent with the requirements of the applicable statutes,
lease terms, and agreement terms; (2) persons with an interest in the
agreement, including, to the extent practical, royalty interests, are
given notice and an opportunity to comment on the proposed valuation
method before it is authorized; and (3) to the extent practical, persons
with an interest in a Federal or Indian lease committed to the
agreement, including royalty interests, must agree to use the proposed
method for valuing production from the agreement for royalty purposes.
[53 FR 1217, Jan. 15, 1988]
[[Page 8]]
Sec. 202.101 Standards for reporting and paying royalties.
Oil volumes are to be reported in barrels of clean oil of 42
standard U.S. gallons (231 cubic inches each) at 60 [deg]F. When
reporting oil volumes for royalty purposes, corrections must have been
made for Basic Sediment and Water (BS&W) and other impurities. Reported
American Petroleum Institute (API) oil gravities are to be those
determined in accordance with standard industry procedures after
correction to 60 [deg]F.
[53 FR 1217, Jan. 15, 1988]
Subpart D_Federal Gas
Source: 53 FR 1271, Jan. 15, 1988, unless otherwise noted.
Sec. 202.150 Royalty on gas.
(a) Royalties due on gas production from leases subject to the
requirements of this subpart, except helium produced from Federal
leases, shall be at the rate established by the terms of the lease.
Royalty shall be paid in value unless MMS requires payment in kind. When
paid in value, the royalty due shall be the value, for royalty purposes,
determined pursuant to 30 CFR part 206 of this title multiplied by the
royalty rate in the lease.
(b)(1) All gas (except gas unavoidably lost or used on, or for the
benefit of, the lease, including that gas used off-lease for the benefit
of the lease when such off-lease use is permitted by the MMS or BLM, as
appropriate) produced from a Federal lease to which this subpart applies
is subject to royalty.
(2) When gas is used on, or for the benefit of, the lease at a
production facility handling production from more than one lease with
the approval of MMS or BLM, as appropriate, or at a production facility
handling unitized or communitized production, only that proportionate
share of each lease's production (actual or allocated) necessary to
operate the production facility may be used royalty free.
(3) Where the terms of any lease are inconsistent with this subpart,
the lease terms shall govern to the extent of that inconsistency.
(c) If BLM determines that gas was avoidably lost or wasted from an
onshore lease, or that gas was drained from an onshore lease for which
compensatory royalty is due, or if MMS determines that gas was avoidably
lost or wasted from an OCS lease, then the value of that gas shall be
determined in accordance with 30 CFR part 206.
(d) If a lessee receives insurance compensation for unavoidably lost
gas, royalties are due on the amount of that compensation. This
paragraph shall not apply to compensation through self-insurance.
(e)(1) In those instances where the lessee of any lease committed to
a Federally approved unitization or communitization agreement does not
actually take the proportionate share of the production attributable to
its Federal lease under the terms of the agreement, the full share of
production attributable to the lease under the terms of the agreement
nonetheless is subject to the royalty payment and reporting requirements
of this title. Except as provided in paragraph (e)(2) of this section,
the value for royalty purposes of production attributable to unitized or
communitized leases will be determined in accordance with 30 CFR part
206. In applying the requirements of 30 CFR part 206, the circumstances
involved in the actual disposition of the portion of the production to
which the lessee was entitled but did not take shall be considered as
controlling in arriving at the value for royalty purposes of that
portion, as if the person actually selling or disposing of the
production were the lessee of the Federal lease.
(2) If a Federal lessee takes less than its proportionate share of
agreement production, upon request of the lessee MMS may authorize a
royalty valuation method different from that required by paragraph
(e)(1) of this section, but consistent with the purpose of these
regulations, for any volumes not taken by the lessee but for which
royalties are due.
(3) For purposes of this subchapter, all persons actually taking
volumes in excess of their proportionate share of production in any
month under a unitization or communitization agreement shall be deemed
to have taken ratably from all persons actually taking less
[[Page 9]]
than their proportionate share of the agreement production for that
month.
(4) If a lessee takes less than its proportionate share of agreement
production for any month but royalties are paid on the full volume of
its proportionate share in accordance with the provisions of this
section, no additional royalty will be owed for that lease for prior
periods at the time the lessee subsequently takes more than its
proportionate share to balance its account or when the lessee is paid a
sum of money by the other agreement participants to balance its account.
(f) For production from Federal leases which are committed to
federally-approved unitization or communitization agreements, upon
request of a lessee MMS may establish the value of production pursuant
to a method other than the method required by the regulations in this
title if: (1) The proposed method for establishing value is consistent
with the requirements of the applicable statutes, lease terms and
agreement terms; (2) to the extent practical, persons with an interest
in the agreement, including royalty interests, are given notice and an
opportunity to comment on the proposed valuation method before it is
authorized; and (3) to the extent practical, persons with an interest in
a Federal lease committed to the agreement, including royalty interests,
must agree to use the proposed method for valuing production from the
agreement for royalty purposes.
[53 FR 1271, Jan. 15, 1988, as amended at 64 FR 43513, Aug. 10, 1999]
Sec. 202.151 Royalty on processed gas.
(a)(1) A royalty, as provided in the lease, shall be paid on the
value of:
(i) Any condensate recovered downstream of the point of royalty
settlement without resorting to processing; and
(ii) Residue gas and all gas plant products resulting from
processing the gas produced from a lease subject to this subpart.
(2) MMS shall authorize a processing allowance for the reasonable,
actual costs of processing the gas produced from Federal leases.
Processing allowances shall be determined in accordance with 30 CFR part
206 subpart D for gas production from Federal leases and 30 CFR part 206
subpart E for gas production from Indian leases.
(b) A reasonable amount of residue gas shall be allowed royalty free
for operation of the processing plant, but no allowance shall be made
for boosting residue gas or other expenses incidental to marketing,
except as provided in 30 CFR part 206. In those situations where a
processing plant processes gas from more than one lease, only that
proportionate share of each lease's residue gas necessary for the
operation of the processing plant shall be allowed royalty free.
(c) No royalty is due on residue gas, or any gas plant product
resulting from processing gas, which is reinjected into a reservoir
within the same lease, unit area, or communitized area, when the
reinjection is included in a plan of development or operations and the
plan has received BLM or MMS approval for onshore or offshore
operations, respectively, until such time as they are finally produced
from the reservoir for sale or other disposition off-lease.
[53 FR 1217, Jan. 15, 1988, as amended at 61 FR 5490, Feb. 12, 1996; 64
FR 43513, Aug. 10, 1999]
Sec. 202.152 Standards for reporting and paying royalties on gas.
(a)(1) If you are responsible for reporting production or royalties,
you must:
(i) Report gas volumes and British thermal unit (Btu) heating
values, if applicable, under the same degree of water saturation;
(ii) Report gas volumes in units of 1,000 cubic feet (mcf); and
(iii) Report gas volumes and Btu heating value at a standard
pressure base of 14.73 pounds per square inch absolute (psia) and a
standard temperature base of 60 [deg]F.
(2) The frequency and method of Btu measurement as set forth in the
lessee's contract shall be used to determine Btu heating values for
reporting purposes. However, the lessee shall measure the Btu value at
least semiannually by recognized standard industry testing methods even
if the lessee's contract provides for less frequent measurement.
[[Page 10]]
(b)(1) Residue gas and gas plant product volumes shall be reported
as specified in this paragraph.
(2) Carbon dioxide (CO2), nitrogen (N2),
helium (He), residue gas, and any other gas marketed as a separate
product shall be reported by using the same standards specified in
paragraph (a) of this section.
(3) Natural gas liquids (NGL) volumes shall be reported in standard
U.S. gallons (231 cubic inches) at 60 [deg]F.
(4) Sulfur (S) volumes shall be reported in long tons (2,240
pounds).
[53 FR 1271, Jan. 15, 1988, as amended at 63 FR 26367, May 12, 1998]
Subpart E--Solid Minerals, General [Reserved]
Subpart F_Coal
Sec. 202.250 Overriding royalty interest.
The regulations governing overriding royalty interests, production
payments, or similar interests created under Federal coal leases are in
43 CFR group 3400.
[54 FR 1522, Jan. 13, 1989]
Subpart G--Other Solid Minerals [Reserved]
Subpart H_Geothermal Resources
Source: 56 FR 57275, Nov. 8, 1991, unless otherwise noted.
Sec. 202.350 Scope and definitions.
(a) This subpart is applicable to all geothermal resources produced
from Federal geothermal leases issued pursuant to the Geothermal Steam
Act of 1970, as amended (30 U.S.C. 1001 et seq.).
(b) The definitions in 30 CFR 206.351 are applicable to this
subpart.
Sec. 202.351 Royalties on geothermal resources.
(a)(1) Royalties on geothermal resources, including byproducts, or
on electricity produced using geothermal resources, will be at the
royalty rate(s) specified in the lease, unless the Secretary of the
Interior temporarily waives, suspends, or reduces that rate(s).
Royalties are determined under 30 CFR part 206, subpart H.
(2) Fees in lieu of royalties on geothermal resources are prescribed
in 30 CFR part 206, subpart H.
(3) Except for the amount credited against royalties for in-kind
deliveries of electricity to a State or county under Sec. 218.306, you
must pay royalties and direct use fees in money.
(b)(1) Except as specified in paragraph (b)(2) of this section,
royalties or fees are due on--
(i) All geothermal resources produced from a lease and that are sold
or used by the lessee or are reasonably susceptible to sale or use by
the lessee, or
(ii) All proceeds derived from the sale of electricity produced
using geothermal resources produced from a lease.
(2) For purposes of this subparagraph, the terms ``Class I lease,''
``Class II lease,'' and ``Class III lease'' have the same meanings
prescribed in 30 CFR 206.351.
(i) For Class I leases, MMS will allow free of royalty--
(A) Geothermal resources that are unavoidably lost or reinjected
before use on or off the lease, as determined by the Bureau of Land
Management (BLM), or that are reasonably necessary to generate plant
parasitic electricity or electricity for Federal lease operations; and
(B) A reasonable amount of commercially demineralized water
necessary for power plant operations or otherwise used on or for the
benefit of the lease.
(ii) For Class II and Class III leases where the lessee uses
geothermal resources for commercial production or generation of
electricity, or where geothermal resources are sold at arm's length for
the commercial production or generation of electricity, MMS will allow
free of royalty or direct use fees geothermal resources that are:
(A) Unavoidably lost or reinjected before use on or off the lease,
as determined by BLM;
(B) Reasonably necessary for the lessee to generate plant parasitic
electricity or electricity for Federal lease operations, as approved by
BLM; or
[[Page 11]]
(C) Otherwise used for Federal lease operations related to
commercial production or generation of electricity, as approved by BLM.
(iii) For Class II and Class III leases where the lessee uses the
geothermal resources for a direct use or in a direct use facility, as
defined in 30 CFR 206.351, resources that are used to generate
electricity for Federal lease operations or that are otherwise used for
Federal lease operations are subject to direct use fees, except for
geothermal resources that are unavoidably lost or reinjected before use
on or off the lease, as determined by BLM.
(3) Royalties on byproducts are due at the time the recovered
byproduct is used, sold, or otherwise finally disposed of. Byproducts
produced and added to stockpiles or inventory do not require payment of
royalty until the byproducts are sold, utilized, or otherwise finally
disposed of. The MMS may ask BLM to increase the lease bond to protect
the lessor's interest when BLM determines that stockpiles or inventories
become excessive.
(c) If BLM determines that geothermal resources (including
byproducts) were avoidably lost or wasted from the lease, or that
geothermal resources (including byproducts) were drained from the lease
for which compensatory royalty (or compensatory fees in lieu of
compensatory royalty) are due, the value of those geothermal resources,
or the royalty or fees owed, will be determined under 30 CFR part 206,
subpart H.
(d) If a lessee receives insurance or other compensation for
unavoidably lost geothermal resources (including byproducts), royalties
at the rates specified in the lease (or fees in lieu of royalties) are
due on the amount of, or as a result of, that compensation. This
paragraph will not apply to compensation through self-insurance.
[72 FR 24458, May 2, 2007]
Sec. 202.352 Minimum royalty.
In no event shall the lessee's annual royalty payments for any
producing lease be less than the minimum royalty established by the
lease.
Sec. 202.353 Measurement standards for reporting and paying royalties and
direct use fees.
(a) For geothermal resources used to generate electricity, you must
report the quantity on which royalty is due on Form MMS-2014 (Report of
Sales and Royalty Remittance) as follows:
(1) For geothermal resources for which royalty is calculated under
Sec. 206.352(a), you must report quantities in:
(i) Thousands of pounds to the nearest whole thousand pounds if the
contract for the geothermal resources specifies delivery in terms of
weight; or
(ii) Millions of Btu to the nearest whole million Btu if the sales
contract for the geothermal resources specifies delivery in terms of
heat or thermal energy.
(2) For geothermal resources for which royalty is calculated under
Sec. 206.352(b), you must report the quantities in kilowatt-hours to
the nearest whole kilowatt-hour.
(b) For geothermal resources used in direct use processes, you must
report the quantity on which a royalty or direct use fee is due on Form
MMS-2014 in:
(1) Millions of Btu to the nearest whole million Btu if valuation is
in terms of heat or thermal energy used or displaced;
(2) Millions of gallons to the nearest million gallons of geothermal
fluid produced if valuation or fee calculation is in terms of volume;
(3) Millions of pounds to the nearest million pounds of geothermal
fluid produced if valuation or fee calculation is in terms of mass; or
(4) Any other measurement unit MMS approves for valuation and
reporting purposes.
(c) For byproducts, you must report the quantity on which royalty is
due on Form MMS-2014 consistent with MMS-established reporting
standards.
(d) For commercially demineralized water, you must report the
quantity on which royalty is due on Form MMS-2014 in hundreds of gallons
to the nearest hundred gallons.
(e) You need not report the quality of geothermal resources,
including byproducts, to MMS. However, you must maintain quality
measurements for
[[Page 12]]
audit purposes. Quality measurements include, but are not limited to:
(1) Temperatures and chemical analyses for fluid geothermal
resources; and
(2) Chemical analyses, weight percent, or other purity measurements
for byproducts.
[72 FR 24458, May 2, 2007]
Subpart I--OCS Sulfur [Reserved]
Subpart J_Gas Production From Indian Leases
Source: 64 FR 43514, Aug. 10, 1999, unless otherwise noted.
Sec. 202.550 How do I determine the royalty due on gas production?
If you produce gas from an Indian lease subject to this subpart, you
must determine and pay royalties on gas production as specified in this
section.
(a) Royalty rate. You must calculate your royalty using the royalty
rate in the lease.
(b) Payment in value or in kind. You must pay royalty in value
unless:
(1) The Tribal lessor requires payment in kind; or
(2) You have a lease on allotted lands and MMS requires payment in
kind.
(c) Royalty calculation. You must use the following calculations to
determine royalty due on the production from or attributable to your
lease.
(1) When paid in value, the royalty due is the unit value of
production for royalty purposes, determined under 30 CFR part 206,
multiplied by the volume of production multiplied by the royalty rate in
the lease.
(2) When paid in kind, the royalty due is the volume of production
multiplied by the royalty rate.
(d) Reduced royalty rate. The Indian lessor and the Secretary may
approve a request for a royalty rate reduction. In your request you must
demonstrate economic hardship.
(e) Reporting and paying. You must report and pay royalties as
provided in part 218 of this title.
Sec. 202.551 How do I determine the volume of production for which I must pay royalty if my lease is not in an approved Federal unit or communitization
agreement (AFA)?
(a) You are liable for royalty on your entitled share of gas
production from your Indian lease, except as provided in Sec. Sec.
202.555, 202.556, and 202.557.
(b) You and all other persons paying royalties on the lease must
report and pay royalties based on your takes. If another person takes
some of your entitled share but does not pay the royalties owed, you are
liable for those royalties.
(c) You and all other persons paying royalties on the lease may ask
MMS for permission to report and pay royalties based on your
entitlements. In that event, MMS will provide valuation instructions
consistent with this part and part 206 of this title.
Sec. 202.552 How do I determine how much royalty I must pay if my lease is
in an approved Federal unit or communitization agreement (AFA)?
You must pay royalties each month on production allocated to your
lease under the terms of an AFA. To determine the volume and the value
of your production, you must follow these three steps:
(a) You must determine the volume of your entitled share of
production allocated to your lease under the terms of an AFA. This may
include production from more than one AFA.
(b) You must value the production you take using 30 CFR part 206. If
you take more than your entitled share of production, see Sec. 202.553
for information on how to value this production. If you take less than
your entitled share of production, see Sec. 202.554 for information on
how to value production you are entitled to but do not take.
Sec. 202.553 How do I value my production if I take more than my entitled
share?
If you take more than your entitled share of production from a lease
in an AFA for any month, you must determine the weighted-average value
of all of the production that you take using the procedures in 30 CFR
part 206, and use that value for your entitled share of production.
[[Page 13]]
Sec. 202.554 How do I value my production that I do not take if I take less
than my entitled share?
If you take none or only part of your entitled production from a
lease in an AFA for any month, use this section to value the production
that you are entitled to but do not take.
(a) If you take a significant volume of production from your lease
during the month, you must determine the weighted average value of the
production that you take using 30 CFR part 206, and use that value for
the production that you do not take.
(b) If you do not take a significant volume of production from your
lease during the month, you must use paragraph (c) or (d) of this
section, whichever applies.
(c) In a month where you do not take production or take an
insignificant volume, and if you would have used Sec. 206.172(b) to
value the production if you had taken it, you must determine the value
of production not taken for that month under Sec. 206.172(b) as if you
had taken it.
(d) If you take none of your entitled share of production from a
lease in an AFA, and if that production cannot be valued under Sec.
206.172(b), then you must determine the value of the production that you
do not take using the first of the following methods that applies:
(1) The weighted average of the value of your production (under 30
CFR part 206) in that month from other leases in the same AFA.
(2) The weighted average of the value of your production (under 30
CFR part 206) in that month from other leases in the same field or area.
(3) The weighted average of the value of your production (under 30
CFR part 206) during the previous month for production from leases in
the same AFA.
(4) The weighted average of the value of your production (under 30
CFR part 206) during the previous month for production from other leases
in the same field or area.
(5) The latest major portion value that you received from MMS
calculated under 30 CFR 206.174 for the same MMS-designated area.
(e) You may take less than your entitled share of AFA production for
any month, but pay royalties on the full volume of your entitled share
under this section. If you do, you will owe no additional royalty for
that lease for that month when you later take more than your entitled
share to balance your account. The provisions of this paragraph (e) also
apply when the other AFA participants pay you money to balance your
account.
Sec. 202.555 What portion of the gas that I produce is subject to royalty?
(a) All gas produced from or allocated to your Indian lease is
subject to royalty except the following:
(1) Gas that is unavoidably lost.
(2) Gas that is used on, or for the benefit of, the lease.
(3) Gas that is used off-lease for the benefit of the lease when the
Bureau of Land Management (BLM) approves such off-lease use.
(4) Gas used as plant fuel as provided in 30 CFR 206.179(e).
(b) You may use royalty-free only that proportionate share of each
lease's production (actual or allocated) necessary to operate the
production facility when you use gas for one of the following purposes:
(1) On, or for the benefit of, the lease at a production facility
handling production from more than one lease with BLM's approval.
(2) At a production facility handling unitized or communitized
production.
(c) If the terms of your lease are inconsistent with this subpart,
your lease terms will govern to the extent of that inconsistency.
Sec. 202.556 How do I determine the value of avoidably lost, wasted, or
drained gas?
If BLM determines that a volume of gas was avoidably lost or wasted,
or a volume of gas was drained from your Indian lease for which
compensatory royalty is due, then you must determine the value of that
volume of gas under 30 CFR part 206.
Sec. 202.557 Must I pay royalty on insurance compensation for unavoidably
lost gas?
If you receive insurance compensation for unavoidably lost gas, you
must pay royalties on the amount of that compensation. This paragraph
does not
[[Page 14]]
apply to compensation through self-insurance.
Sec. 202.558 What standards do I use to report and pay royalties on gas?
(a) You must report gas volumes as follows:
(1) Report gas volumes and Btu heating values, if applicable, under
the same degree of water saturation. Report gas volumes and Btu heating
value at a standard pressure base of 14.73 psia and a standard
temperature of 60 degrees Fahrenheit. Report gas volumes in units of
1,000 cubic feet (Mcf).
(2) You must use the frequency and method of Btu measurement stated
in your contract to determine Btu heating values for reporting purposes.
However, you must measure the Btu value at least semi-annually by
recognized standard industry testing methods even if your contract
provides for less frequent measurement.
(b) You must report residue gas and gas plant product volumes as
follows:
(1) Report carbon dioxide (CO2), nitrogen
(N2), helium (He), residue gas, and any gas marketed as a
separate product by using the same standards specified in paragraph (a)
of this section.
(2) Report natural gas liquid (NGL) volumes in standard U.S. gallons
(231 cubic inches) at 60 degrees F.
(3) Report sulfur (S) volumes in long tons (2,240 pounds).
PART 203_RELIEF OR REDUCTION IN ROYALTY RATES--Table of Contents
Subpart A_General Provisions
Sec.
203.0 What definitions apply to this part?
203.1 What is MMS's authority to grant royalty relief?
203.2 How can I get royalty relief?
203.3 Why must I pay a fee to request royalty relief?
203.4 How do the provisions in this part apply to different types of
leases and projects?
203.5 What is MMS's authority to collect information?
Subpart B_OCS Oil, Gas, and Sulfur General
Royalty Relief for Drilling Deep Gas Wells on Leases Not Subject to Deep
Water Royalty Relief
203.40 Which leases are eligible for royalty relief as a result of
drilling deep wells?
203.41 If I have a qualified well, what royalty relief will my lease
earn?
203.42 To which production do I apply the royalty suspension volume
earned from qualified wells on my lease?
203.43 What administrative steps must I take to use the royalty
suspension volume?
203.44 If I drill a certified unsuccessful well, what royalty relief
will my lease earn?
203.45 To which production do I apply the royalty suspension supplements
from drilling one or two certified unsuccessful wells on my
lease?
203.46 What administrative steps do I take to obtain and use the royalty
suspension supplement?
203.47 Do I keep royalty relief if prices rise significantly?
203.48 May I substitute the deep gas drilling provisions in Sec. 203.0
and Sec. Sec. 203.40 through 203.47 for the deep gas royalty
relief provided in my lease terms?
Royalty Relief for end-of-life Leases
203.50 Who may apply for end-of-life royalty relief?
203.51 How do I apply for end-of-life royalty relief?
203.52 What criteria must I meet to get relief?
203.53 What relief will MMS grant?
203.54 How does my relief arrangement for an oil and gas lease operate
if prices rise sharply?
203.55 Under what conditions can my end-of-life royalty relief
arrangement for an oil and gas lease be ended?
203.56 Does relief transfer when a lease is assigned?
Royalty Relief For Deep Water Expansion Projects And Pre-Act Deep Water
Leases
203.60 Who may apply for deep water royalty relief?
203.61 How do I assess my chances for getting relief?
203.62 How do I apply for relief?
203.63 Does my application have to include all leases in the field?
203.64 How many applications may I file on a field or a development
project?
203.65 How long will MMS take to evaluate my application?
203.66 What happens if MMS does not act in the time allowed?
[[Page 15]]
203.67 What economic criteria must I meet to get royalty relief on an
authorized field or project?
203.68 What pre-application costs will MMS consider in determining
economic viability?
203.69 If my application is approved, what royalty relief will I
receive?
203.70 What information must I provide after MMS approves relief?
203.71 How does MMS allocate a field's suspension volume between my
lease and other leases on my field?
203.72 Can my lease receive more than one suspension volume?
203.73 How do suspension volumes apply to natural gas?
203.74 When will MMS reconsider its determination?
203.75 What risk do I run if I request a redetermination?
203.76 When might MMS withdraw or reduce the approved size of my relief?
203.77 May I voluntarily give up relief if conditions change?
203.78 Do I keep relief if prices rise significantly?
203.79 How do I appeal MMS's decisions related to Deep Water Royalty
Relief?
203.80 When can I get royalty relief if I am not eligible for end-of-
life or deep water royalty relief?
Required Reports
203.81 What supplemental reports do royalty-relief applications require?
203.82 What is MMS's authority to collect this information?
203.83 What is in an administrative information report?
203.84 What is in a net revenue and relief justification report?
203.85 What is in an economic viability and relief justification report?
203.86 What is in a G&G report?
203.87 What is in an engineering report?
203.88 What is in a production report?
203.89 What is in a deep water cost report?
203.90 What is in a fabricator's confirmation report?
203.91 What is in a post-production development report?
Subpart C--Federal and Indian Oil [Reserved]
Subpart D--Federal and Indian Gas [Reserved]
Subpart E--Solid Minerals, General [Reserved]
Subpart F_Coal
203.250 Advance royalty.
203.251 Reduction in royalty rate or rental.
Subpart G--Other Solid Minerals [Reserved]
Subpart H--Geothermal Resources [Reserved]
Subpart I--OCS Sulfur [Reserved]
Authority: 25 U.S.C. 396 et seq.; 25 U.S.C. 396a et seq.; 25 U.S.C.
2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.; 30 U.S.C.
1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et
seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C. 1801 et seq.
Subpart A_General Provisions
Source: 63 FR 2616, Jan. 16, 1998, unless otherwise noted.
Sec. 203.0 What definitions apply to this part?
Authorized field means a field:
(1) Located in a water depth of at least 200 meters and in the Gulf
of Mexico (GOM) west of 87 degrees, 30 minutes West longitude;
(2) That includes one or more pre-Act leases; and
(3) From which no current pre-Act lease produced, other than test
production, before November 28, 1995.
Certified unsuccessful well means an original well, or a sidetrack
with a sidetrack measured depth of at least 10,000 feet, on your lease
that:
(1) You begin drilling on or after March 26, 2003, and before May 3,
2009, and before your lease produces gas or oil from a deep well with a
perforated interval the top of which is at least 18,000 feet true
vertical depth below the datum at mean sea level (TVD SS);
(2) You drill to at least 18,000 feet TVD SS with a target reservoir
on your lease, identified from seismic and related data, deeper than
that depth;
(3) Fails to meet the producibility requirements of 30 CFR part 250,
subpart A, and does not produce gas or oil, or the MMS agrees is not
commercially producible; and
(4) For which you have provided the notices and information in Sec.
203.46.
Complete application means an original and two copies of the six
reports consisting of the data specified in 30 CFR 203.81, 203.83 and
203.85 through
[[Page 16]]
203.89, along with one set of digital information, which MMS has
reviewed and found complete.
Deep well means either an original well or a sidetrack with a
perforated interval the top of which is at least 15,000 feet TVD SS. A
deep well subsequently re-perforated less than 15,000 feet TVD SS in the
same reservoir is still a deep well.
Determination means the binding decision by MMS on whether your
field qualifies for relief or how large a royalty-suspension volume must
be to make the field economically viable.
Development project means a project to develop one or more oil or
gas reservoirs located on one or more contiguous leases that:
(1) Were issued in a sale held after November 28, 2000;
(2) Are located in a water depth of at least 200 meters and in the
GOM wholly west of 87 degrees, 30 minutes West longitude; and
(3) Have had no production (other than test production) before the
current application for royalty relief.
Draft application means the preliminary set of information and
assumptions you submit to seek a nonbinding assessment on whether a
field could be expected to qualify for royalty relief.
Eligible lease means a lease that:
(1) Is issued as part of an OCS lease sale held after November 28,
1995, and before November 28, 2000;
(2) Is located in the Gulf of Mexico in water depths of 200 meters
or deeper;
(3) Lies wholly west of 87 degrees, 30 minutes West longitude; and
(4) Is offered subject to a royalty suspension volume.
Expansion project means a project you propose in a Development
Operations Coordination Document (DOCD) or a Supplement approved by the
Secretary of the Interior after November 28, 1995, that will
significantly increase the ultimate recovery of resources from one or
more reservoirs that have not produced on a pre-Act lease or a lease
issued in a sale held after November 28, 2000. A significant increase
does not simply extend recovery from reservoirs already in production.
For a pre-Act lease, the expansion project must also involve a
substantial capital investment (e.g., fixed-leg platform, subsea
template and manifold, tension-leg platform, multiple well project,
etc.). For a lease issued after November 28, 2000, the expansion project
must involve a new well drilled into a reservoir that has not previously
produced. In all cases, all leases in an expansion project must be
wholly located in a water depth of at least 200 meters and in the GOM
wholly west of 87 degrees, 30 minutes West longitude.
Fabrication (or start of construction) means evidence of an
irreversible commitment to a concept and scale of development. Evidence
includes copies of a binding contract between you (as applicant) and a
fabrication yard, a letter from a fabricator certifying that continuous
construction has begun, and a receipt for the customary down payment.
Field means an area consisting of a single reservoir or multiple
reservoirs all grouped on, or related to, the same general geological
structural feature or stratigraphic trapping condition. Two or more
reservoirs may be in a field, separated vertically by intervening
impervious strata or laterally by local geologic barriers, or both.
Lease means a lease or unit.
New production means any production from a current pre-Act lease
from which no royalties are due on production, other than test
production, before November 28, 1995. Also, it means any additional
production resulting from new lease-development activities on a lease
issued in a sale after November 28, 2000, or a current pre-Act lease
under a DOCD or a Supplement approved by the Secretary of the Interior
after November, 28, 1995.
Nonbinding assessment means an opinion by MMS of whether your field
could qualify for royalty relief. It is based on your draft application
and does not entitle the field to relief.
Original well means a well that is drilled without utilizing an
existing wellbore. An original well includes all sidetracks drilled from
the original wellbore before the drilling rig moves off the well
location. A bypass from an original well (e.g., drilling around material
blocking the hole or to straighten crooked holes) is part of the
original well.
[[Page 17]]
Participating area means that part of the unit area that MMS
determines is reasonably proven by drilling and completion of producible
wells, geological and geophysical information, and engineering data to
be capable of producing hydrocarbons in paying quantities.
Performance conditions means minimum conditions you must meet, after
we have granted relief and before production begins, to remain qualified
for that relief. If you do not meet each one of these performance
conditions, we consider it a change in material fact significant enough
to invalidate our original evaluation and approval.
Pre-Act lease means a lease that:
(1) Results from a sale held before November 28, 1995;
(2) Is located in the GOM in water depths of 200 meters or deeper;
and
(3) Lies wholly west of 87 degrees, 30 minutes West longitude.
Production means all oil, gas, and other relevant products you save,
remove, or sell from a tract or those quantities allocated to your tract
under a unitization formula, as measured for the purposes of determining
the amount of royalty payable to the United States.
Project means any activity that requires at least a permit to drill.
Qualified well means a deep well:
(1) For which drilling begins on or after March 26, 2003;
(2) That produces natural gas (other than test production),
including gas associated with oil production, before May 3, 2009; and
(3) For which you have met the requirements prescribed in Sec.
203.43.
Redetermination means our reconsideration of our determination on
royalty relief because you request it after:
(1) We have rejected your application;
(2) We have granted relief but you want a larger suspension volume;
(3) We withdraw approval; or
(4) You renounce royalty relief.
Renounce means action you take to give up relief after we have
granted it and before you start production.
Reservoir means an underground accumulation of oil or natural gas,
or both, characterized by a single pressure system and segregated from
other such accumulations.
Royalty suspension (RS) lease means a lease that:
(1) Is issued as part of an OCS lease sale held after November 28,
2000;
(2) Is in locations or planning areas specified in a particular
Notice of OCS Lease Sale offering that lease; and
(3) Is offered subject to a royalty suspension specified in a Notice
of OCS Lease Sale published in the Federal Register.
Royalty suspension supplement means a royalty suspension volume
resulting from drilling a certified unsuccessful well that is applied to
future natural gas and oil production generated at any drilling depth
on, or allocated under an MMS-approved unit agreement to, the same
lease.
Royalty suspension volume means a volume of production from a lease
that is not subject to royalty under the provisions of this part.
Sidetrack means, for the purpose of this subpart, a well resulting
from drilling an additional hole to a new objective bottom-hole location
by leaving a previously drilled hole. A sidetrack also includes drilling
a well from a platform slot reclaimed from a previously drilled well or
re-entering and deepening a previously drilled well. A bypass from a
sidetrack (e.g., drilling around material blocking the hole, or to
straighten crooked holes) is part of the sidetrack.
Sidetrack measured depth means the actual distance or length in feet
a sidetrack is drilled beginning where it exits a previously drilled
hole to the bottom hole of the sidetrack, that is, to its total depth.
Sunk costs for an authorized field means the after-tax eligible
costs that you (not third parties) incur for exploration, development,
and production from the spud date of the first discovery on the field to
the date we receive your complete application for royalty relief. The
discovery well must be qualified as producible under part 250, subpart A
of this title. Sunk costs include the rig mobilization and material
costs for the discovery well that you incurred before its spud date.
Sunk costs for an expansion or development project means the after-
tax eligible costs that you (not third parties)
[[Page 18]]
incur for only the first well that encounters hydrocarbons in the
reservoir(s) included in the application and that meets the
producibility requirements under part 250, subpart A of this chapter on
each lease participating in the application. Sunk costs include rig
mobilization and material costs for the discovery wells that you
incurred before their spud dates.
Withdraw means action we take on a field that has qualified for
relief if you have not met one or more of the performance conditions.
[63 FR 2616, Jan. 16, 1998, as amended at 67 FR 1872, Jan. 15, 2002; 69
FR 3509, Jan. 26, 2004; 69 FR 24053, Apr. 30, 2004]
Sec. 203.1 What is MMS's authority to grant royalty relief?
The Outer Continental Shelf (OCS) Lands Act, 43 U.S.C. 1337, as
amended by the OCS Deep Water Royalty Relief Act (DWRRA), Public Law
104-58, authorizes us to grant royalty relief in three situations.
(a) Under 43 U.S.C. 1337(a)(3)(A), we may reduce or eliminate any
royalty or a net profit share specified for an OCS lease to promote
increased production.
(b) Under 43 U.S.C. 1337(a)(3)(B), we may reduce, modify, or
eliminate any royalty or net profit share to promote development,
increase production, or encourage production of marginal resources on
certain leases or categories of leases. This authority is restricted to
leases in the Gulf of Mexico (GOM) that are west of 87 degrees, 30
minutes West longitude.
(c) Under 43 U.S.C. 1337(a)(3)(C), we may suspend royalties for
designated volumes of new production from any lease if:
(1) Your lease is in deep water (water at least 200 meters deep);
(2) Your lease is in designated areas of the GOM (west of 87
degrees, 30 minutes West longitude);
(3) Your lease was acquired in a lease sale held before the DWRRA
(before November 28, 1995);
(4) We find that your new production would not be economic without
royalty relief; and
(5) Your lease is on a field that did not produce before enactment
of the DWRRA, or if you propose a project to significantly expand
production under a Development Operations Coordination Document (DOCD)
or a supplementary DOCD, that MMS approved after November 28, 1995.
Sec. 203.2 How can I get royalty relief?
We may reduce or suspend royalties for Outer Continental Shelf (OCS)
leases or projects that meet the criteria in the following table.
------------------------------------------------------------------------
Then we may grant
If you have a lease . . . And if you . . . you . . .
------------------------------------------------------------------------
(a) With earnings that cannot Would abandon A reduced royalty
sustain production (i.e., End- otherwise rate on current
of-life lease). potentially monthly
recoverable production and a
resources but higher royalty
seek to increase rate on
production by additional
operating beyond monthly
the point at production. (See
which the lease Sec. Sec.
is economic under 203.50 through
the existing 203.56.)
royalty rate.
(b) Located in a designated GOM Are producing and A royalty
deep water area, and acquired seek to increase suspension for
in a lease sale before November ultimate resource additional
28, 1995, or after November 28, recovery from one production large
2000, and you propose in a DOCD or more enough to make
or supplement to expand reservoirs not the project
production significantly. previously or economic. (See
currently Sec. Sec.
producing on the 203.60 through
field or lease, 203.79.)
not simply extend
recovery of
reservoirs that
already produced.
(Expansion
project).
(c) Located in a designated GOM Are on a field A royalty
deep water area and acquired in from which no suspension for a
a lease sale held before current pre-Act minimum
November 28, 1995 (Pre-Act lease produced production volume
lease). (other than test plus any
production) additional volume
before November needed to make
28, 1995 the field
(Authorized economic. (See
field). Sec. Sec.
203.60 through
203.79.)
(d) Located in a designated GOM Have not produced A royalty
deep water area and acquired in and can suspension for a
a lease sale held after demonstrate that minimum
November 28, 2000. the suspension production volume
volume, if any, plus any
in your lease is additional volume
not enough to needed to make
make development your project
economic economic. (See
(Development Sec. Sec.
project). 203.60 through
203.79.)
(e) Where royalty relief would Are not eligible A royalty
recover significant additional to apply for end- modification in
resources or, in certain areas of-life or deep size, duration,
of the GOM, would enable water royalty or form that
development. relief, but show makes your lease
us you meet or project
certain economic. (See
elligibility Sec. 203.80.)
conditions.
------------------------------------------------------------------------
[[Page 19]]
[67 FR 1872, Jan. 15, 2002]
Sec. 203.3 Why must I pay a fee to request royalty relief?
(a) When you submit an application or ask for a preview assessment,
you must include a fee to reimburse us for our costs of processing your
application or assessment. Federal policy and law require us to recover
the cost of services that confer special benefits to identifiable non-
Federal recipients. The Independent Offices Appropriation Act (31 U.S.C.
9701), Office of Management and Budget Circular A-25, and the Omnibus
Appropriations Bill (Pub. L. 104-133, 110 Stat. 1321, April 26, 1996)
authorize us to collect these fees.
(b) We will specify the necessary fees for each of the types of
royalty-relief applications and possible MMS audits in a Notice to
Lessees. We will periodically update the fees to reflect changes in
costs as well as provide other information necessary to administer
royalty relief.
Sec. 203.4 How do the provisions in this part apply to different types of
leases and projects?
The tables in this section summarize the similar application and
approval provisions for the discretionary end-of-life and deep water
royalty relief programs in Sec. Sec. 203.50 to 203.91. Because royalty
relief for deep gas on leases not subject to deep water royalty relief,
as provided for under Sec. Sec. 203.40 to 203.48, does not involve an
application, its provisions do not parallel the other two royalty relief
programs and are not summarized in this section.
(a) We require the information elements indicated by an X in the
following table and described in Sec. Sec. 203.51, 203.62, and 203.81
through 203.89 for applications for royalty relief.
----------------------------------------------------------------------------------------------------------------
Deep water
End-of- ------------------------------------------
Information elements life Expansion Pre-act Development
lease project lease project
----------------------------------------------------------------------------------------------------------------
(1) Administrative information report..................... X X X X
(2) Net revenue and relief justification report X
(prescribed format)......................................
(3) Economic viability and relief justification report ......... X X X
(Royalty Suspension Viability Program (RSVP) model inputs
justified with Geological and Geophysical (G&G),
Engineering, Production, & Cost reports).................
(4) G&G report............................................ ......... X X X
(5) Engineering report.................................... ......... X X X
(6) Production report..................................... ......... X X X
(7) Deep water cost report................................ ......... X X X
----------------------------------------------------------------------------------------------------------------
(b) We require the confirmation elements indicated by an X in the
following table and described in Sec. Sec. 203.70, 203.81 and 203.90
through 203.91 to retain royalty relief.
----------------------------------------------------------------------------------------------------------------
Deep water
End-of- ------------------------------------------
Confirmation elements life Expansion Pre-act Development
lease project lease project
----------------------------------------------------------------------------------------------------------------
(1) Fabricator's confirmation report...................... ......... X X X
(2) Post-production development report approved by an ......... X X X
independent certified public accountant (CPA)............
----------------------------------------------------------------------------------------------------------------
(c) The following table indicates by an X, and Sec. Sec. 203.50,
203.52, 203.60 and 203.67 describe, the prerequisites for our approval
of your royalty relief application.
[[Page 20]]
----------------------------------------------------------------------------------------------------------------
Deep water
End-of- ------------------------------------------
Approval conditions life Pre-act Development
lease Expansion lease project
----------------------------------------------------------------------------------------------------------------
(1) At least 12 of the last 15 months have the required X
level of production......................................
(2) Already producing..................................... X
(3)A producible well into a reservoir that has not ......... X X X
produced before..........................................
(4) Royalties for qualifying months exceed 75% of net X
revenue (NR).............................................
(5) Substantial investment on a pre-Act lease (e.g.,
platform, subsea template)...............................
(6) Determined to be economic only with relief............ ......... X X X
----------------------------------------------------------------------------------------------------------------
(d) The following table indicates by an X, and Sec. Sec. 203.52 and
203.74 through 203.75 describe, the prerequisites for a redetermination
of our royalty relief decision.
----------------------------------------------------------------------------------------------------------------
Deep water
End-of- ------------------------------------------
Redetermination conditions Life Expansion Pre-act Development
lease project lease project
----------------------------------------------------------------------------------------------------------------
(1) After 12 months under current rate, criteria same as X
for approval.............................................
(2) For material change in geologic data, prices, costs, ......... X X X
or available technology..................................
----------------------------------------------------------------------------------------------------------------
(e) The following table indicates by an X, and Sec. Sec. 203.53 and
203.69 describe, the characteristics of approved royalty relief.
----------------------------------------------------------------------------------------------------------------
Deep water
End-of- ------------------------------------------
Relief rate and volume, subject to certain conditions life Expansion Pre-act Development
lease project lease project
----------------------------------------------------------------------------------------------------------------
(1) One-half pre-application effective lease rate on the X
qualifying amount, 1.5 times pre-application effective
lease rate on additional production up to twice the
qualifying amount, and the pre-application effective
lease rate for any larger volumes........................
(2) Qualifying amount is the average monthly production X
for 12 qualifying months.................................
(3) Zero royalty rate on the suspension volume and the ......... X X X
original lease rate on additional production.............
(4) Suspension volume is at least 17.5, 52.5 or 87.5 ......... .............. X
million barrels of oil equivalent (MMBOE)................
(5) Suspension volume is at least the minimum set in the ......... X ......... X
Notice of Sale, the lease, or the regulations............
(6) Amount needed to become economic...................... ......... X X X
----------------------------------------------------------------------------------------------------------------
(f) The following table indicates by an X, and Sec. Sec. 203.54 and
203.78 describe, circumstances under which we discontinue your royalty
relief.
----------------------------------------------------------------------------------------------------------------
Deep water
End-of- ------------------------------------------
Full royalty resumes when life Expansion Pre-act Development
lease project lease project
----------------------------------------------------------------------------------------------------------------
(1) Average NYMEX price for last 12 months is at least 25 X
percent above the average for the qualifying months......
(2) Average NYMEX price for last calendar year exceeds $28/ ......... X X
bbl or $3.50/mcf, escalated by the gross domestic product
(GDP) deflator since 1994................................
(3) Average prices for designated periods exceed levels we ......... X ......... X
specify in the Notice of Sale or the lease...............
----------------------------------------------------------------------------------------------------------------
(g) The following table indicates by an X, and Sec. Sec. 203.55 and
203.76 through 203.77 describe, circumstances under which we end or
reduce royalty relief.
[[Page 21]]
----------------------------------------------------------------------------------------------------------------
Deep water
End-of- ------------------------------------------
Relief withdrawn or reduced life Expansion Pre-act Development
lease project lease project
----------------------------------------------------------------------------------------------------------------
(1) If recipient requests................................. X X X X
(2) Lease royalty rate is at the effective rate for 12 X
consecutive months.......................................
(3) Conditions occur that we specified in the approval X
letter in individual cases...............................
(4) Recipient does not submit post-production report that ......... X X X
compares expected to actual costs........................
(5) Recipient changes development system.................. ......... X X X
(6) Recipient excessively delays starting fabrication..... ......... X X X
(7) Recipient spends less than 80 percent of proposed pre- ......... X X X
production costs prior to start of production............
(8) Amount of relief volume is produced................... ......... X X X
----------------------------------------------------------------------------------------------------------------
[67 FR 1873, Jan. 15, 2002, as amended at 69 FR 3509, Jan. 26, 2004]
Sec. 203.5 What is MMS's authority to collect information?
The Paperwork Reduction Act of 1995 (PRA) requires us to inform you
that MMS may not conduct or sponsor and you are not required to respond
to a collection of information unless it displays a currently valid OMB
control number. OMB approved the information collection requirements in
this part 203 under 44 U.S.C. 3501 et seq. in two actions. The
information collection requirements in Sec. Sec. 203.50 through 203.91
are approved under OMB control number 1010-0071, and those in Sec. Sec.
203.40 through 203.48 are approved under 1010-0153.
[69 FR 3509, Jan. 26, 2004]
Subpart B_OCS Oil, Gas, and Sulfur General
Source: 63 FR 2618, Jan. 16, 1998, unless otherwise noted.
Royalty Relief for Drilling Deep Gas Wells on Leases Not Subject to Deep
Water Royalty Relief
Source: 69 FR 3510, Jan. 26, 2004, unless otherwise noted.
Sec. 203.40 Which leases are eligible for royalty relief as a result of
drilling deep wells?
Your lease may receive a royalty suspension volume under Sec. Sec.
203.41 through 203.43, and may receive a royalty suspension supplement
under Sec. Sec. 203.44 through 203.46, if it:
(a) Was:
(1) In existence on January 1, 2001;
(2) Issued in a lease sale held after January 1, 2001, and before
April 1, 2004, and either the lessee has exercised the option provided
for in Sec. 203.48 or the lease is located partly in water less than
200 meters deep and no deep water royalty relief provisions in statutes
or lease terms apply to the lease; or
(3) Issued in a lease sale held on or after April 1, 2004, and
either the lease terms provide for royalty relief under Sec. Sec.
203.41 through 203.47 of this part or the lease is located partly in
water less than 200 meters deep and no deep water royalty relief
provisions in statutes or lease terms apply to the lease;
(b) Is located:
(1) In the GOM, wholly west of 87 degrees, 30 minutes West
longitude;
(2) Entirely in water less than 200 meters deep, or partly in water
less than 200 meters deep and no deep-water royalty relief provisions in
statutes or lease terms apply to the lease; and
(c) Has not produced gas or oil from a deep well with a perforated
interval the top of which is 18,000 feet TVD SS or deeper that commenced
drilling before March 26, 2003.
[69 FR 3510, Jan. 26, 2004, as amended at 70 FR 22252, Apr. 29, 2005]
Sec. 203.41 If I have a qualified well, what royalty relief will my lease
earn?
(a) This paragraph and paragraph (b) of this section apply if your
lease has not produced gas or oil from a deep well that commenced
drilling before March 26, 2003. Subject to the administrative
requirements of Sec. 203.43, the provisions of Sec. 203.44(d), and the
price
[[Page 22]]
conditions in Sec. 203.47, you earn a royalty suspension volume shown
in the following table in billions of cubic feet (BCF) or in thousands
of cubic feet (MCF) applicable to gas production as prescribed in Sec.
203.42:
------------------------------------------------------------------------
Then you earn a royalty
suspension volume on this
If you have a qualified well that is . amount of gas production, as
. . prescribed in this section and
Sec. 203.42:
------------------------------------------------------------------------
(1) An original well with a perforated 15 BCF.
interval the top of which is from
15,000 to less than 18,000 feet TVD SS.
(2) A sidetrack with a perforated 4 BCF plus 600 MCF times
interval the top of which is from sidetrack measured depth
15,000 to less than 18,000 feet TVD SS. (rounded to the nearest 100
feet) but no more than 15 BCF.
(3) An original well with a perforated 25 BCF.
interval the top of which is 18,000
feet TVD SS or deeper.
(4) A sidetrack with a perforated 4 BCF plus 600 MCF times
interval the top of which is 18,000 sidetrack measured depth
feet TVD SS or deeper. (rounded to the nearest 100
feet) but no more than 25 BCF.
------------------------------------------------------------------------
(b) We will suspend royalties on gas volumes produced on or after
May 3, 2004, reported on the Oil and Gas Operations Report, Part A
(OGOR-A) for your lease under Sec. 216.53, as and to the extent
prescribed in Sec. 203.42. All gas production from qualified wells
reported on the OGOR-A, including production that is not subject to
royalty (except for production to which a royalty suspension supplement
under Sec. Sec. 203.44 and 203.45 applies), counts toward the lease
royalty suspension volume.
Example 1. If you have a qualified well that is an original well
with a perforated interval the top of which is 16,000 feet TVD SS, you
earn a royalty suspension volume of 15 BCF of gas production from
qualified wells on your lease, as prescribed in Sec. 203.42. However,
if the top of the perforated interval is 18,500 feet TVD SS, the royalty
suspension volume is 25 BCF.
Example 2. If you have a qualified well that is a sidetrack with a
perforated interval the top of which is 16,000 feet TVD SS, that has a
sidetrack measured depth of 6,789 feet, we round the distance to 6,800
feet and you earn a royalty suspension volume of 8.08 BCF of gas
production from qualified wells on your lease, as prescribed in Sec.
203.42.
Example 3. If you have a qualified well that is a sidetrack with a
perforated interval the top of which is 16,000 feet TVD SS, that has a
sidetrack measured depth of 19,500 feet, you earn a royalty suspension
volume of 15 BCF of gas production from qualified wells on your lease,
as prescribed in Sec. 203.42, even though 4 BCF plus 600 MCF per foot
of sidetrack measured depth equals 15.7 BCF.
(c) This paragraph and paragraph (d) of this section apply if your
lease has produced gas or oil from a deep well with a perforated
interval the top of which is from 15,000 to less than 18,000 feet TVD SS
(regardless of whether drilling began before or after March 26, 2003),
and you subsequently have a qualified well on your lease with a
perforated interval the top of which is 18,000 feet TVD or deeper.
Subject to the administrative requirements of Sec. 203.43, the
provisions of Sec. 203.44(d), and the price conditions in Sec. 203.47,
you earn a royalty suspension volume specified in the following table,
applicable to gas production as prescribed in Sec. 203.42. This royalty
suspension volume is in addition to any royalty suspension volume your
lease already may have earned, if any, as a result of a qualified well
with a perforated interval the top of which is from 15,000 to less than
18,000 feet TVD SS.
------------------------------------------------------------------------
If your lease has produced gas or oil
from a deep well with a perforated Then, you earn a royalty
interval the top of which is from suspension volume on this
15,000 to less than 18,000 feet TVD SS, amount of gas production, as
and you subsequently have a qualified prescribed in this section and
well that is . . . Sec. 203.42
------------------------------------------------------------------------
(1) An original well or a sidetrack 0 BCF.
with a perforated interval the top of
which is from 15,000 to less than
18,000 feet TVD SS.
(2) An original well with a perforated 10 BCF.
interval the top of which is 18,000
feet TVD SS or deeper.
(3) A sidetrack with a perforated 4 BCF plus 600 MCF times
interval the top of which is 18,000 sidetrack measured depth
feet TVD SS or deeper. (rounded to the nearest 100
feet) but no more than 10 BCF.
------------------------------------------------------------------------
(d) We will suspend royalties on gas volumes produced on or after
May 3, 2004, reported on the Oil and Gas Operations Report, Part A
(OGOR-A) for
[[Page 23]]
your lease under Sec. 216.53, as and to the extent prescribed in Sec.
203.42. All gas production from qualified wells reported on the OGOR-A,
including production that is not subject to royalty (except for
production to which a royalty suspension supplement under Sec. Sec.
203.44 and 203.45 applies), counts toward the lease royalty suspension
volume.
Example 1. If you have drilled and produced a well with a perforated
interval the top of which is 16,000 feet TVD SS before March 26, 2003
(and therefore, it is not a qualified well and has earned no royalty
suspension volume) and later drill:
(i) A well with a perforated interval the top of which is 17,000
feet TVD SS, you earn no royalty suspension volume.
(ii) A qualified well that is an original well with a perforated
interval the top of which is 19,000 feet TVD SS, you earn a royalty
suspension volume of 10 BCF of gas production from qualified wells on
your lease, as prescribed in Sec. 203.42.
(iii) A qualified well that is a sidetrack with a perforated
interval the top of which is 19,000 feet TVD SS, that has a sidetrack
measured depth of 7,000 feet, you earn a royalty suspension volume of
8.2 BCF of gas production from qualified wells on your lease, as
prescribed in Sec. 203.42.
Example 2. If you have a qualified well (i.e., drilled after March
26, 2003) that is an original well with a perforated interval the top of
which is 16,000 feet TVD SS and later drill a second qualified well that
is an original well with a perforated interval the top of which is
19,000 feet TVD SS, we increase the total royalty suspension volume for
your lease from 15 BCF to 25 BCF, as prescribed in Sec. 203.42.
Example 3. If you have a qualified well (i.e., drilled after March
26, 2003) that is a sidetrack with a perforated interval the top of
which is 16,000 feet TVD SS, that has a sidetrack measured depth of
4,000 feet, and later drill a second qualified well that is a sidetrack
with a perforated interval the top of which is 19,000 feet TVD SS, that
has a sidetrack measured depth of 8,000 feet, we increase the total
royalty suspension volume for your lease from 6.4 BCF to 15.2 BCF, as
prescribed in Sec. 203.42. The difference of 8.8 BCF represents the
royalty suspension volume earned by the second sidetrack.
(e) After your lease has produced gas or oil from a deep well with a
perforated interval the top of which is 18,000 feet TVD SS or deeper,
your lease cannot earn a royalty suspension volume as a result of
drilling any subsequent qualified wells.
(f) The royalty suspension volume determined under this section for
the first qualified well on your lease (whether an original well or a
sidetrack) establishes the total royalty suspension volume available for
that drilling depth interval on your lease, regardless of the number of
subsequent qualified wells you drill to that depth interval.
Example to paragraph (f): If your first qualified well is a
sidetrack with a perforated interval the top of which is 16,000 feet TVD
SS and earns a royalty suspension volume of 12.5 BCF, and you later
drill a qualified original well to 17,000 feet TVD SS, the royalty
suspension volume for your lease remains at 12.5 BCF and does not
increase to 15 BCF. However, under paragraph (b) of this section, if you
subsequently drill a qualified well to another depth interval 18,000
feet or greater TVD SS, you may earn an additional royalty suspension
volume.
(g) If a qualified well on your lease is within a unitized portion
of your lease, the royalty suspension volume earned by that well under
this section applies only to your lease and not to other leases within
the unit.
(h) If your qualified well is a directional well (either an original
well or a sidetrack) drilled across a lease line, the lease with the
perforated interval that initially produces earns the royalty suspension
volume. However, if the perforated interval crosses a lease line, the
lease where the surface of the well is located earns the royalty
suspension volume.
(i) Any royalty suspension volume earned under this section is in
addition to any royalty suspension supplement for your lease under Sec.
203.44 that results from a different wellbore.
(j) If your lease earns a royalty suspension volume under this
section and later produces from a deep well that is not a qualified
well, the royalty suspension volume is not forfeited or terminated.
However, you may not apply the royalty suspension volume under this
section to production from the deep well that is not a qualified well,
even if it begins producing after your first qualified well.
(k) You owe minimum royalties or rentals in accordance with your
lease terms notwithstanding any royalty
[[Page 24]]
suspension volumes allowed under paragraphs (a) and (b) of this section.
[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24053, Apr. 30, 2004]
Sec. 203.42 To which production do I apply the royalty suspension volume
earned from qualified wells on my lease?
(a) This paragraph applies to any lease that is not within an MMS-
approved unit. Subject to the requirements of Sec. Sec. 203.40, 203.41,
203.43, 203.44, and 203.47, you must apply the royalty suspension
volumes prescribed in Sec. 203.41 to the earliest gas production:
(1) Occurring on and after the later of May 3, 2004, or the date
that the first qualified well that earns your lease the royalty
suspension volume begins production (other than test production);
(2) From all qualified wells, regardless of their depth, on your
lease for which you have met the requirements in Sec. 203.43, up to the
aggregate royalty suspension volume earned by your lease.
Example to paragraph (a): You began drilling an original well that
was a qualified well with a perforated interval the top of which is
18,200 feet TVD SS on May 1, 2003 and it began producing on September 1,
2003. You subsequently drilled two more original wells that are
qualified wells with a perforated interval the tops of which are 16,600
feet TVD SS. The first well earned a royalty suspension volume of 25
BCF. You must apply the royalty suspension volume each month beginning
on March 1, 2004 to production from all three wells until the 25 BCF
royalty suspension volume is fully utilized.
(b) This paragraph applies to any lease all or part of which is
within an MMS-approved unit. If your lease has a qualified well, a share
of the production from all the qualified wells in the unit participating
area will be allocated to your lease each month according to the
participating area percentages. Subject to the requirements of
Sec. Sec. 203.40, 203.41, 203.43, 203.44, and 203.47, you must apply
the royalty suspension volume to the earliest gas production occurring
on and after the later of May 3, 2004, or the date that the first
qualified well that earns your lease the royalty suspension volume
begins production (other than test production):
(1) From all qualified wells on the non-unitized area of your lease
and
(2) Allocated to your lease from qualified wells on unitized areas
of your lease and other leases in the unit under an MMS-approved unit
agreement. That allocated share does not increase the royalty suspension
volume for your lease. None of the volumes produced from a well that is
not within a unit participating area may be allocated to other leases in
the unit.
Example to paragraph (b): The east half of your lease A is unitized
with all of lease B. There is one qualified well on the non-unitized
portion of lease A, one qualified well on the unitized portion of lease
A and a qualified well on lease B. The participating area percentages
allocate 32 percent of production from both of the unit qualified wells
to lease A and 68 percent to lease B. If the non-unitized qualified well
on lease A produces 12,000 MCF and the unitized qualified well on lease
A produces 15,000 MCF, and the qualified well on lease B produces 10,000
MCF, then the production volume from and allocated to lease A to which
the lease A royalty suspension volume applies is 20,000 MCF [12,000 +
(15,000 + 10,000)(32 percent)]. The production volume allocated to lease
B to which the lease B royalty suspension volume applies is 17,000 MCF
[(15,000 + 10,000)(68 percent)].
(c) Unused royalty suspension volume transfers to a successor lessee
and expires with the lease.
(d) You may not apply the royalty suspension volume allowed under
Sec. 203.41:
(1) To production from completions less than 15,000 feet TVD SS,
except in cases where the qualified well is re-perforated in the same
reservoir previously perforated deeper than 15,000 feet TVD SS;
(2) To production from a deep well that commenced drilling before
March 26, 2003; or
(3) To production from a deep well on any other lease, except as
provided in paragraph (b) of this section.
(e) You must begin paying royalties when the cumulative production
of gas from all qualified wells on your lease, or allocated to your
lease under paragraph (b) of this section, reaches the applicable
royalty suspension volume allowed under Sec. 203.41. For the month in
which cumulative production reaches this royalty suspension volume, you
[[Page 25]]
owe royalties on the portion of gas production that exceeds the royalty
suspension volume remaining at the beginning of that month.
(f) No royalty suspension volume may be applied to any liquid
hydrocarbon (oil and condensate) volumes.
[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004]
Sec. 203.43 What administrative steps must I take to use the royalty
suspension volume?
(a) You must notify, in writing, the MMS Regional Supervisor for
Production and Development of your intent to begin drilling operations
on all deep wells; and
(b) Within 30 days of the beginning of production from all wells
that would become qualified wells by satisfying the requirements of this
section, you must:
(1) Provide written notification to the MMS Regional Supervisor for
Production and Development that production has begun; and
(2) Request confirmation of the size of the royalty suspension
volume earned by your lease.
(c) Before beginning production, you must meet any production
measurement requirements that the MMS Regional Supervisor for Production
and Development has determined are necessary under 30 CFR part 250,
subpart L.
(d) If you produced from a qualified well before May 3, 2004, you
must provide the information in paragraph (b) of this section no later
than August 3, 2004.
(e) If you cannot produce from a well that otherwise meets the
criteria for a qualified well before May 3, 2009, the MMS Regional
Supervisor for Production and Development may extend the deadline for
beginning production for up to 1 year, based on the circumstances of the
particular well involved, provided you demonstrate that:
(1) The delay occurred after reaching total depth in your well;
(2) Production (other than test production) was expected to begin
before March 1, 2009; and
(3) The delay in beginning production is for reasons beyond your
control, including but not limited to adverse weather and unavoidable
accidents.
[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004]
Sec. 203.44 If I drill a certified unsuccessful well, what royalty relief
will my lease earn?
Your lease may earn a royalty suspension supplement. Subject to
paragraph (d) of this section, the royalty suspension supplement is in
addition to any royalty suspension volume your lease may earn under
Sec. 203.41.
(a) If you drill a certified unsuccessful well and you satisfy the
administrative requirements of Sec. 203.46 and subject to the price
conditions in Sec. 203.47, you earn a royalty suspension supplement
shown in the following table (in billions of cubic feet of gas
equivalent (BCFE) or in thousands of cubic feet of gas equivalent
(MCFE)) applicable to oil and gas production as prescribed in Sec.
203.45:
------------------------------------------------------------------------
Then, you earn a royalty
suspension supplement on this
If you have a certified unsuccessful volume of oil and gas
well that is . . . production as prescribed in
this section and Sec. 203.45:
------------------------------------------------------------------------
(1) An original well and your lease has 5 BCFE.
not produced gas or oil from a deep
well.
(2) A sidetrack (with a sidetrack 0.8 BCFE plus 120 MCFE times
measured depth of at least 10,000 sidetrack measured depth
feet) and your lease has not produced (rounded to the nearest 100
gas or oil from a deep well. feet) but no more than 5 BCFE.
(3) An original well or a sidetrack 2 BCFE.
(with a sidetrack measured depth of at
least 10,000 feet) and your lease has
produced gas or oil from a deep well
with a perforated interval the top of
which is from 15,000 to less than
18,000 feet TVD SS.
------------------------------------------------------------------------
(b) We will suspend royalties on oil and gas volumes produced on or
after May 3, 2004, reported on the Oil and Gas Operations Report, Part A
(OGOR-A) for your lease under Sec. 216.53, as and to the extent
prescribed in Sec. 203.45. All oil and gas production reported on the
OGOR-A, including production that is
[[Page 26]]
not subject to royalty (except for production to which a royalty
suspension volume under Sec. Sec. 203.41 and 203.42 applies), counts
toward the lease royalty suspension supplement.
Example 1. If you drill a certified unsuccessful well that is an
original well to a target 19,000 feet TVD SS, you earn a royalty
suspension supplement of 5 BCFE of gas and oil production if your lease
has not previously produced from a deep well, or you earn a royalty
suspension supplement of 2 BCFE of gas and oil production if your lease
has previously produced from a deep well with a perforated interval from
15,000 to less than 18,000 feet TVD SS, as prescribed in Sec. 203.45.
Example 2. If you drill a certified unsuccessful well that is a
sidetrack that reaches a target 19,000 feet TVD SS, that has a sidetrack
measured depth of 12,545 feet, and your lease has not produced gas or
oil from any deep well, we round the distance to 12,500 feet and you
earn a royalty suspension supplement of 2.3 BCFE of gas and oil
production as prescribed in Sec. 203.45.
(c) The conversion from oil to gas for using the royalty suspension
supplement is specified in Sec. 203.73.
(d) Each lease is eligible for up to two royalty suspension
supplements. Therefore, the total royalty suspension supplement for a
lease cannot exceed 10 BCFE.
(1) You may not earn more than one royalty suspension supplement
from a single wellbore.
(2) If you begin drilling a certified unsuccessful well on one lease
but the completion target is on a second lease, the entire royalty
suspension supplement belongs to the second lease. However, if the
target straddles a lease line, the lease where the surface of the well
is located earns the royalty suspension supplement.
(e) If the same wellbore that earns a royalty suspension supplement
as a certified unsuccessful well later produces from a perforated
interval the top of which is 15,000 feet TVD SS or deeper before May 3,
2009, it will become a qualified well subject to the following
conditions:
(1) Beginning on the date production starts, you must stop applying
the royalty suspension supplement earned by that wellbore to your lease
production.
(2) If the completion of this qualified well is on your lease or, in
the case of a directional well, is on another lease, then you must
subtract from the royalty suspension volume earned by that qualified
well the royalty suspension supplement amounts earned by that wellbore
that have already been applied either on your lease or any other lease.
The difference represents the royalty suspension volume earned by the
qualified well.
(f) If the same wellbore that earned a royalty suspension supplement
later has a sidetrack drilled from that wellbore, you are not required
to subtract any royalty suspension supplement earned by that wellbore
from the royalty suspension volume that may be earned by the sidetrack.
(g) You owe minimum royalties or rentals in accordance with your
lease terms notwithstanding any royalty suspension supplements under
this section.
[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004; 72
FR 25198, May 4, 2007]
Sec. 203.45 To which production do I apply the royalty suspension
supplements from drilling one or two certified unsuccessful wells on my lease?
(a) Subject to the requirements of Sec. Sec. 203.40, 203.42,
203.44, 203.46 and 203.47, you must apply royalty suspension supplements
in Sec. 203.44 to the earliest oil and gas production:
(1) Occurring on and after the day you file the information under
Sec. 203.46(b),
(2) From, or allocated under an MMS-approved unit agreement to, the
lease on which the certified unsuccessful well was drilled, without
regard to the drilling depth of the well producing the gas or oil.
(b) If you have a royalty suspension volume for the lease under
Sec. 203.41, you must use the royalty suspension volumes for gas
produced from qualified wells on the lease before using royalty
suspension supplements for gas produced from qualified wells.
Example to paragraph (b): You have two shallow oil wells on your
lease. Then you drill a certified unsuccessful well and earn a royalty
suspension supplement of 5 BCFE. Thereafter, you begin production from
an original well that is a qualified well that earns a royalty
suspension volume of 15 BCF.
[[Page 27]]
You use only 2 BCFE of the royalty suspension supplement before the oil
wells deplete. You must use up the 15 BCF of royalty suspension volume
before you use the remaining 3 BCFE of the royalty suspension supplement
for gas produced from the qualified well.
(c) If you have no current production on which to apply the royalty
suspension supplement allowed under Sec. 203.44, your royalty
suspension supplement applies to the earliest subsequent production of
gas and oil from, or allocated under an MMS-approved unit agreement to,
your lease.
(d) Unused royalty suspension supplements transfer to a successor
lessee and expire with the lease.
(e) You may not apply the royalty suspension supplement allowed
under Sec. 203.44 to production from any other lease, except for
production allocated to your lease from an MMS-approved unit agreement.
If your certified unsuccessful well is on a lease subject to an MMS-
approved unit agreement, the lessees of other leases in the unit may not
apply any portion of the royalty suspension supplement for your lease to
production from the other leases in the unit.
(f) You must begin or resume paying royalties when cumulative gas
and oil production from, or allocated under an MMS-approved unit
agreement to, your lease (excluding any gas produced from qualified
wells subject to a royalty suspension volume allowed under Sec. 203.41)
reaches the applicable royalty suspension supplement. For the month in
which the cumulative production reaches this royalty suspension
supplement, you owe royalties on the portion of gas or oil production
that exceeds the amount of the royalty suspension supplement remaining
at the beginning of that month.
Sec. 203.46 What administrative steps do I take to obtain and use the
royalty suspension supplement?
(a) Before you start drilling a well on your lease targeted to a
reservoir at least 18,000 feet TVD SS, you must notify, in writing, the
MMS Regional Supervisor for Production and Development of your intent to
begin drilling operations and the depth of the target.
(b) After drilling the well, you must provide the MMS Regional
Supervisor for Production and Development within 60 days after reaching
the total depth in your well:
(1) Information that allows MMS to confirm that you drilled a
certified unsuccessful well as defined under Sec. 203.0, including:
(i) Well log data, if your original well or sidetrack does not meet
the producibility requirements of 30 CFR part 250, subpart A; or
(ii) Well log, well test, seismic, and economic data, if your well
does meet the producibility requirements of 30 CFR part 250, subpart A;
and
(2) Information that allows MMS to confirm the size of the royalty
suspension supplement for a sidetrack, including sidetrack measured
depth and supporting documentation.
(c) If you commenced drilling a well that otherwise meets the
criteria for a certified unsuccessful well on or after March 26, 2003,
and finished it before May 3, 2004, provide the information in paragraph
(b) of this section no later than August 3, 2004.
[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004]
Sec. 203.47 Do I keep royalty relief if prices rise significantly?
(a) You must pay royalties on all gas and oil production for which
royalty suspension volume or royalty suspension supplement otherwise
would be allowed under Sec. Sec. 203.40 through 203.46 for any calendar
year when the average daily closing NYMEX natural gas price exceeds the
threshold of $9.34 per MMBtu, adjusted annually after year 2004 for
inflation. The threshold price for any calendar year after 2004 is found
by adjusting the threshold price in the previous year by the percentage
that the implicit price deflator for the gross domestic product as
published by the Department of Commerce changed during the calendar
year.
(b) You must pay any royalty due under this paragraph, plus late
payment interest from the end of the month after the month of production
until the date of payment under 30 CFR 218.54, no later than 90 days
after the end of the calendar year for which you owe royalty.
(c) Production volumes on which you must pay royalty under this
section
[[Page 28]]
count as part of your royalty suspension volumes and royalty suspension
supplements.
Sec. 203.48 May I substitute the deep gas drilling provisions in Sec. 203.0
and Sec. Sec. 203.40 through 203.47 for the deep gas royalty relief provided
in my lease terms?
(a) You may exercise an option to replace the applicable lease terms
for royalty relief related to deep-well drilling with those in Sec.
203.0 and Sec. Sec. 203.40 through 203.47 if you have a lease issued
with royalty relief provisions for deep-well drilling. Such leases:
(1) Must be issued as part of an OCS lease sale held after January
1, 2001, and before April 1, 2004; and
(2) Must be located wholly west of 87 degrees, 30 minutes West
longitude in the GOM entirely or partly in water less than 200 meters
deep.
(b) To exercise the option under paragraph (a) of this section, you
must notify, in writing, the MMS Regional Supervisor for Production and
Development of your decision before September 1, 2004 or 180 days after
your lease is issued, whichever is later, and specify the lease and
block number.
(c) Once you exercise the option under paragraph (a) of this
section, you are subject to all the activity, timing, and administrative
requirements pertaining to deep gas royalty relief as specified in
Sec. Sec. 203.40 through 203.47.
(d) Exercising the option under paragraph (a) of this section is
irrevocable. If you do not exercise this option, then the terms of your
lease apply.
Royalty Relief for End-of-life Leases
Sec. 203.50 Who may apply for end-of-life royalty relief?
You may apply for royalty relief in two situations.
(a) Your end-of-life lease (as defined in Sec. 203.2) is an oil and
gas lease and has average daily production of at least 100 barrels of
oil equivalent (BOE) per month (as calculated in Sec. 203.73) in at
least 12 of the past 15 months. The most recent of these 12 months are
considered the qualifying months. These 12 months should reflect the
basic operation you intend to use until your resources are depleted. If
you changed your operation significantly (e.g., begin re-injecting
rather than recovering gas) during the qualifying months, or if you do
so while we are processing your application, we may defer action on your
application until you revise it to show the new circumstances.
(b) Your end-of-life lease is other than an oil and gas lease (e.g.,
sulphur) and has production in at least 12 of the past 15 months. The
most recent of these 12 months are considered the qualifying months.
[63 FR 2618, Jan. 16, 1998, as amended at 63 FR 57249, Oct. 27, 1998]
Sec. 203.51 How do I apply for end-of-life royalty relief?
You must submit a complete application and the required fee to the
appropriate MMS Regional Director. Your MMS regional office will provide
specific guidance on the report formats. A complete application for
relief includes:
(a) An administrative information report (specified in Sec. 203.83)
and
(b) A net revenue and relief justification report (specified in
Sec. 203.84).
Sec. 203.52 What criteria must I meet to get relief?
(a) To qualify for relief, you must demonstrate that the sum of
royalty payments over the 12 qualifying months exceeds 75 percent of the
sum of net revenues (before-royalty revenues minus allowable costs, as
defined in Sec. 203.84).
(b) To re-qualify for relief, e.g., either applying for additional
relief on top of relief already granted, or applying for relief sometime
after your earlier agreement terminated, you must demonstrate that:
(1) You have met the criterion listed in paragraph (a) of this
section, and
(2) The 12 required qualifying months of operation have occurred
under the current royalty arrangement.
Sec. 203.53 What relief will MMS grant?
(a) If we approve your application and you meet certain conditions,
we will reduce the pre-application effective royalty rate by one-half on
production up to the relief volume
[[Page 29]]
amount. If you produce more than the relief volume amount:
(1) We will impose a royalty rate equal to 1.5 times the effective
royalty rate on your additional production up to twice the relief volume
amount; and
(2) We will impose a royalty rate equal to the effective rate on all
production greater than twice the relief volume amount.
(b) Regardless of the level of production or prices (see Sec.
203.54), royalty payments due under end-of-life relief will not exceed
the royalty obligations that would have been due at the effective
royalty rate.
(1) The effective royalty rate is the average lease rate paid on
production during the 12 qualifying months.
(2) The relief volume amount is the average monthly BOE production
for the 12 qualifying months.
Sec. 203.54 How does my relief arrangement for an oil and gas lease operate
if prices rise sharply?
In those months when your current reference price rises by at least
25 percent above your base reference price, you must pay the effective
royalty rate on all monthly production.
(a) Your current reference price is a weighted average of daily
closing prices on the NYMEX for light sweet crude oil and natural gas
over the most recent full 12 calendar months;
(b) Your base reference price is a weighted average of daily closing
prices on the NYMEX for light sweet crude oil and natural gas during the
qualifying months; and
(c) Your weighting factors are the proportions of your total
production volume (in BOE) provided by oil and gas during the qualifying
months.
Sec. 203.55 Under what conditions can my end-of-life royalty relief
arrangement for an oil and gas lease be ended?
(a) If you have an end-of-life royalty relief arrangement, you may
renounce it at any time. The lease rate will return to the effective
rate during the qualifying period in the first full month following our
receipt of your renouncement of the relief arrangement.
(b) If you pay the effective lease rate for 12 consecutive months,
we will terminate your relief. The lease rate will return to the
effective rate in the first full month following this termination.
(c) We may stipulate in the letter of approval for individual cases
certain events that would cause us to terminate relief because they are
inconsistent with an end-of-life situation.
Sec. 203.56 Does relief transfer when a lease is assigned?
Yes. Royalty relief is based on the lease circumstances, not
ownership. It transfers upon lease assignment.
Royalty Relief For Deep Water Expansion Projects And Pre-Act Deep Water
Leases
Sec. 203.60 Who may apply for deep water royalty relief?
You may apply for royalty relief under Sec. Sec. 203.61(b) and
203.62 if:
(a) You are a lessee of a lease in water at least 200 meters deep in
the GOM and lying wholly west of 87 degrees, 30 minutes West longitude;
(b) We have assigned your pre-Act lease to a field (as defined in
Sec. 203.0); and
(c) You either:
(1) Hold a pre-Act lease on an authorized field (as defined in Sec.
203.0) or
(2) Propose an expansion project (as defined in Sec. 203.0) or
(3) Propose a development project (as defined in Sec. 203.0).
[67 FR 1875, Jan. 15, 2002]
Sec. 203.61 How do I assess my chances for getting relief?
You may ask for a nonbinding assessment (a formal opinion on whether
a field would qualify for royalty relief) before turning in your first
complete application on an authorized field. This field must have a
qualifying well under 30 CFR part 250, subpart A, or be on a lease that
has allocated production under an approved unit agreement.
(a) To request a nonbinding assessment, you must:
(1) Submit a draft application in the format and detail specified in
guidance from the MMS regional office for the GOM;
(2) Propose to drill at least one more appraisal well if you get a
favorable assessment; and
[[Page 30]]
(3) Pay a fee under Sec. 203.3.
(b) You must wait at least 90 days after receiving our assessment to
apply for relief under Sec. 203.62.
(c) This assessment is not binding because a complete application
may contain more accurate information that does not support our original
assessment. It will help you decide whether your proposed inputs for
evaluating economic viability and your supporting data and assumptions
are adequate.
Effective Date Note: At 63 FR 2619, Jan. 16, 1998, Sec. 203.61 was
revised. This section contains information collection and recordkeeping
requirements and will not become effective until approval has been given
by the Office of Management and Budget.
Sec. 203.62 How do I apply for relief?
You must send a complete application and the required fee to the MMS
Regional Director for the GOM.
(a) Your application for deep water royalty relief must include an
original and two copies (one set of digital information) of:
(1) Administrative information report;
(2) Deep water economic viability and relief justification report;
(3) G&G report;
(4) Engineering report;
(5) Production report; and
(6) Deep water cost report.
(b) Section 203.82 explains why we are authorized to require these
reports.
(c) Sections 203.81, 203.83, and 203.85 through 203.89 describe what
these reports must include. The MMS regional office for the GOM will
guide you on the format for the required reports, and we encourage you
to contact this office prior to preparing your application for this
guidance.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]
Sec. 203.63 Does my application have to include all leases in the field?
(a) For authorized fields, we will accept only one joint application
for all leases that are part of the designated field on the date of
application, except as provided in paragraph (a)(3) of this section and
Sec. 203.64. However, we will evaluate all acreage that may eventually
become part of the authorized field. Therefore, if you have any other
leases that you believe may eventually be part of the authorized field,
you must submit data for these leases according to Sec. 203.81.
(1) The Regional Director maintains a Field Names Master List with
updates of all leases in each designated field.
(2) To avoid sharing proprietary data with other lessees on the
field, you may submit your proprietary G&G report separately from the
rest of your application. Your application is not complete until we
receive all the required information for each lease on the field. We
will not disclose proprietary data when explaining our assumptions and
reasons for our determinations under Sec. 203.67.
(3) We will not require a joint application if you show good cause
and honest effort to get all lessees in the field to participate. If you
must exclude a lease from your application because its lessee will not
participate, that lease is ineligible for the royalty relief for the
designated field.
(b) If your application seeks only relief for a development project
or an expansion project, your application does not have to include all
leases in the field.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]
Sec. 203.64 How many applications may I file on a field or a development
project?
You may file one complete application for royalty relief during the
life of the field or for a development project or an expansion project
designed to produce a reservoir or set of reservoirs. However, you may
send another application if:
(a) You are eligible to apply for a redetermination under Sec.
203.74;
(b) You apply for royalty relief for an expansion project;
(c) You withdraw the application before we make a determination; or
(d) You apply for end-of-life royalty relief.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]
[[Page 31]]
Sec. 203.65 How long will MMS take to evaluate my application?
(a) We will determine within 20 working days if your application for
royalty relief is complete. If your application is incomplete, we will
explain in writing what it needs. If you withdraw a complete
application, you may reapply.
(b) We will evaluate your first application on a field within 180
days, evaluate your first application on a development project or an
expansion project within 150 days and evaluate a redetermination under
Sec. 203.75 within 120 days after we determine that it is complete.
(c) We may ask to extend the review period for your application
under the conditions in the following table.
------------------------------------------------------------------------
If-- Then we may--
------------------------------------------------------------------------
We need more records to audit sunk Ask to extend the 120-day or 180-
costs. day evaluation period. The
extension we request will equal
the number of days between when
you receive our request for
records and the day we receive the
records.
We cannot evaluate your application Add another 30 days. We may add
for a valid reason, such as more than 30 days, but only if you
missing vital information or agree.
inconsistent or inconclusive
supporting data.
We need more data, explanations, or Ask to extend the 120-day or 180-
revision. day evaluation period. The
extension we request will equal
the number of days between when
you receive our request and the
day we receive the information.
------------------------------------------------------------------------
(d) We may change your assumptions under Sec. 203.62 if our
technical evaluation reveals others that are more appropriate. We may
consult with you before a final decision and will explain any changes.
(e) We will notify all designated lease operators within a field
when royalty relief is granted.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]
Sec. 203.66 What happens if MMS does not act in the time allowed?
If we do not act within the timeframes established under Sec.
203.65, you get royalty relief according to the following table.
------------------------------------------------------------------------
And we do not
If you apply for royalty relief decide within the As long as you
for time specified
------------------------------------------------------------------------
(a) An authorized field......... You get the Abide by Sec.
minimum Sec. 203.70 and
suspension 203.76.
volumes specified
in Sec. 203.69.
(b) An expansion project........ You get a royalty Abide by Sec.
suspension for Sec. 203.70 and
the first year of 203.76.
production.
(c) A development project....... You get a royalty Abide by Sec.
suspension for Sec. 203.70 and
initial 203.76.
production for
the number of
months that a
decision is
delayed beyond
the stipulated
timeframes set by
Sec. 203.65,
plus all the
royalty
suspension volume
for which you
qualify.
------------------------------------------------------------------------
[67 FR 1875, Jan. 15, 2002]
Sec. 203.67 What economic criteria must I meet to get royalty relief on an
authorized field or project?
We will not approve applications if we determine that royalty relief
cannot make the field, development project, or expansion project
economically viable. Your field or project must be uneconomic while you
are paying royalties and must become economic with royalty relief.
[67 FR 1876, Jan. 15, 2002]
[[Page 32]]
Sec. 203.68 What pre-application costs will MMS consider in determining
economic viability?
(a) We will not consider ineligible costs as set forth in Sec.
203.89(h) in determining economic viability for purposes of royalty
relief.
(b) We will consider sunk costs according to the following table.
------------------------------------------------------------------------
We will When determining
------------------------------------------------------------------------
(1) Include sunk costs................. Whether a field that includes a
pre-Act lease which has not
produced, other than test
production, before the
application or redetermination
submission date needs relief
to become economic.
(2) Not include sunk costs............. Whether an authorized field, a
development project, or an
expansion project can become
economic with full relief (see
Sec. 203.67).
(3) Not include sunk costs............. How much suspension volume is
necessary to make the field, a
development project, or an
expansion project economic
(see Sec. 203.69(c)).
(4) Include sunk costs for the project Whether a development project
discovery well on each lease. or an expansion project needs
relief to become economic.
------------------------------------------------------------------------
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1876, Jan. 15, 2002]
Sec. 203.69 If my application is approved, what royalty relief will I
receive?
If we approve your application, subject to certain conditions, we
will not collect royalties on a specified suspension volume for your
field, development project, or expansion project. Suspension volumes
include volumes allocated to a lease under an approved unit agreement,
but exclude any volumes of production that are not normally royalty-
bearing under the lease or the regulations of this chapter (e.g., fuel
gas).
(a) For authorized fields, the minimum royalty-suspension volumes
are:
(1) 17.5 million barrels of oil equivalent (MMBOE) for fields in 200
to 400 meters of water;
(2) 52.5 MMBOE for fields in 400 to 800 meters of water; and
(3) 87.5 MMBOE for fields in more than 800 meters of water.
(b) For development projects, any relief we grant applies only to
project wells and replaces the royalty suspension volume with which we
issued your lease. If your project is economic given the royalty
suspension volume with which we issued your lease, we will reject the
application. Otherwise, the minimum royalty suspension volumes are as
shown in the following table:
------------------------------------------------------------------------
The minimum royalty
For suspension volume is Plus
------------------------------------------------------------------------
(1) RS leases................. A volume equal to the 10 percent of
combined royalty the median of
suspension volumes the
(or the volume distribution of
equivalent based on known
the data in your recoverable
approved application resources upon
for other forms of which we based
royalty suspension) approval of
with which we issued your
the leases application
participating in the from all
application that have reservoirs
or plan a well into a included in the
reservoir identified project.
in the application.
(2) Other deep water leases A volume equal to 10
issued in sales after percent of the median
November 28, 2000. of the distribution
of known recoverable
resources upon which
we based approval of
your application from
all reservoirs
included in the
project.
------------------------------------------------------------------------
(c) If your application includes pre-Act or eligible leases in
different categories of water depth, we apply the minimum royalty
suspension volume for the deepest such lease then assigned to the field.
We base the water depth and makeup of a field on the water-depth
delineations in the ``Lease Terms and Economic Conditions'' map and the
``Field Names Master List'' documents and updates in effect at the time
your application is deemed complete. These publications are available
from the MMS Regional Office for the GOM.
(d) You will get a royalty suspension volume above the minimum if we
determine that you need more to make
[[Page 33]]
the field or development project economic.
(e) For expansion projects, the minimum royalty suspension volume
equals 10 percent of the median of the distribution of known recoverable
resources upon which we based approval of your application from all
reservoirs included in your project plus any suspension volumes required
under Sec. 203.66. If we determine that your expansion project may be
economic only with more relief, we will determine and grant you the
royalty suspension volume necessary to make the project economic.
(f) The royalty suspension volume applicable to specific leases will
continue through the end of the month in which cumulative production
reaches that volume. You must calculate cumulative production from all
the leases in the authorized field or project that are entitled to share
the royalty suspension volume.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1876, Jan. 15, 2002]
Sec. 203.70 What information must I provide after MMS approves relief?
You must submit reports to us as indicated in the following table.
Sections 203.81, 203.90, and 203.91 describe what these reports must
include. The MMS regional office for the GOM will prescribe the formats.
------------------------------------------------------------------------
Due date
Required report When due to MMS extensions
------------------------------------------------------------------------
(a) Fabricator's confirmation Within 18 months MMS Director may
report. after approval of grant you an
relief. extension under
Sec. 203.79(c)
for up to 6
months.
(b) Post-production report...... Within 120 days With acceptable
after the start justification
of production from you, MMS
that is subject Regional Director
to the approved for the GOM may
royalty extend due date
suspension volume. up to 30 days.
------------------------------------------------------------------------
[67 FR 1876, Jan. 15, 2002]
Sec. 203.71 How does MMS allocate a field's suspension volume between my
lease and other leases on my field?
The allocation depends on when production occurs, when we issued the
lease, when we assigned it to the field, and whether we award the volume
suspension by an approved application or establish it in the lease
terms, as prescribed in this section.
(a) If your authorized field has an approved royalty suspension
volume under Sec. Sec. 203.67 and 203.69, we will suspend payment of
royalties on production from all leases in the field that participate in
the application until their cumulative production equals the approved
volume. The following conditions also apply:
------------------------------------------------------------------------
If . . . Then . . . And . . .
------------------------------------------------------------------------
(1) We assign an eligible lease We will not change The assigned
to your field after we approve your field's lease(s) may
relief. royalty share in any
suspension volume. remaining royalty
relief.
(2) We assign a pre-Act or post- We will not change The assigned
November 2000 deep water lease your field's lease(s) may
to your field after we approve royalty share in any
your application. suspension volume. remaining royalty
relief by filing
the short-form
application
specified in Sec.
203.83 and
authorized in
Sec. 203.82. An
assigned RS lease
also gets any
portion of its
royalty
suspension volume
remaining even
after the field
has produced the
approved relief
volume.
[[Page 34]]
(3) We assign another lease(s) We will change (i) You toll the
that you operate to your field your field's time period for
while we are evaluating your minimum evaluation until
application. suspension volume you modify your
if the assigned application to be
lease is a pre- consistent with
Act or eligible the new field;
lease entitled to (ii) We have an
a larger minimum additional 60
or automatic days to review
suspension volume. the new
information; and
(iii) The assigned
lease(s) shares
the royalty
suspension we
grant to the new
field. If you do
not agree to
toll, we will
have to reject
your application
due to incomplete
information. But,
an eligible lease
we assigned to
the field kept
its automatic
suspension
volume.
(4) We assign another operator's We will change (i) You both toll
lease to your field while we your field's the time period
are evaluating your application. minimum for evaluation
suspension volume until both of you
provided the modify your
assigned lease application to be
joins the consistent with
application and the new field;
is entitled to a (ii) We have an
larger minimum additional 60
suspension volume. days to review
the new
information; and
(iii) The assigned
lease(s) shares
the royalty
suspension we
grant to the new
field. If you
(the original
applicant) do not
agree to toll,
the other
operator's lease
retains any
suspension volume
it has or may
share in any
relief that we
grant by filing
the short form
application
specified in Sec.
203.83 and
authorized in
Sec. 203.82.
(5) We reassign a well on a pre- The past The past
Act, eligible, or post-November production from production from
2000 deep water lease to the well counts that well will
another field. toward the not count toward
royalty any royalty
suspension volume suspension volume
of the field to granted to the
which we assigned field from which
the well. we reassigned it.
------------------------------------------------------------------------
(b) If your authorized field has a royalty suspension volume
established under Sec. 260.111 of this title (i.e., a field with a pre-
Act lease where an eligible lease starts production first), we will
suspend payment of royalties on production from all eligible leases in
the field until their cumulative production equals the established
volume. The following conditions also apply:
------------------------------------------------------------------------
If . . . Then . . . And . . .
------------------------------------------------------------------------
(1) We assign another eligible Your field's The assigned lease
lease to your field. royalty may share in any
suspension volume remaining royalty
does not change. relief.
(2) We assign an RS lease to Your field's The assigned lease
your field. royalty gets only the
suspension volume volume suspension
does not change. with which we
issued it, and
its production
volume counts
against the
field's royalty
suspension
volume.
(3) We assign a pre-Act lease or Your field's We assign lease
a lease issued after November royalty shares none of
2000 without royalty suspension suspension volume the volume
to your field. does not change. suspension, and
its production
does not count as
part of the
suspension
volume.
(4) A pre-Act or post-November Your field's (i) All leases in
2000 deep water lease applies royalty the field share
(along with the other leases in suspension volume the royalty
the field) and qualifies may increase or suspension volume
(subject to any pre-existing stay the same, if we approve the
suspension volumes) for royalty but will not application; or
relief under Sec. Sec. diminish. (ii) The eligible
203.67 and 203.69. or RS leases in
the field keep
their respective
volumes if we
reject the
application.
------------------------------------------------------------------------
(c) When a project has more than one lease, the royalty suspension
volume for each lease equals that lease's actual production from the
project (or production allocated under an approved unit agreement) until
total production for all leases in the project equals the project's
approved royalty suspension volume.
(d) You may receive a royalty-suspension volume only if your entire
lease is west of 87 degrees, 30 minutes West longitude. If the field
lies on both
[[Page 35]]
sides of this meridian, only leases located entirely west of the
meridian will receive a royalty-suspension volume.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1877, Jan. 15, 2002]
Sec. 203.72 Can my lease receive more than one suspension volume?
Yes. You may apply for royalty relief that involves more than one
suspension volume under Sec. 203.62 in two circumstances.
(a) Each field that includes your lease may receive a separate
royalty-suspension volume, if it meets the evaluation criteria of Sec.
203.67.
(b) An expansion project on your lease may receive a separate
royalty-suspension volume, even if we have already granted a royalty-
suspension volume to the field that encompasses the project. But the
reserves associated with the project must not have been part of our
original determination, and the project must meet the evaluation
criteria of Sec. 203.67.
Sec. 203.73 How do suspension volumes apply to natural gas?
You must measure natural gas production under the royalty-suspension
volume as follows: 5.62 thousand cubic feet of natural gas, measured in
accordance with 30 CFR part 250, subpart L, equals one barrel of oil
equivalent.
Sec. 203.74 When will MMS reconsider its determination?
You may request a redetermination after we withdraw approval or
after you renounce royalty relief, unless we withdraw approval due to
your providing false or intentionally inaccurate information. Under
certain conditions you may also request a redetermination if we deny
your application or if you want your approved royalty suspension volume
to change. In these instances, to be eligible for a redetermination, at
least one of the following four conditions must occur.
(a) You have significant new G&G data and you previously have not
either requested a redetermination or reapplied for relief after we
withdrew approval or you relinquished royalty relief. ``Significant''
means that the new G&G data:
(1) Results from drilling new wells or getting new three-dimensional
seismic data and information (but not reinterpreting old data);
(2) Did not exist at the time of the earlier application; and
(3) Changes your estimates of gross resource size, quality, or
projected flow rates enough to materially affect the results of our
earlier determination.
(b) You demonstrate in your new application that the technology that
most efficiently develops this field or lease was not considered or
deemed feasible in the original application. Your newly proposed
technology must improve the profitability, under equivalent market
conditions, of the field or lease relative to the development system
proposed in the prior application.
(c) Your current reference price decreases by more than 25 percent
from your base reference price as calculated under this paragraph.
(1) Your current reference price is a weighted-average of daily
closing prices on the NYMEX for light sweet crude oil and natural gas
over the most recent full 12 calendar months;
(2) Your base reference price is a weighted average of daily closing
prices on the NYMEX for light sweet crude oil and natural gas for the
full 12 calendar months preceding the date of your most recently
approved application for this royalty relief; and
(3) The weighting factors are the proportions of the total
production volume (in BOE) for oil and gas associated with the most
likely scenario (identified in Sec. Sec. 203.85 and 203.88) from your
most recently approved application for this royalty relief.
(d) Before starting to build your development and production system,
you have revised your estimated development costs, and they are more
than 120 percent of the eligible development costs associated with the
most likely scenario from your most recently approved application for
this royalty relief.
[63 FR 2618, Jan. 16, 1998; 63 FR 24747, May 5, 1998, as amended at 67
FR 1878, Jan. 15, 2002]
Sec. 203.75 What risk do I run if I request a redetermination?
If you request a redetermination after we have granted you a
suspension
[[Page 36]]
volume, you could lose some or all of the previously granted relief.
This can happen because you must file a new complete application and pay
the required fee, as discussed in Sec. 203.62. We will evaluate your
application under Sec. 203.67 using the conditions prevailing at the
time of your redetermination request. In our evaluation, we may find
that you should receive a larger, equivalent, smaller, or no suspension
volume. This means we could find that you do not qualify for the amount
of relief previously granted or for any relief at all.
Sec. 203.76 When might MMS withdraw or reduce the approved size of my
relief?
We will withdraw approval of relief for any of the following
reasons.
(a) You change the type of development system proposed in your
application (e.g., change from a fixed platform to floating production
system, or from an independent development and production system to one
with subsea wells tied back to a host production facility, etc.).
(b) You do not start building the proposed development and
production system within18 months of the date we approved your
application, unless the MMS Director grants you an extension under Sec.
203.79(c). If you start building the proposed system and then suspend
its construction before completion, and you do not restart continuous
building of the proposed system within 18 months of our approval, we
will withdraw the relief we granted.
(c) Your actual development costs are less than 80 percent of the
eligible development costs estimated in your application's most likely
scenario, and you do not report that fact in your post-production
development report (Sec. 203.70). Development costs are those
expenditures defined in Sec. 203.89(b) incurred between the application
submission date and start of production. If you report this fact in the
post-production development report, you may retain the lesser of 50
percent of the original royalty suspension volume or 50 percent of the
median of the distribution of the potentially recoverable resources
anticipated in your application.
(d) We granted you a royalty-suspension volume after you qualified
for a redetermination under Sec. 203.74(c), and we find out your actual
development costs are less than 90 percent of the eligible development
costs associated with your application's most likely scenario.
Development costs are those expenditures defined in Sec. 203.89(b)
incurred between your application submission date and start of
production.
(e) You do not send us the fabrication confirmation report or the
post-production development report, or you provide false or
intentionally inaccurate information that was material to our granting
royalty relief under this section. You must pay royalties and late-
payment interest determined under 30 U.S.C. 1721 and Sec. 218.54 of
this chapter on all volumes for which you used the royalty suspension.
You also may be subject to penalties under other provisions of law.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1878, Jan. 15, 2002]
Sec. 203.77 May I voluntarily give up relief if conditions change?
Yes, by sending a letter to that effect to the MMS Regional Director
for the GOM.
[67 FR 1878, Jan. 15, 2002]
Sec. 203.78 Do I keep relief if prices rise significantly?
If prices rise above a base price for light sweet crude oil or
natural gas, set by statute for pre-Act leases, indicated in your
original lease agreement or Notice of Sale for post-November 2000 deep
water leases, you must pay full royalties as prescribed in this section.
For post-November 2000 deepwater leases, price thresholds apply on a
lease basis, so different leases on the same field, development project,
or expansion project may have different price thresholds.
(a) Suppose the arithmetic average of the daily closing NYMEX light
sweet crude oil prices for the previous calendar year exceeds $28.00 per
barrel, as adjusted in paragraph (f) of this section. In this case, we
retract the royalty relief authorized in this section and you must:
[[Page 37]]
(1) Pay royalties on all oil production for the previous year at the
lease stipulated royalty rate plus interest (under 30 U.S.C. 1721 and
Sec. 218.54 of this chapter) by March 31 of the current calendar year,
and
(2) Pay royalties on all your oil production in the current year.
(b) Suppose the arithmetic average of the daily closing NYMEX
natural gas prices for the previous calendar year exceeds $3.50 per
million British thermal units (Btu), as adjusted in paragraph (f) of
this section. In this case, we retract the royalty relief authorized in
this section and you must:
(1) Pay royalties on all natural gas production for the previous
year at the lease stipulated royalty rate plus interest (under 30 U.S.C.
1721 and Sec. 218.54 of this chapter) by March 31 of the current
calendar year, and
(2) Pay royalties on all your natural gas production in the current
year.
(c) Production under both paragraphs (a) and (b) of this section
counts as part of the royalty-suspension volume.
(d) You are entitled to a refund or credit, with interest, of
royalties paid on any production (that counts as part of the royalty-
suspension volume):
(1) Of oil if the arithmetic average of the closing oil prices for
the current calendar year is $28.00 per barrel or less, as adjusted in
paragraph (f) of this section, and
(2) Of gas if the arithmetic average of the closing natural gas
prices for the current calendar year is $3.50 per million Btu or less,
as adjusted in paragraph (f) of this section.
(e) You must follow our regulations in part 230 of this chapter for
receiving refunds or credits.
(f) We change the prices referred to in paragraphs (a), (b), and (d)
of this section periodically. For pre-Act leases, these prices change
during each calendar year after 1994 by the percentage that the implicit
price deflator for the gross domestic product changed during the
preceding calendar year. For post-November 2000 deepwater leases, these
prices change as indicated in the lease instrument or in the Notice of
Sale under which we issued the lease.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1878, Jan. 15, 2002]
Sec. 203.79 How do I appeal MMS's decisions related to Deep Water Royalty
Relief?
(a) Once we have designated your lease as part of a field and
notified you and other affected operators of the designation, you can
request reconsideration by sending the MMS Director a letter within 15
days that also states your reasons. The MMS Director's response is the
final agency action.
(b) Our decisions on your application for relief from paying royalty
under Sec. 203.67 and the royalty-suspension volumes under Sec. 203.69
are final agency actions.
(c) If you cannot start construction by the deadline in Sec.
203.76(b) for reasons beyond your control (e.g., strike at the
fabrication yard), you may request an extension up to 1 year by writing
the MMS Director and stating your reasons. The MMS Director's response
is the final agency action.
(d) We will notify you of all final agency actions by certified
mail, return receipt requested. Final agency actions are not subject to
appeal to the Interior Board of Land Appeals under 30 CFR part 290 and
43 CFR part 4. They are judicially reviewable under section 10(a) of the
Administrative Procedure Act (5 U.S.C. 702) only if you file an action
within 30 days of the date you receive our decision.
Sec. 203.80 When can I get royalty relief if I am not eligible for end-of-
life or deep water royalty relief?
We may grant royalty relief when it serves the statutory purposes
summarized in Sec. 203.1, and our formal relief programs provide
inadequate encouragement to increase production or development. Unless
your lease lies wholly west of 87 degrees, 30 minutes West longitude in
the Gulf of Mexico, your lease must be producing to qualify for relief.
Before you may apply for royalty relief apart from our end-of-life or
deepwater programs, we must agree that your lease or project has two or
more of the following characteristics:
(a) The lease has produced for a substantial period and the lessee
can recover significant additional resources. Significant additional
resources means enough to allow production for at least
[[Page 38]]
a year more than would be profitable without royalty relief.
(b) Valuable facilities (e.g., a platform or pipeline that would be
removed upon lease relinquishment) exist that we do not expect a
successor lessee to use. If the facilities are located off the lease,
their preservation must depend on continued production from the lease
applying for royalty relief. We will only consider an allocable share of
costs for off-lease facilities in the relief application.
(c) A substantial risk exists that no new lessee will recover the
resources.
(d) The lessee made major efforts to reduce operating costs too
recently to use the formal program for royalty relief (e.g., recent
significant change in operations).
(e) Circumstances beyond the lessee's control, other than water
depth, preclude reliance on one of the existing royalty relief programs.
[67 FR 1879, Jan. 15, 2002]
Required Reports
Sec. 203.81 What supplemental reports do royalty-relief applications
require?
(a) You must send us the supplemental reports, indicated in the
following table by an X, that apply to your field. Sections 203.83
through 203.91 describe these reports in detail.
----------------------------------------------------------------------------------------------------------------
Deep water
End-of- ------------------------------------------
Required reports life Expansion Pre-act Development
lease project lease project
----------------------------------------------------------------------------------------------------------------
(1) Administrative information Report..................... X X X X
(2) Net revenue & relief justification report............. X
(3) Economic viability & relief justification report (RSVP ......... X X X
model imputs justified by other required reports)........
(4) G&G report............................................ ......... X X X
(5) Engineering report.................................... ......... X X X
(6) Production report..................................... ......... X X X
(7) Deep water cost report................................ ......... X X X
(8) Fabricator's confirmation report...................... ......... X X X
(9) Post-production development report.................... ......... X X X
----------------------------------------------------------------------------------------------------------------
(b) You must certify that all information in your application,
fabricator's confirmation and post-production development reports is
accurate, complete, and conforms to the most recent content and
presentation guidelines available from the MMS GOM Regional Office.
(c) With your application and post-production development report,
you must submit an additional report prepared by an independent CPA
that:
(1) Assesses the accuracy of the historical financial information in
your report; and
(2) Certifies that the content and presentation of the financial
data and information conform to our most recent guidelines on royalty
relief. This means the data and information must--
(i) Include only eligible costs that are incurred during the
qualification months; and
(ii) Be shown in the proper format.
(d) You must identify the people in the CPA firm who prepared the
reports referred to in paragraph (c) of this section and make them
available to us to respond to questions about the historical financial
information. We may also further review your records to support this
information.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002]
Sec. 203.82 What is MMS's authority to collect this information?
The Office of Management and Budget (OMB) approved the information
collection requirements in part 203 under 44 U.S.C. 3501 et seq. and
assigned OMB control number 1010-0071.
(a) We use the information to determine whether royalty relief will
result in production that wouldn't otherwise occur. We rely largely on
your information to make these determinations.
(1) Your application for royalty relief must contain enough
information on finances, economics, reservoirs, G&G
[[Page 39]]
characteristics, production, and engineering estimates for us to
determine whether:
(i) We should grant relief under the law, and
(ii) The requested relief will ultimately recover more resources and
return a reasonable profit on project investments.
(2) Your fabricator confirmation and post-production development
reports must contain enough information for us to verify that your
application reasonably represented your plans.
(b) Applicants (respondents) are Federal OCS oil and gas lessees.
Applications are required to obtain or retain a benefit. Therefore, if
you apply for royalty relief, you must provide this information. We will
protect information considered proprietary under applicable law and
under regulations at Sec. 203.63(b) and part 250 of this chapter.
(c) The Paperwork Reduction Act of 1995 requires us to inform you
that we may not conduct or sponsor, and you are not required to respond
to, a collection of information unless it displays a currently valid OMB
control number.
(d) Send comments regarding any aspect of the collection of
information under this part, including suggestions for reducing the
burden, to the Information Collection Clearance Officer, Minerals
Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC
20240.
[63 FR 2618, Jan. 16, 1998, as amended at 65 FR 2875, Jan. 19, 2000]
Sec. 203.83 What is in an administrative information report?
This report identifies the field or lease for which royalty relief
is requested and must contain the following items:
(a) The field or lease name;
(b) The serial number of leases we have assigned to the field, names
of the lease title holders of record, the lease operators, and whether
any lease is part of a unit;
(c) Well number, API number, location, and status of each well that
has been drilled on the field or lease or project (not required for non-
oil and gas leases);
(d) The location of any new wells proposed under the terms of the
application (not required for non-oil and gas leases);
(e) A description of field or lease history;
(f) Full information as to whether you will pay royalties or a share
of production to anyone other than the United States, the amount you
will pay, and how much you will reduce this payment if we grant relief;
(g) The type of royalty relief you are requesting;
(h) Confirmation that we approved a DOCD or supplemental DOCD (Deep
Water expansion project applications only); and
(i) A narrative description of the development activities associated
with the proposed capital investments and an explanation of proposed
timing of the activities and the effect on production (Deep Water
applications only).
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002]
Sec. 203.84 What is in a net revenue and relief justification report?
This report presents cash flow data for 12 qualifying months, using
the format specified in the ``Guidelines for the Application, Review,
Approval, and Administration of Royalty Relief for End-of-Life Leases'',
U.S. Department of the Interior, MMS. Qualifying months for an oil and
gas lease are the most recent 12 months out of the last 15 months that
you produced at least 100 BOE per day on average. Qualifying months for
other than oil and gas leases are the most recent 12 of the last 15
months having some production.
(a) The cash flow table you submit must include historical data for:
(1) Lease production subject to royalty;
(2) Total revenues;
(3) Royalty payments out of production;
(4) Total allowable costs; and
(5) Transportation and processing costs.
(b) Do not include in your cash flow table the non-allowable costs
listed at 30 CFR 220.013 or:
(1) OCS rental payments on the lease(s) in the application;
(2) Damages and losses;
(3) Taxes;
[[Page 40]]
(4) Any costs associated with exploratory activities;
(5) Civil or criminal fines or penalties;
(6) Fees for your royalty relief application; and
(7) Costs associated with existing obligations (e.g., royalty
overrides or other forms of payment for acquiring the lease,
depreciation on previously acquired equipment or facilities).
(c) We may, in reviewing and evaluating your application, disallow
costs when you have not shown they are necessary to operate the lease,
or if they are inconsistent with end-of-life operations.
[63 FR 2618, Jan. 16, 1998, as amended at 63 FR 57249, Oct. 27, 1998]
Sec. 203.85 What is in an economic viability and relief justification
report?
This report should show that your project appears economic without
royalties and sunk costs using the RSVP model we provide. The format of
the report and the assumptions and parameters we specify are found in
the ``Guidelines for the Application, Review, Approval and
Administration of the Deep Water Royalty Relief Program,'' U.S.
Department of the Interior, MMS. Clearly justify each parameter you set
in every scenario you specify in the RSVP. You may provide supplemental
information, including your own model and results. The economic
viability and relief justification report must contain the following
items for an oil and gas lease.
(a) Economic assumptions we provide which include:
(1) Starting oil and gas prices;
(2) Real price growth;
(3) Real cost growth or decline rate, if any;
(4) Base year;
(5) Range of discount rates; and
(6) Tax rate (for use in determining after-tax sunk costs).
(b) Analysis of projected cash flow (from the date of the
application using annual totals and constant dollar values) which shows:
(1) Oil and gas production;
(2) Total revenues;
(3) Capital expenditures;
(4) Operating costs;
(5) Transportation costs; and
(6) Before-tax net cash flow without royalties, overrides, sunk
costs, and ineligible costs.
(c) Discounted values which include:
(1) Discount rate used (selected from within the range we specify).
(2) Before-tax net present value without royalties, overrides, sunk
costs, and ineligible costs.
(d) Demonstrations that:
(1) All costs, gross production, and scheduling are consistent with
the data in the G&G, engineering, production, and cost reports
(Sec. Sec. 203.86 through 203.89) and
(2) The development and production scenarios provided in the various
reports are consistent with each other and with the proposed development
system. You can use up to three scenarios (conservative, most likely,
and optimistic), but you must link each to a specific range on the
distribution of resources from the RSVP Resource Module.
Sec. 203.86 What is in a G&G report?
This report supports the reserve and resource estimates used in the
economic evaluation and must contain each of the following elements.
(a) Seismic data which includes:
(1) Non-interpreted 2D/3D survey lines reflecting any available
state-of-the-art processing technique in a format readable by MMS and
specified by the deep water royalty relief guidelines;
(2) Interpreted 2D/3D seismic survey lines reflecting any available
state-of-the-art processing technique identifying all known and
prospective pay horizons, wells, and fault cuts;
(3) Digital velocity surveys in the format of the GOM region's
letter to lessees of 10/1/90;
(4) Plat map of ``shot points;'' and
(5) ``Time slices'' of potential horizons.
(b) Well data which includes:
(1) Hard copies of all well logs in which--
(i) The 1-inch electric log shows pay zones and pay counts and
lithologic and paleo correlation markers at least every 500-feet,
(ii) The 1-inch type log shows missing sections from other logs
where faulting occurs,
[[Page 41]]
(iii) The 5-inch electric log shows pay zones and pay counts and
labeled points used in establishing resistivity of the formation, 100
percent water saturated (Ro) and the resistivity of the
undisturbed formation (Rt), and
(iv) The 5-inch porosity logs show pay zones and pay counts and
labeled points used in establishing reservoir porosity or labeled points
showing values used in calculating reservoir porosity such as bulk
density or transit time;
(2) Digital copies of all well logs spudded before December 1, 1995;
(3) Core data, if available;
(4) Well correlation sections;
(5) Pressure data;
(6) Production test results;
(7) Pressure-volume-temperature analysis, if available; and
(8) A table listing the wells and completions, and indicating which
sands and fault blocks will be targeted for completion or recompletion.
(c) Map interpretations which includes for each reservoir in the
field:
(1) Structure maps consisting of top and base of sand maps showing
well and seismic shot point locations;
(2) Isopach maps for net sand, net oil, net gas, all with well
locations;
(3) Maps indicating well surface and bottom hole locations, location
of development facilities, and shot points; and
(4) An explanation for excluding the reservoirs you are not planning
to develop.
(d) Reservoir-specific data which includes:
(1) Probability of reservoir occurrence with hydrocarbons;
(2) Probability the hydrocarbon in the reservoir is all oil and the
probability it is all gas;
(3) Distributions or point estimates (accompanied by explanations of
why distributions less appropriately reflect the uncertainty) for the
parameters used to estimate reservoir size, i.e., acres and net
thickness;
(4) Most likely values for porosity, salt water saturation, volume
factor for oil formation, and volume factor for gas formation;
(5) Distributions or point estimates (accompanied by explanations of
why distributions less appropriately reflect the uncertainty) for
recovery efficiency (in percent) and oil or gas recovery (in stock-tank-
barrels per acre-foot or in thousands of cubic feet per acre foot);
(6) A gas/oil ratio distribution or point estimate (accompanied by
explanations of why distributions less appropriately reflect the
uncertainty) for each reservoir;
(7) A yield distribution or point estimate (accompanied by
explanations of why distributions less appropriately reflect the
uncertainty) for each gas reservoir; and
(8) Reserve or resource distribution by reservoir.
(e) Aggregated reserve and resource data which includes:
(1) The aggregated distributions for reserves and resources (in BOE)
and oil fraction for your field computed by the resource module of our
RSVP model;
(2) A description of anticipated hydrocarbon quality (i.e., specific
gravity); and
(3) The ranges within the aggregated distribution for reserves and
resources that define the development and production scenarios presented
in the engineering and production reports. Typically there will be three
ranges specified by two positive reserve and resource points on the
aggregated distribution. The range at the low end of the distribution
will be associated with the conservative development and production
scenario; the middle range will be related to the most likely
development and production scenario; and, the high end range will be
consistent with the optimistic development and production scenario.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002]
Sec. 203.87 What is in an engineering report?
This report defines the development plan and capital requirements
for the economic evaluation and must contain the following elements.
(a) A description of the development concept (e.g., tension leg
platform, fixed platform, floater type, subsea tieback, etc.) which
includes:
(1) Its size along with basic design specifications and drawings;
and
(2) The construction schedule.
[[Page 42]]
(b) An identification of planned wells which includes:
(1) The number;
(2) The type (platform, subsea, vertical, deviated, horizontal);
(3) The well depth;
(4) The drilling schedule;
(5) The kind of completion (single, dual, horizontal, etc.); and
(6) The completion schedule.
(c) A description of the production system equipment which includes:
(1) The production capacity for oil and gas and a description of
limiting component(s);
(2) Any unusual problems (low gravity, paraffin, etc.);
(3) All subsea structures;
(4) All flowlines; and
(5) Schedule for installing the production system.
(d) A discussion of any plans for multi-phase development which
includes the conceptual basis for developing in phases and goals or
milestones required for starting later phases.
(e) A set of development scenarios consisting of activity timing and
scale associated with each of up to three production profiles
(conservative, most likely, optimistic) provided in the production
report for your field (Sec. 203.88). Each development scenario and
production profile must denote the likely events should the field size
turn out to be within a range represented by one of the three segments
of the field size distribution. If you send in fewer than three
scenarios, you must explain why fewer scenarios are more efficient
across the whole field size distribution.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]
Sec. 203.88 What is in a production report?
This report supports your development and production timing and
product quality expectations and must contain the following elements.
(a) Production profiles by well completion and field that specify
the actual and projected production by year for each of the following
products: oil, condensate, gas, and associated gas. The production from
each profile must be consistent with a specific level of reserves and
resources on the aggregated distribution of field size.
(b) Production drive mechanisms for each reservoir.
Sec. 203.89 What is in a deep water cost report?
This report lists all actual and projected costs for your field,
must explain and document the source of each cost estimate, and must
identify the following elements.
(a) Sunk costs. Report sunk costs in dollars not adjusted for
inflation and only if you have documentation.
(b) Appraisal, delineation and development costs. Base them on
actual spending, current authorization for expenditure, engineering
estimates, or analogous projects. These costs cover:
(1) Platform well drilling and average depth;
(2) Platform well completion;
(3) Subsea well drilling and average depth;
(4) Subsea well completion;
(5) Production system (platform); and
(6) Flowline fabrication and installation.
(c) Production costs based on historical costs, engineering
estimates, or analogous projects. These costs cover:
(1) Operation;
(2) Equipment; and
(3) Existing royalty overrides (we will not use the royalty
overrides in evaluations).
(d) Transportation costs, based on historical costs, engineering
estimates, or analogous projects. These costs cover:
(1) Oil or gas tariffs from pipeline or tankerage;
(2) Trunkline and tieback lines; and
(3) Gas plant processing for natural gas liquids.
(e) Abandonment costs, based on historical costs, engineering
estimates, or analogous projects. You should provide the costs to plug
and abandon only wells and to remove only production systems for which
you have not incurred costs as of the time of application submission.
You should also include a point estimate or distribution of prospective
salvage value for all potentially reusable facilities and materials,
along with the source and an explanation of the figures provided.
[[Page 43]]
(f) A set of cost estimates consistent with each one of up to three
field-development scenarios and production profiles (conservative, most
likely, optimistic). You should express costs in constant real dollar
terms for the base year. You may also express the uncertainty of each
cost estimate with a minimum and maximum percentage of the base value.
(g) A spending schedule. You should provide costs for each year (in
real dollars) for each category in paragraphs (a) through (f) of this
section.
(h) A summary of other costs which are ineligible for evaluating
your need for relief. These costs cover:
(1) Expenses before first discovery on the field;
(2) Cash bonuses;
(3) Fees for royalty relief applications;
(4) Lease rentals, royalties, and payments of net profit share and
net revenue share;
(5) Legal expenses;
(6) Damages and losses;
(7) Taxes;
(8) Interest or finance charges, including those embedded in
equipment leases;
(9) Fines or penalties; and
(10) Money spent on previously existing obligations (e.g., royalty
overrides or other forms of payment for acquiring a financial position
in a lease, expenditures for plugging wells and removing and abandoning
facilities that existed on the application submission date).
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]
Sec. 203.90 What is in a fabricator's confirmation report?
This report shows you have committed in a timely way to the approved
system for production. This report must include the following (or its
equivalent for unconventionally acquired systems):
(a) A copy of the contract(s) under which the fabrication yard is
building the approved system for you;
(b) A letter from the contractor building the system to the MMS's
GOM Regional Supervisor--Production and Development, certifying when
construction started on your system; and
(c) Evidence of an appropriate down payment or equal action that
you've started acquiring the approved system.
Sec. 203.91 What is in a post-production development report?
For each cost category in the deep water cost report, you must
compare actual costs up to the date when production starts to your
planned pre-production costs. If your application included more than one
development scenario, you need to compare actual costs with those in
your scenario of most likely development. Also, you must have this
report certified by an independent CPA according to Sec. 203.81(c).
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]
Subpart C--Federal and Indian Oil [Reserved]
Subpart D--Federal and Indian Gas [Reserved]
Subpart E--Solid Minerals, General [Reserved]
Subpart F_Coal
Sec. 203.250 Advance royalty.
Provisions for the payment of advance royalty in lieu of continued
operation are contained at 43 CFR 3483.4.
[54 FR 1522, Jan. 13, 1989]
Sec. 203.251 Reduction in royalty rate or rental.
An application for reduction in coal royalty rate or rental shall be
filed and processed in accordance with 43 CFR group 3400.
[54 FR 1522, Jan. 13, 1989]
Subpart G--Other Solid Minerals [Reserved]
Subpart H--Geothermal Resources [Reserved]
Subpart I--OCS Sulfur [Reserved]
[[Page 44]]
PART 204_ALTERNATIVES FOR MARGINAL PROPERTIES--Table of Contents
Subpart A_General Provisions
Sec.
204.1 What is the purpose of this part?
204.2 What definitions apply to this part?
204.3 What alternatives are available for marginal properties?
204.4 What is a marginal property under this part?
204.5 What statutory requirements must I meet to obtain royalty
prepayment or accounting and auditing relief?
204.6 May I appeal if MMS denies my request for prepayment or other
relief?
Subpart B--Prepayment of Royalty [Reserved]
Subpart C_Accounting and Auditing Relief
204.200 What is the purpose of this subpart?
204.201 Who may obtain accounting and auditing relief?
204.202 What is the cumulative royalty reports and payments relief
option?
204.203 What is the other relief option?
204.204 What accounting and auditing relief will MMS not allow?
204.205 How do I obtain accounting and auditing relief?
204.206 What will MMS do when it receives my request for other relief?
204.207 Who will approve, deny, or modify my request for accounting and
auditing relief?
204.208 May a State decide that it will or will not allow one or both of
the relief options under this subpart?
204.209 What if a property ceases to qualify for relief obtained under
this subpart?
204.210 What if a property is approved as part of a nonqualifying
agreement?
204.211 When may MMS rescind relief for a property?
204.212 What if I took relief for which I was ineligible?
204.213 May I obtain relief for a property that benefits from other
Federal or State incentive programs?
204.214 Is minimum royalty due on a property for which I took relief?
204.215 Are the information collection requirements in this subpart
approved by the Office of Management and Budget (OMB)?
Authority: 30 U.S.C. 1701 et seq.
Source: 69 FR 55088, Sept. 13, 2004, unless otherwise noted.
Subpart A_General Provisions
Sec. 204.1 What is the purpose of this part?
This part explains how you as a lessee or designee of a Federal
onshore or Outer Continental Shelf (OCS) oil and gas lease may obtain
prepayment or accounting and auditing relief for production from certain
marginal properties. This part does not apply to production from Indian
leases, even if the Indian lease is within an agreement that qualifies
as a marginal property.
Sec. 204.2 What definitions apply to this part?
Agreement means a federally approved communitization agreement or
unit participating area.
Barrels of oil equivalent (BOE) means the combined equivalent
production of oil and gas stated in barrels of oil. Each barrel of oil
production is equal to one BOE. Also, each 6,000 cubic feet of gas
production is equal to one BOE.
Base period means the 12-month period from July 1 through June 30
immediately preceding the calendar year for which you take or request
marginal property relief. For example, if you request relief for
calendar year 2006, your base period is July 1, 2004, through June 30,
2005.
Combined equivalent production means the total of all oil and gas
production for the marginal property, stated in BOE.
Designee means the person designated by a lessee under 30 CFR 218.52
to make all or part of the royalty or other payments due on a lease on
the lessee's behalf.
Producing wells means only those producing oil or gas wells that
contribute to the sum of BOE used in the calculation under Sec.
204.4(c). Producing wells do not include injection or water wells. Wells
with multiple zones commingled downhole are considered as a single well.
Property means a lease, a portion of a lease, or an agreement that
may be a marginal property if it meets the qualification requirements of
Sec. 204.4.
State concerned (State) means the State that receives a statutorily
prescribed portion of the royalties from a Federal onshore or OCS lease.
[[Page 45]]
Sec. 204.3 What alternatives are available for marginal properties?
If you have production from a marginal property, MMS and the State
may allow you the following options:
(a) Prepay royalty. MMS and the State may allow you to make a lump-
sum advance payment of royalties instead of monthly royalty payments for
the remainder of the lease term. See Subpart B for prepayment of royalty
requirements.
(b) Take accounting and auditing relief. MMS and the State may allow
various accounting and auditing relief options to encourage you to
continue to produce and develop your marginal property. See Subpart C
for accounting and auditing relief requirements.
Sec. 204.4 What is a marginal property under this part?
(a) To qualify as a marginal property eligible for royalty
prepayment or accounting and auditing relief under this part, the
property must meet the following requirements:
------------------------------------------------------------------------
If your lease is . . . Then . . . And . . .
------------------------------------------------------------------------
(1) Not in an agreement......... The lease must ..................
qualify as a
marginal property
under paragraph
(b) of this
section.
(2) Entirely or partly committed The entire Agreement
to one agreement. agreement must production
qualify as a allocable to your
marginal property lease may be
under paragraph eligible for
(b) of this relief under this
section. part. Any
production from
your lease that
is not committed
to the agreement
also may be
eligible for
separate relief
under paragraph
(a)(4) of this
table.
(3) Entirely or partly committed Each agreement For any agreement
to more than one agreement. must qualify that does
separately as a qualify, that
marginal property agreement's
under paragraph production
(b) of this allocable to your
section. lease may be
eligible for
relief under this
part. Any
production from
your lease that
is not committed
to an agreement
also may be
eligible for
separate relief
under paragraph
(a)(4) of this
table.
(4) Partly committed to an The part of the
agreement and you have lease that is not
production from the part of the committed to the
lease that is not committed to agreement must
the agreement. qualify
separately as a
marginal property
under paragraph
(b) of this
section.
------------------------------------------------------------------------
(b) To qualify as a marginal property for a calendar year, the
combined equivalent production of the property during the base period
must equal an average daily well production of less than 15 barrels of
oil equivalent (BOE) per well per day calculated under paragraph (c) of
this section.
(c) To determine the average daily well production for a property,
divide the sum of the BOE for all producing wells on the property during
the base period by the sum of the number of days that each of those
wells actually produced during the base period. If the property is an
agreement, your calculation under this paragraph must include all wells
included in the agreement, even if they are not on a Federal onshore or
OCS lease.
Sec. 204.5 What statutory requirements must I meet to obtain royalty
prepayment or accounting and auditing relief?
(a) MMS and the State may allow royalty prepayment or accounting and
auditing relief for your marginal property production if MMS and the
State jointly determine that the prepayment or accounting and auditing
relief is in the best interests of the Federal Government and the State
to:
(1) Promote production;
(2) Reduce the administrative costs of MMS and the State; and
(3) Increase net receipts to the Federal Government and the State.
(b) At any time, if MMS and the State determine that either
prepayment or accounting and auditing relief no longer meets the
criteria in paragraph (a) of this section, MMS, with
[[Page 46]]
the State's concurrence, may discontinue any prepayment or accounting
and auditing relief options granted for production from any marginal
property.
(1) MMS will provide you written notice of the decision to
discontinue relief.
(i) If you took the cumulative reports and payments relief option
under Sec. 204.202, your relief will terminate at the end of the
calendar year in which you received the notice.
(ii) If you were approved for prepayment relief under subpart B of
this part or other relief under Sec. 204.203, MMS's notice will tell
you when your relief terminates.
(2) MMS's decision to discontinue relief is not subject to
administrative appeal.
Sec. 204.6 May I appeal if MMS denies my request for prepayment or other
relief?
If MMS denies your request for prepayment relief under Subpart B of
this part or other relief under Sec. 204.203, you may appeal under 30
CFR part 290.
Subpart B--Prepayment of Royalty [Reserved]
Subpart C_Accounting and Auditing Relief
Sec. 204.200 What is the purpose of this subpart?
This subpart explains how you as a lessee or designee may obtain
accounting and auditing relief for your Federal onshore or OCS lease
production from a marginal property. The two types of accounting and
auditing relief that you can receive under this subpart are cumulative
reports and payment relief (explained in Sec. 204.202) and other
accounting and auditing relief appropriate for your property (explained
in Sec. 204.203).
Sec. 204.201 Who may obtain accounting and auditing relief?
(a) You may obtain accounting and auditing relief under this
subpart:
(1) If you are a lessee or a designee for a Federal lease with
production from a property that qualifies as a marginal property under
Sec. 204.4;
(2) If you meet any additional requirements for specific types of
relief under this subpart; and
(3) Only for the fractional interest in production from the marginal
property for which you report and pay royalty. You may obtain relief
even if the other lessees or designees for your lease or agreement do
not request relief.
(b) You may not obtain one or both of the relief options specified
in this subpart on any portion of production from a marginal property
if:
(1) The marginal property covers multiple States; and
(2) One of the States determines under Sec. 204.208 that it will
not allow the relief option you seek.
Sec. 204.202 What is the cumulative royalty reports and payments relief
option?
(a) The cumulative royalty reports and payments relief option allows
you to submit one royalty report and payment annually for production
during a calendar year. You are eligible for this option only if the
total volume produced from the marginal property (not just your share of
the production) is 1,000 BOE or less during the base period.
(b) To use the cumulative royalty reports and payments relief
option, you must do all of the following:
(1) Notify MMS in writing by January 31 of the calendar year for
which you begin taking your relief. See Sec. 204.205(a) for what your
notification must contain;
(2) Submit your royalty report and payment in accordance with 30 CFR
218.51(g) by the end of February of the year following the calendar year
for which you reported annually, unless you have an estimated payment on
file. If you have an estimated payment on file, you must submit your
royalty report and payment by the end of March of the year following the
calendar year for which you reported annually;
(3) Use the sales month prior to the month that you submit your
annual report and payment under paragraph (b)(2) of this section on your
Report of Sales and Royalty Remittance, Form MMS-2014, for the entire
previous calendar year's production for which you are paying annually.
(For example, for
[[Page 47]]
a report in February use January as your sales month, and for a report
in March use February as your sales month, to report production for the
entire previous calendar year for which you are paying annually);
(4) Report one line of cumulative royalty information on Form MMS-
2014 for the calendar year, the same as if it were a monthly report; and
(5) Report allowances on Form MMS-2014 on the same annual basis as
the royalties for your marginal property production.
(c) If you do not pay your royalty by the date due in paragraph (b)
of this section, you will owe late payment interest determined under 30
CFR 218.54 from the date your payment was due under this section until
the date MMS receives it.
(d) If you take relief you are not qualified for, you may be liable
for civil penalties. Also you must:
(1) Pay MMS late payment interest determined under 30 CFR 218.54
from the date your payment was due until the date MMS receives it; and
(2) Amend your Form MMS-2014 to reflect the required monthly
reporting.
(e) If you dispose of your ownership interest in a marginal property
for which you have taken relief under this section (or if you are a
designee who reports and pays royalty for a lessee who has disposed of
its ownership interest), you must:
(1) Report and pay royalties for the portion of the calendar year
for which you had an ownership interest; and
(2) Make the report and payment by the end of the month after you
dispose of the ownership interest in the marginal property. If you do
not report and pay timely, you will owe interest determined under 30 CFR
218.54 from the date the payment was due under this section.
Sec. 204.203 What is the other relief option?
(a) Under this relief option, you may request any type of accounting
and auditing relief that is appropriate for production from your
marginal property, provided it is not prohibited under Sec. 204.204 and
meets the statutory requirements of Sec. 204.5. Examples of relief
options you could request are:
(1) To report and pay royalties using a valuation method other than
that required under 30 CFR part 206 that approximates royalties payable
under that part 206; and
(2) To reduce your royalty audit burden. However, MMS will not
consider any request that eliminates MMS's or the States' right to
audit.
(b) You must request approval from MMS under Sec. 204.205(b), and
receive approval under Sec. 204.206 before taking relief under this
option.
Sec. 204.204 What accounting and auditing relief will MMS not allow?
MMS will not approve your request for accounting and auditing relief
under this subpart if your request:
(a) Prohibits MMS or the State from conducting any form of audit;
(b) Permanently relieves you from making future royalty reports or
payments;
(c) Provides for less frequent royalty reports and payments than
annually;
(d) Provides for you to submit royalty reports and payments at
separate times;
(e) Impairs MMS's ability to properly or efficiently account for or
distribute royalties;
(f) Requests relief for a lease under which the Federal Government
takes its royalties in kind;
(g) Alters production reporting requirements;
(h) Alters lease operation or safety requirements;
(i) Conflicts with rent, minimum royalty, or lease requirements; or
(j) Requests relief for production from a marginal property located
in whole or in part in a State that has determined that it will not
allow such relief under Sec. 204.208.
Sec. 204.205 How do I obtain accounting and auditing relief?
(a) To take cumulative reports and payments relief under Sec.
204.202, you must notify MMS in writing by January 31 of the calendar
year for which you begin taking your relief.
(1) Your notification must contain:
(i) Your company name, MMS-assigned payor code, address, phone
number, and contact name; and
[[Page 48]]
(ii) The specific MMS lease number and agreement number, if
applicable.
(2) You may file a single notification for multiple marginal
properties.
(b) To obtain other relief under Sec. 204.203, you must file a
written request for relief with MMS.
(1) Your request must contain:
(i) Your company name, MMS-assigned payor code, address, phone
number, and contact name;
(ii) The MMS lease number and agreement number, if applicable; and
(iii) A complete and detailed description of the specific accounting
or auditing relief you seek.
(2) You may file a single request for multiple marginal properties
if you are requesting the same relief for all properties.
Sec. 204.206 What will MMS do when it receives my request for other relief?
When MMS receives your request for other relief under Sec.
204.205(b), it will notify you in writing as follows:
(a) If your request for relief is complete, MMS may either approve,
deny, or modify your request in writing after consultation with any
State required under Sec. 204.207(b).
(1) If MMS approves your request for relief, MMS will notify you of
the effective date of your accounting or auditing relief and other
specifics of the relief approved.
(2) If MMS denies your relief request, MMS will notify you of the
reasons for denial and your appeal rights under Sec. 204.6.
(3) If MMS modifies your relief request, MMS will notify you of the
modifications.
(i) You have 60 days from your receipt of MMS's notice to either
accept or reject any modification(s) in writing.
(ii) If you reject the modification(s) or fail to respond to MMS's
notice, MMS will deny your relief request. MMS will notify you in
writing of the reasons for denial and your appeal rights under Sec.
204.6.
(b) If your request for relief is not complete, MMS will notify you
in writing that your request is incomplete and identify any missing
information.
(1) You must submit the missing information within 60 days of your
receipt of MMS's notice that your request is incomplete.
(2) After you submit all required information, MMS may approve,
deny, or modify your request for relief under paragraph (a) of this
section.
(3) If you do not submit all required information within 60 days of
your receipt of MMS's notice that your request is incomplete, MMS will
deny your relief request. MMS will notify you in writing of the reasons
for denial and your appeal rights under Sec. 204.6.
(4) You may submit a new request for relief under this subpart at
any time after MMS returns your incomplete request.
Sec. 204.207 Who will approve, deny, or modify my request for accounting and
auditing relief?
(a) If there is not a State concerned for your marginal property,
only MMS will decide whether to approve, deny, or modify your relief
request.
(b) If there is a State concerned for your marginal property that
has determined in advance under Sec. 204.208 that it will allow either
or both of the relief options under this subpart, MMS will decide
whether to approve, deny, or modify your relief request after consulting
with the State concerned.
Sec. 204.208 May a State decide that it will or will not allow one or both
of the relief options under this subpart?
(a) A State may decide in advance that it will or will not allow one
or both of the relief options specified in this subpart for a particular
calendar year. If a State decides that it will not consent to one or
both of the relief options, MMS will not grant that type of marginal
property relief.
(b) To help States decide whether to allow one or both of the relief
options specified in this subpart, for each calendar year MMS will send
States a Report of Marginal Properties by October 1 preceding the
calendar year.
(c) If a State decides under paragraph (a) of this section that it
will or will not allow one or both of the relief options in this subpart
during the next calendar year, within 30 days of the State's receipt of
the Report of Marginal Properties under paragraph (b) of this section,
the State must:
[[Page 49]]
(1) Notify the Associate Director for Minerals Revenue Management,
MMS, in writing, of its intent to allow or not allow one or both of the
relief options under this subpart; and
(2) Specify in its notice of intent to MMS which relief option(s) it
will allow or not allow.
(d) If a State decides in advance under paragraph (a) of this
section that it will not allow one or both of the relief options
specified in this subpart, it may decide for subsequent calendar years
that it will allow one or both of the relief options in this subpart. If
it so decides, within 30 days of the State's receipt of the Report of
Marginal Properties under paragraph (b) of this section, the State must:
(1) Notify the Associate Director for Minerals Revenue Management,
MMS, in writing, of its intent to allow one or both of the relief
options allowed under this subpart during the next calendar year; and
(2) Specify in its notice of intent to MMS which relief option(s) it
will allow.
(e) If a State does not notify MMS under paragraph (c) or (d) of
this section, the State will be deemed to have decided not to allow
either of the relief options under this subpart for the next calendar
year.
(f) MMS will publish a notice of the State s intent to allow or not
allow certain relief options under this section in the Federal Register
no later than 30 days before the beginning of the applicable calendar
year.
Sec. 204.209 What if a property ceases to qualify for relief obtained under
this subpart?
(a) A marginal property must qualify for relief under this subpart
for each calendar year based on production during the base period for
that calendar year. The notice or request you provided to MMS under
Sec. 204.205 for the first calendar year that the property qualified
for relief remains effective for successive calendar years if the
property continues to qualify.
(b) If a property is no longer eligible for relief for any reason
during a calendar year other than the reason under Sec. 204.210 or
paragraph (c) of this section, the relief for the property terminates as
of December 31 of that calendar year. You must notify MMS in writing by
December 31 that the relief for the property has terminated.
(c) If you dispose of your interest in a marginal property during
the calendar year, your relief terminates as of the end of the sales
month in which you disposed of the property. Report and pay royalties
for your production using the procedures in Sec. 204.202(e).
Sec. 204.210 What if a property is approved as part of a nonqualifying
agreement?
If the Bureau of Land Management (BLM) or MMS's Offshore Minerals
Management (OMM) retroactively approves a marginal property that
qualified for relief for inclusion as part of an agreement that does not
qualify for relief under this subpart, the property no longer qualifies
for relief under this subpart then:
(a) MMS will not retroactively rescind the marginal property relief
for production from your property under Sec. 204.211;
(b) Your marginal property relief terminates as of December 31 of
the calendar year that you receive the BLM or OMM approval of your
marginal property as part of a nonqualifying agreement; and
(c) For the calendar year in which you receive the BLM or OMM
approval, and for any previous period affected by the approval, the
volumes on which you report and pay royalty for your lease must be
amended to reflect all volumes produced on or allocated to your lease
under the nonqualifying agreement as modified by BLM or OMM. Report and
pay royalties for your production using the procedures in Sec.
204.202(b).
(d) If you owe additional royalties based on the retroactive
agreement approval and do not pay your royalty by the date due in Sec.
204.202(b), you will owe late payment interest determined under 30 CFR
218.54 from the date your payment was due under Sec. 204.202 (b)(2)
until the date MMS receives it.
[[Page 50]]
Sec. 204.211 When may MMS rescind relief for a property?
(a) MMS may retroactively rescind the relief for your property if
MMS determines that your property was not eligible for the relief
obtained under this subpart because:
(1) You did not submit a notice or request for relief under Sec.
204.205;
(2) You submitted erroneous information in the notice or request for
relief you provided to MMS under Sec. 204.205 or in your royalty or
production reports; or
(3) Your property is no longer eligible for relief because
production increased, but you failed to provide the notice required
under Sec. 204.209(b).
(b) MMS may rescind relief for your property if MMS decides to take
royalty in kind.
Sec. 204.212 What if I took relief for which I was ineligible?
If you took relief under this subpart for a period for which you
were not eligible, you:
(a) May owe additional royalties and late payment interest
determined under 30 CFR 218.54 from the date your additional payments
were due until the date MMS receives them; and
(b) May be subject to civil penalties.
Sec. 204.213 May I obtain relief for a property that benefits from other
Federal or State incentive programs?
You may obtain accounting and auditing relief for production from a
marginal property under this subpart even if the property benefits from
other Federal or State production incentive programs.
Sec. 204.214 Is minimum royalty due on a property for which I took relief?
(a) If you took cumulative royalty reports and payment relief on a
property under this subpart, minimum royalty is still due for that
property by the date prescribed in your lease and in the amount
prescribed therein.
(b) If you pay minimum royalty on production from a marginal
property during a calendar year for which you are taking cumulative
royalty reports and payment relief, and:
(1) The annual payment you owe under this subpart is greater than
the minimum royalty you paid, you must pay the difference between the
minimum royalty you paid and your annual payment due under this subpart;
or
(2) The annual payment you owe under this subpart is less than the
minimum royalty you paid, you are not entitled to a credit because you
must pay at least the minimum royalty amount on your lease each year.
Sec. 204.215 Are the information collection requirements in this subpart
approved by the Office of Management and Budget (OMB)?
OMB has approved the information collection requirements contained
in this subpart under 44 U.S.C. 3501 et seq., and assigned OMB control
number 1010-0155. See 30 CFR part 210 for details concerning your
estimated reporting burden and how you may comment on the accuracy of
the burden estimate.
PART 206_PRODUCT VALUATION--Table of Contents
Subpart A_General Provisions
Sec.
206.10 Information collection.
Subpart B_Indian Oil
206.50 Purpose and scope.
206.51 Definitions.
206.52 Valuation standards.
206.53 Point of royalty settlement.
206.54 Transportation allowances--general.
206.55 Determination of transportation allowances.
Subpart C_Federal Oil
206.100 What is the purpose of this subpart?
206.101 What definitions apply to this subpart?
206.102 How do I calculate royalty value for oil that I or my affiliate
sell(s) under an arm's-length contract?
206.103 How do I value oil that is not sold under an arm's-length
contract?
206.104 What publications are acceptable to MMS?
206.105 What records must I keep to support my calculations of value
under this subpart?
206.106 What are my responsibilities to place production into marketable
condition and to market production?
206.107 How do I request a value determination?
[[Page 51]]
206.108 Does MMS protect information I provide?
206.109 When may I take a transportation allowance in determining value?
206.110 How do I determine a transportation allowance under an arm's-
length transportation contract?
206.111 How do I determine a transportation allowance if I do not have
an arm's-length transportation contract or arm's-length
tariff?
206.112 What adjustments and transportation allowances apply when I
value oil production from my lease using NYMEX prices or ANS
spot prices?
206.113 How will MMS identify market centers?
206.114 What are my reporting requirements under an arm's-length
transportation contract?
206.115 What are my reporting requirements under a non-arm's-length
transportation arrangement?
206.116 What interest and assessments apply if I improperly report a
transportation allowance?
206.117 What reporting adjustments must I make for transportation
allowances?
206.119 How are the royalty quantity and quality determined?
206.120 How are operating allowances determined?
Subpart D_Federal Gas
206.150 Purpose and scope.
206.151 Definitions.
206.152 Valuation standards--unprocessed gas.
206.153 Valuation standards--processed gas.
206.154 Determination of quantities and qualities for computing
royalties.
206.155 Accounting for comparison.
206.156 Transportation allowances--general.
206.157 Determination of transportation allowances.
206.158 Processing allowances--general.
206.159 Determination of processing allowances.
206.160 Operating allowances.
Subpart E_Indian Gas
206.170 What does this subpart contain?
206.171 What definitions apply to this subpart?
206.172 How do I value gas produced from leases in an index zone?
206.173 How do I calculate the alternative methodology for dual
accounting?
206.174 How do I value gas production when an index-based method cannot
be used?
206.175 How do I determine quantities and qualities of production for
computing royalties?
206.176 How do I perform accounting for comparison?
Transportation Allowances
206.177 What general requirements regarding transportation allowances
apply to me?
206.178 How do I determine a transportation allowance?
Processing Allowances
206.179 What general requirements regarding processing allowances apply
to me?
206.180 How do I determine an actual processing allowance?
206.181 How do I establish processing costs for dual accounting purposes
when I do not process the gas?
Subpart F_Federal Coal
206.250 Purpose and scope.
206.251 Definitions.
206.252 Information collection.
206.253 Coal subject to royalties--general provisions.
206.254 Quality and quantity measurement standards for reporting and
paying royalties.
206.255 Point of royalty determination.
206.256 Valuation standards for cents-per-ton leases.
206.257 Valuation standards for ad valorem leases.
206.258 Washing allowances--general.
206.259 Determination of washing allowances.
206.260 Allocation of washed coal.
206.261 Transportation allowances--general.
206.262 Determination of transportation allowances.
206.263 [Reserved]
206.264 In-situ and surface gasification and liquefaction operations.
206.265 Value enhancement of marketable coal.
Subpart G_Other Solid Minerals
206.301 Value basis for royalty computation.
Subpart H_Geothermal Resources
206.350 What is the purpose of this subpart?
206.351 What definitions apply to this subpart?
206.352 How do I calculate the royalty due on geothermal resources used
for commercial production or generation of electricity?
206.353 How do I determine transmission deductions?
206.354 How do I determine generating deductions?
206.355 How do I calculate royalty due on geothermal resources I sell at
arm's length to a purchaser for direct use?
206.356 How do I calculate royalty due on geothermal resources I use for
direct use purposes?
[[Page 52]]
206.357 How do I calculate royalty due on byproducts?
206.358 What are byproduct transportation allowances?
206.359 How do I determine byproduct transportation allowances?
206.360 What records must I keep to support my calculations of royalty
or fees under this subpart?
206.361 How will MMS determine whether my royalty or direct use fee
payments are correct?
206.362 What are my responsibilities to place production into marketable
condition and to market production?
206.363 When is an MMS audit, review, reconciliation, monitoring, or
other like process considered final?
206.364 How do I request a value or gross proceeds determination?
206.365 Does MMS protect information I provide?
206.366 What is the nominal fee that a State, tribal, or local
government lessee must pay for the use of geothermal
resources?
Subpart I--OCS Sulfur [Reserved]
Subpart J_Indian Coal
206.450 Purpose and scope.
206.451 Definitions.
206.452 Coal subject to royalties--general provisions.
206.453 Quality and quantity measurement standards for reporting and
paying royalties.
206.454 Point of royalty determination.
206.455 Valuation standards for cents-per-ton leases.
206.456 Valuation standards for ad valorem leases.
206.457 Washing allowances--general.
206.458 Determination of washing allowances.
206.459 Allocation of washed coal.
206.460 Transportation allowances--general.
206.461 Determination of transportation allowances.
206.462 [Reserved]
206.463 In-situ and surface gasification and liquefaction operations.
206.464 Value enhancement of marketable coal.
Authority: 5 U.S.C. 301 et seq.; 25 U.S.C. 396 et seq., 396a et
seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et seq.,
1701 et seq.; 31 U.S.C. 9701.; 43 U.S.C. 1301 et seq., 1331 et seq., and
1801 et seq.
Editorial Note: Nomenclature changes to part 206 appear at 67 FR
19111, Apr. 18, 2002.
Subpart A_General Provisions
Sec. 206.10 Information collection.
The information collection requirements contained in this part have
been approved by the Office of Management and Budget (OMB) under 44
U.S.C. 3501 et seq. The forms, filing date, and approved OMB clearance
numbers are identified in 30 CFR 210.10.
[57 FR 41863, Sept. 14, 1992]
Subpart B_Indian Oil
Source: 61 FR 5455, Feb. 12, 1996, unless otherwise noted.
Sec. 206.50 Purpose and scope.
(a) This subpart is applicable to all oil production from Indian
(Tribal and allotted) oil and gas leases (except leases on the Osage
Indian Reservation, Osage County, Oklahoma). The purpose of this subpart
is to establish the value of production, for royalty purposes,
consistent with the mineral leasing laws, other applicable laws, and
lease terms.
(b) If the specific provisions of any Federal statute, treaty,
settlement agreement between the Indian lessor and a lessee resulting
from administrative or judicial litigation, or oil and gas lease subject
to the requirements of this subpart are inconsistent with any regulation
in this subpart, then the statute, treaty, lease provision or settlement
agreement shall govern to the extent of that inconsistency.
(c) All royalty payments made to MMS or Indian Tribes are subject to
audit and adjustment.
(d) The regulations in this subpart are intended to ensure that the
trust responsibilities of the United States with respect to the
administration of Indian oil and gas leases are discharged in accordance
with the requirements of the governing mineral leasing laws, treaties,
and lease terms.
Sec. 206.51 Definitions.
For the purposes of this subpart:
Allowance means an approved or an MMS-initially accepted deduction
in determining value for royalty purposes. Transportation allowance
means an allowance for the reasonable, actual
[[Page 53]]
costs incurred by the lessee for moving oil to a point of sale or point
of delivery off the lease, unit area, or communitized area, excluding
gathering, or an approved or MMS-initially accepted deduction for costs
of such transportation, determined by this subpart.
Area means a geographic region at least as large as the defined
limits of an oil and/or gas field in which oil and/or gas lease products
have similar quality, economic, and legal characteristics.
Arm's-length contract means a contract or agreement that has been
arrived at in the market place between independent, nonaffiliated
persons with opposing economic interests regarding that contract. For
purposes of this subpart, two persons are affiliated if one person
controls, is controlled by, or is under common control with another
person. For purposes of this subpart, based on the instruments of
ownership of the voting securities of an entity, or based on other forms
of ownership: ownership in excess of 50 percent constitutes control;
ownership of 10 through 50 percent creates a presumption of control; and
ownership of less than 10 percent creates a presumption of noncontrol
which MMS may rebut if it demonstrates actual or legal control,
including the existence of interlocking directorates. Notwithstanding
any other provisions of this subpart, contracts between relatives,
either by blood or by marriage, are not arm's-length contracts. MMS may
require the lessee to certify ownership control. To be considered arm's-
length for any production month, a contract must meet the requirements
of this definition for that production month, as well as when the
contract was executed.
Audit means a review, conducted in accordance with generally
accepted accounting and auditing standards, of royalty payment
compliance activities of lessees or other interest holders who pay
royalties, rents, or bonuses on Indian leases.
BIA means the Bureau of Indian Affairs of the Department of the
Interior.
BLM means the Bureau of Land Management of the Department of the
Interior.
Condensate means liquid hydrocarbons (normally exceeding 40 degrees
of API gravity) recovered at the surface without resorting to
processing. Condensate is the mixture of liquid hydrocarbons that
results from condensation of petroleum hydrocarbons existing initially
in a gaseous phase in an underground reservoir.
Contract means any oral or written agreement, including amendments
or revisions thereto, between two or more persons and enforceable by law
that with due consideration creates an obligation.
Field means a geographic region situated over one or more subsurface
oil and gas reservoirs encompassing at least the outermost boundaries of
all oil and gas accumulations known to be within those reservoirs
vertically projected to the land surface. Onshore fields are usually
given names and their official boundaries are often designated by oil
and gas regulatory agencies in the respective States in which the fields
are located.
Gathering means the movement of lease production to a central
accumulation or treatment point on the lease, unit, or communitized
area, or to a central accumulation or treatment point off the lease,
unit, or communitized area as approved by BLM operations personnel for
onshore leases.
Gross proceeds (for royalty payment purposes) means the total monies
and other consideration accruing to an oil and gas lessee for the
disposition of the oil produced. Gross proceeds includes, but is not
limited to, payments to the lessee for certain services such as
dehydration, measurement, and/or gathering to the extent that the lessee
is obligated to perform them at no cost to the Indian lessor. Gross
proceeds, as applied to oil, also includes, but is not limited to,
reimbursements for harboring or terminaling fees. Tax reimbursements are
part of the gross proceeds accruing to a lessee even though the Indian
royalty interest may be exempt from taxation. Monies and other
consideration, including the forms of consideration identified in this
paragraph, to which a lessee is contractually or legally entitled but
which it
[[Page 54]]
does not seek to collect through reasonable efforts are also part of
gross proceeds.
Indian allottee means any Indian for whom land or an interest in
land is held in trust by the United States or who holds title subject to
Federal restriction against alienation.
Indian Tribe means any Indian Tribe, band, nation, pueblo,
community, rancheria, colony, or other group of Indians for which any
land or interest in land is held in trust by the United States or which
is subject to Federal restriction against alienation.
Lease means any contract, profit-share arrangement, joint venture,
or other agreement issued or approved by the United States under a
mineral leasing law that authorizes exploration for, development or
extraction of, or removal of lease products--or the land area covered by
that authorization, whichever is required by the context.
Lease products means any leased minerals attributable to,
originating from, or allocated to Indian leases.
Lessee means any person to whom an Indian Tribe, or an Indian
allottee issues a lease, and any person who has been assigned an
obligation to make royalty or other payments required by the lease. This
includes any person who has an interest in a lease as well as an
operator or payor who has no interest in the lease but who has assumed
the royalty payment responsibility.
Like-quality lease products means lease products which have similar
chemical, physical, and legal characteristics.
Load oil means any oil which has been used with respect to the
operation of oil or gas wells for wellbore stimulation, workover,
chemical treatment, or production purposes. It does not include oil used
at the surface to place lease production in marketable condition.
Marketable condition means lease products which are sufficiently
free from impurities and otherwise in a condition that they will be
accepted by a purchaser under a sales contract typical for the field or
area.
Marketing affiliate means an affiliate of the lessee whose function
is to acquire only the lessee's production and to market that
production.
Minimum royalty means that minimum amount of annual royalty that the
lessee must pay as specified in the lease or in applicable leasing
regulations.
MMS means the Minerals Management Service of the Department of the
Interior.
Net-back method (or workback method) means a method for calculating
market value of oil at the lease. Under this method, costs of
transportation, processing, or manufacturing are deducted from the
proceeds received for the oil and any extracted, processed, or
manufactured products, or from the value of the oil or any extracted,
processed, or manufactured products at the first point at which
reasonable values for any such products may be determined by a sale
under an arm's-length contract or comparison to other sales of such
products, to ascertain value at the lease.
Net profit share (for applicable Indian lessees) means the specified
share of the net profit from production of oil and gas as provided in
the agreement.
Oil means a mixture of hydrocarbons that existed in the liquid phase
in natural underground reservoirs and remains liquid at atmospheric
pressure after passing through surface separating facilities and is
marketed or used as such. Condensate recovered in lease separators or
field facilities is considered to be oil. For purposes of royalty
valuation, the term tar sands is defined separately from oil.
Oil shale means a kerogen-bearing rock (i.e., fossilized, insoluble,
organic material). Separation of kerogen from oil shale may take place
in situ or in surface retorts by various processes. The kerogen, upon
distillation, will yield liquid and gaseous hydrocarbons.
Person means any individual, firm, corporation, association,
partnership, consortium, or joint venture (when established as a
separate entity).
Posted price means the price specified in publicly available posted
price bulletins, onshore terminal postings, or other price notices net
of all adjustments for quality (e.g., API gravity, sulfur content, etc.)
and location for oil in marketable condition.
[[Page 55]]
Processing means any process designed to remove elements or
compounds (hydrocarbon and nonhydrocarbon) from gas, including
absorption, adsorption, or refrigeration. Field processes which normally
take place on or near the lease, such as natural pressure reduction,
mechanical separation, heating, cooling, dehydration, and compression
are not considered processing. The changing of pressures and/or
temperatures in a reservoir is not considered processing.
Selling arrangement means the individual contractual arrangements
under which sales or dispositions of oil are made. Selling arrangements
are described by illustration in MMS Royalty Management Program Oil and
Gas Payor Handbook.
Spot sales agreement means a contract wherein a seller agrees to
sell to a buyer a specified amount of oil at a specified price over a
fixed period, usually of short duration, which does not normally require
a cancellation notice to terminate, and which does not contain an
obligation, nor imply an intent, to continue in subsequent periods.
Tar sands means any consolidated or unconsolidated rock (other than
coal, oil shale, or gilsonite) that contains a hydrocarbonaceous
material with a gas-free viscosity greater than 10,000 centipoise at
original reservoir temperature.
[61 FR 5455, Feb. 12, 1996, as amended at 64 FR 43288, Aug. 10, 1999]
Sec. 206.52 Valuation standards.
(a)(1) The value of production, for royalty purposes, of oil from
leases subject to this subpart shall be the value determined under this
section less applicable allowances determined under this subpart.
(2)(i) For any Indian leases which provide that the Secretary may
consider the highest price paid or offered for a major portion of
production (major portion) in determining value for royalty purposes, if
data are available to compute a major portion, MMS will, where
practicable, compare the value determined in accordance with this
section with the major portion. The value to be used in determining the
value of production, for royalty purposes, shall be the higher of those
two values.
(ii) For purposes of this paragraph, major portion means the highest
price paid or offered at the time of production for the major portion of
oil production from the same field. The major portion will be calculated
using like-quality oil sold under arm's-length contracts from the same
field (or, if necessary to obtain a reasonable sample, from the same
area) for each month. All such oil production will be arrayed from
highest price to lowest price (at the bottom).
The major portion is that price at which 50 percent (by volume) plus
1 barrel of the oil (starting from the bottom) is sold.
(b)(1)(i) The value of oil which is sold under an arm's-length
contract shall be the gross proceeds accruing to the lessee, except as
provided in paragraphs (b)(1)(ii) and (b)(1)(iii) of this section. The
lessee shall have the burden of demonstrating that its contract is
arm's-length. The value which the lessee reports, for royalty purposes,
is subject to monitoring, review, and audit. For purposes of this
section, oil which is sold or otherwise transferred to the lessee's
marketing affiliate and then sold by the marketing affiliate under an
arm's-length contract shall be valued in accordance with this paragraph
based upon the sale by the marketing affiliate.
(ii) In conducting reviews and audits, MMS will examine whether the
contract reflects the total consideration actually transferred either
directly or indirectly from the buyer to the seller for the oil. If the
contract does not reflect the total consideration, then MMS may require
that the oil sold under that contract be valued in accordance with
paragraph (c) of this section. Value may not be less than the gross
proceeds accruing to the lessee, including the additional consideration.
(iii) If MMS determines that the gross proceeds accruing to the
lessee under an arm's-length contract do not reflect the reasonable
value of the production because of misconduct by or between two
contracting parties, or because the lessee otherwise has breached its
duty to the lessor to market the production for the mutual benefit of
[[Page 56]]
the lessee and the lessor, then MMS shall require that the oil
production be valued under the first applicable of paragraph (c)(2),
(c)(3), (c)(4), or (c)(5) of this section. When MMS determines that the
value may be unreasonable, MMS will notify the lessee and give the
lessee an opportunity to provide written information justifying the
lessee's value. If the oil production is then valued under paragraph
(c)(4) or (c)(5) of this section, the notification requirements of
paragraph (e) of this section shall apply.
(2) MMS may require a lessee to certify that its arm's-length
contract provisions include all of the consideration to be paid by the
buyer, either directly or indirectly, for the oil.
(c) The value of oil production from leases subject to this section
which is not sold under an arm's-length contract shall be the reasonable
value determined in accordance with the first applicable of the
following paragraphs:
(1) The lessee's contemporaneous posted prices or oil sales contract
prices used in arm's-length transactions for purchases or sales of
significant quantities of like-quality oil in the same field (or, if
necessary to obtain a reasonable sample, from the same area); provided,
however, that those posted prices or oil sales contract prices are
comparable to other contemporaneous posted prices or oil sales contract
prices used in arm's-length transactions for purchases or sales of
significant quantities of like-quality oil in the same field (or, if
necessary to obtain a reasonable sample, from the same area). In
evaluating the comparability of posted prices or oil sales contract
prices, the following factors shall be considered: Price, duration,
market or markets served, terms, quality of oil, volume, and other
factors as may be appropriate to reflect the value of the oil. If the
lessee makes arm's-length purchases or sales at different postings or
prices, then the volume-weighted average price for the purchases or
sales for the production month will be used;
(2) The arithmetic average of contemporaneous posted prices used in
arm's-length transactions by persons other than the lessee for purchases
or sales of significant quantities of like-quality oil in the same field
(or, if necessary to obtain a reasonable sample, from the same area);
(3) The arithmetic average of other contemporaneous arm's-length
contract prices for purchases or sales of significant quantities of
like-quality oil in the same area or nearby areas;
(4) Prices received for arm's-length spot sales of significant
quantities of like-quality oil from the same field (or, if necessary to
obtain a reasonable sample, from the same area), and other relevant
matters, including information submitted by the lessee concerning
circumstances unique to a particular lease operation or the salability
of certain types of oil;
(5) A net-back method or any other reasonable method to determine
value;
(6) For purposes of this paragraph, the term lessee includes the
lessee's designated purchasing agent, and the term contemporaneous means
postings or contract prices in effect at the time the royalty obligation
is incurred.
(d) Any Indian lessee will make available, upon request to the
authorized MMS or Indian representatives, to the Office of the Inspector
General of the Department of the Interior, or other persons authorized
to receive such information, arm's-length sales and volume data for
like-quality production sold, purchased, or otherwise obtained by the
lessee from the field or area or from nearby fields or areas.
(e)(1) Where the value is determined under paragraph (c) of this
section, the lessee shall retain all data relevant to the determination
of royalty value. Such data shall be subject to review and audit, and
MMS will direct a lessee to use a different value if it determines that
the reported value is inconsistent with the requirements of these
regulations.
(2) A lessee shall notify MMS if it has determined value under
paragraph (c)(4) or (c)(5) of this section. The notification shall be by
letter to MMS Associate Director for Minerals Revenue Management or his/
her designee. The letter shall identify the valuation method to be used
and contain a brief description of the procedure to be followed. The
notification required by this paragraph is a one-time notification due
no later than the end of the
[[Page 57]]
month following the month the lessee first reports royalties on a Form
MMS-2014 using a valuation method authorized by paragraph (c)(4) or
(c)(5) of this section and each time there is a change from one to the
other of these two methods.
(f) If MMS determines that a lessee has not properly determined
value, the lessee shall pay the difference, if any, between royalty
payments made based upon the value it has used and the royalty payments
that are due based upon the value established by MMS. The lessee shall
also pay interest on the difference computed under 30 CFR 218.54. If the
lessee is entitled to a credit, MMS will provide instructions for the
taking of that credit.
(g) The lessee may request a value determination from MMS. In that
event, the lessee shall propose to MMS a value determination method and
may use that value for royalty payment purposes until MMS issues a value
determination. The lessee shall submit all available data relevant to
its proposal. MMS shall expeditiously determine the value based upon the
lessee's proposal and any additional information MMS deems necessary. In
making a value determination, MMS may use any of the valuation criteria
authorized by this subpart. That determination shall remain effective
for the period stated therein. After MMS issues its determination, the
lessee shall make the adjustments in accordance with paragraph (f) of
this section.
(h) Notwithstanding any other provision of this section, under no
circumstances shall the value of production, for royalty purposes, be
less than the gross proceeds accruing to the lessee for lease
production, less applicable allowances determined under this subpart.
(i) The lessee is required to place oil in marketable condition at
no cost to the Indian lessor unless otherwise provided in the lease
agreement or this section. Where the value established under this
section is determined by a lessee's gross proceeds, that value shall be
increased to the extent that the gross proceeds have been reduced
because the purchaser, or any other person, is providing certain
services the cost of which ordinarily is the responsibility of the
lessee to place the oil in marketable condition.
(j) Value shall be based on the highest price a prudent lessee can
receive through legally enforceable claims under its contract. Absent
contract revision or amendment, if the lessee fails to take proper or
timely action to receive prices or benefits to which it is entitled, it
must pay royalty at a value based upon that obtainable price or benefit.
Contract revisions or amendments shall be in writing and signed by all
parties to an arm's-length contract. If the lessee makes timely
application for a price increase or benefit allowed under its contract
but the purchaser refuses, and the lessee takes reasonable measures,
which are documented, to force purchaser compliance, the lessee will owe
no additional royalties unless or until monies or consideration
resulting from the price increase or additional benefits are received.
This paragraph shall not be construed to permit a lessee to avoid its
royalty payment obligation in situations where a purchaser fails to pay,
in whole or in part or timely, for a quantity of oil.
(k) Notwithstanding any provision in these regulations to the
contrary, no review, reconciliation, monitoring, or other like process
that results in a redetermination by MMS of value under this section
shall be considered final or binding as against the Indian Tribes or
allottees until the audit period is formally closed.
(l) Certain information submitted to MMS to support valuation
proposals, including transportation allowances or extraordinary cost
allowances, is exempted from disclosure by the Freedom of Information
Act, 5 U.S.C. 552, or other Federal law. Any data specified by law to be
privileged, confidential, or otherwise exempt, will be maintained in a
confidential manner in accordance with applicable laws and regulations.
All requests for information about determinations made under this part
are to be submitted in accordance with the Freedom of Information Act
regulation of the Department of the Interior, 43 CFR part 2. Nothing in
this section is intended to limit or diminish in any manner whatsoever
the right of an Indian lessor to obtain any and all information to which
such lessor may be
[[Page 58]]
lawfully entitled from MMS or such lessor's lessee directly under the
terms of the lease, 30 U.S.C. 1733, or other applicable law.
Sec. 206.53 Point of royalty settlement.
(a)(1) Royalties shall be computed on the quantity and quality of
oil as measured at the point of settlement approved by BLM for onshore
leases.
(2) If the value of oil determined under Sec. 206.52 of this
subpart is based upon a quantity and/or quality different from the
quantity and/or quality at the point of royalty settlement approved by
the BLM for onshore leases, the value shall be adjusted for those
differences in quantity and/or quality.
(b) No deductions may be made from the royalty volume or royalty
value for actual or theoretical losses. Any actual loss that may be
sustained prior to the royalty settlement metering or measurement point
will not be subject to royalty provided that such actual loss is
determined to have been unavoidable by BLM.
(c) Except as provided in paragraph (b) of this section, royalties
are due on 100 percent of the volume measured at the approved point of
royalty settlement. There can be no reduction in that measured volume
for actual losses beyond the approved point of royalty settlement or for
theoretical losses that are claimed to have taken place either prior to
or beyond the approved point of royalty settlement. Royalties are due on
100 percent of the value of the oil as provided in this subpart. There
can be no deduction from the value of the oil for royalty purposes to
compensate for actual losses beyond the approved point of royalty
settlement or for theoretical losses that are claimed to have taken
place either prior to or beyond the approved point of royalty
settlement.
[61 FR 5455, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999]
Sec. 206.54 Transportation allowances--general.
(a) Where the value of oil has been determined under Section 206.52
of this subpart at a point (e.g., sales point or point of value
determination) off the lease, MMS shall allow a deduction for the
reasonable, actual costs incurred by the lessee to transport oil to a
point off the lease; provided, however, that no transportation allowance
will be granted for transporting oil taken as Royalty-In-Kind (RIK); or
(b)(1) Except as provided in paragraph (b)(2) of this section, the
transportation allowance deduction on the basis of a selling arrangement
shall not exceed 50 percent of the value of the oil at the point of sale
as determined under Sec. 206.52 of this subpart. Transportation costs
cannot be transferred between selling arrangements or to other products.
(2) Upon request of a lessee, MMS may approve a transportation
allowance deduction in excess of the limitation prescribed by paragraph
(b)(1) of this section. The lessee must demonstrate that the
transportation costs incurred in excess of the limitation prescribed in
paragraph (b)(1) of this section were reasonable, actual, and necessary.
An application for exception (using Form MMS-4393, Request to Exceed
Regulatory Allowance Limitation) shall contain all relevant and
supporting documentation necessary for MMS to make a determination.
Under no circumstances shall the value, for royalty purposes, under any
selling arrangement, be reduced to zero.
(c) Transportation costs must be allocated among all products
produced and transported as provided in Sec. 206.55. Transportation
allowances for oil shall be expressed as dollars per barrel.
(d) If, after a review and/or audit, MMS determines that a lessee
has improperly determined a transportation allowance authorized by this
subpart, then the lessee shall pay any additional royalties, plus
interest determined in accordance with 30 CFR 218.54, or shall be
entitled to a credit, without interest.
Sec. 206.55 Determination of transportation allowances.
(a) Arm's-length transportation contracts. (1)(i) For transportation
costs incurred by a lessee under an arm's-length contract, the
transportation allowance shall be the reasonable, actual costs incurred
by the lessee for transporting oil under that contract, except as
provided in paragraphs (a)(1)(ii) and
[[Page 59]]
(a)(1)(iii) of this section, subject to monitoring, review, audit, and
adjustment. The lessee shall have the burden of demonstrating that its
contract is arm's-length. Such allowances shall be subject to the
provisions of paragraph (f) of this section. Before any deduction may be
taken, the lessee must submit a completed page one of Form MMS-4110 (and
Schedule 1), Oil Transportation Allowance Report, in accordance with
paragraph (c)(1) of this section. A transportation allowance may be
claimed retroactively for a period of not more than 3 months prior to
the first day of the month that Form MMS-4110 is filed with MMS, unless
MMS approves a longer period upon a showing of good cause by the lessee.
(ii) In conducting reviews and audits, MMS will examine whether the
contract reflects more than the consideration actually transferred
either directly or indirectly from the lessee to the transporter for the
transportation. If the contract reflects more than the total
consideration, then MMS may require that the transportation allowance be
determined in accordance with paragraph (b) of this section.
(iii) If MMS determines that the consideration paid under an arm's-
length transportation contract does not reflect the reasonable value of
the transportation because of misconduct by or between the contracting
parties, or because the lessee otherwise has breached its duty to the
lessor to market the production for the mutual benefit of the lessee and
the lessor, then MMS shall require that the transportation allowance be
determined in accordance with paragraph (b) of this section. When MMS
determines that the value of the transportation may be unreasonable, MMS
will notify the lessee and give the lessee an opportunity to provide
written information justifying the lessee's transportation costs.
(2)(i) If an arm's-length transportation contract includes more than
one liquid product, and the transportation costs attributable to each
product cannot be determined from the contract, then the total
transportation costs shall be allocated in a consistent and equitable
manner to each of the liquid products transported in the same proportion
as the ratio of the volume of each product (excluding waste products
which have no value) to the volume of all liquid products (excluding
waste products which have no value). Except as provided in this
paragraph, no allowance may be taken for the costs of transporting lease
production which is not royalty-bearing without MMS approval.
(ii) Notwithstanding the requirements of paragraph (i), the lessee
may propose to MMS a cost allocation method on the basis of the values
of the products transported. MMS shall approve the method unless it
determines that it is not consistent with the purposes of the
regulations in this part.
(3) If an arm's-length transportation contract includes both gaseous
and liquid products, and the transportation costs attributable to each
product cannot be determined from the contract, the lessee shall propose
an allocation procedure to MMS. The lessee may use the oil
transportation allowance determined in accordance with its proposed
allocation procedure until MMS issues its determination on the
acceptability of the cost allocation. The lessee shall submit all
available data to support its proposal. The initial proposal must be
submitted by June 30, 1988 or within 3 months after the last day of the
month for which the lessee requests a transportation allowance,
whichever is later (unless MMS approves a longer period). MMS shall then
determine the oil transportation allowance based upon the lessee's
proposal and any additional information MMS deems necessary.
(4) Where the lessee's payments for transportation under an arm's-
length contract are not on a dollar-per-unit basis, the lessee shall
convert whatever consideration is paid to a dollar value equivalent for
the purposes of this section.
(5) Where an arm's-length sales contract price, or a posted price,
includes a provision whereby the listed price is reduced by a
transportation factor, MMS will not consider the transportation factor
to be a transportation allowance. The transportation factor may be used
in determining the lessee's gross proceeds for the sale of the product.
The transportation factor may not
[[Page 60]]
exceed 50 percent of the base price of the product without MMS approval.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length transportation contract or has no contract, including those
situations where the lessee performs transportation services for itself,
the transportation allowance will be based upon the lessee's reasonable,
actual costs as provided in this paragraph. All transportation
allowances deducted under a non-arms-length or no-contract situation are
subject to monitoring, review, audit, and adjustment. Before any
estimated or actual deduction may be taken, the lessee must submit a
completed Form MMS-4110 in its entirety in accordance with paragraph
(c)(2) of this section. A transportation allowance may be claimed
retroactively for a period of not more than 3 months prior to the first
day of the month that Form MMS-4110 is filed with MMS, unless MMS
approves a longer period upon a showing of good cause by the lessee. MMS
will monitor the allowance deductions to determine whether lessees are
taking deductions that are reasonable and allowable. When necessary or
appropriate, MMS may direct a lessee to modify its actual transportation
allowance deduction.
(2) The transportation allowance for non-arms-length or no-contract
situations shall be based upon the lessee's actual costs for
transportation during the reporting period, including operating and
maintenance expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph
(b)(2)(iv)(A) of this section, or a cost equal to the initial capital
investment in the transportation system multiplied by a rate of return
in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable
capital costs are generally those for depreciable fixed assets
(including costs of delivery and installation of capital equipment)
which are an integral part of the transportation system.
(i) Allowable operating expenses include: Operations supervision and
engineering; operations labor; fuel; utilities; materials; ad valorem
property taxes; rent; supplies; and any other directly allocable and
attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the
transportation system; maintenance of equipment; maintenance labor; and
other directly allocable and attributable maintenance expenses which the
lessee can document.
(iii) Overhead directly attributable and allocable to the operation
and maintenance of the transportation system is an allowable expense.
State and Federal income taxes and severance taxes and other fees,
including royalties, are not allowable expenses.
(iv) A lessee may use either depreciation or a return on depreciable
capital investment. After a lessee has elected to use either method for
a transportation system, the lessee may not later elect to change to the
other alternative without approval of MMS.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the transportation system services or on
a unit-of-production method. After an election is made, the lessee may
not change methods without MMS approval. A change in ownership of a
transportation system shall not alter the depreciation schedule
established by the original transporter/lessee for purposes of the
allowance calculation. With or without a change in ownership, a
transportation system shall be depreciated only once. Equipment shall
not be depreciated below a reasonable salvage value.
(B) MMS shall allow as a cost an amount equal to the initial capital
investment in the transportation system multiplied by the rate of return
determined under paragraph (b)(2)(v) of this section. No allowance shall
be provided for depreciation. This alternative shall apply only to
transportation facilities first placed in service after March 1, 1988.
(v) The rate of return shall be the industrial rate associated with
Standard and Poor's BBB rating. The rate of return shall be the monthly
average rate as published in Standard and Poor's Bond Guide for the
first month of the reporting period for which the allowance is
applicable and shall be effective
[[Page 61]]
during the reporting period. The rate shall be redetermined at the
beginning of each subsequent transportation allowance reporting period
(which is determined under paragraph (c) of this section).
(3)(i) The deduction for transportation costs shall be determined on
the basis of the lessee's cost of transporting each product through each
individual transportation system. Where more than one liquid product is
transported, allocation of costs to each of the liquid products
transported shall be in the same proportion as the ratio of the volume
of each liquid product (excluding waste products which have no value) to
the volume of all liquid products (excluding waste products which have
no value) and such allocation shall be made in a consistent and
equitable manner. Except as provided in this paragraph, the lessee may
not take an allowance for transporting lease production which is not
royalty-bearing without MMS approval.
(ii) Notwithstanding the requirements of paragraph (i), the lessee
may propose to MMS a cost allocation method on the basis of the values
of the products transported. MMS shall approve the method unless it
determines that it is not consistent with the purposes of the
regulations in this part.
(4) Where both gaseous and liquid products are transported through
the same transportation system, the lessee shall propose a cost
allocation procedure to MMS. The lessee may use the oil transportation
allowance determined in accordance with its proposed allocation
procedure until MMS issues its determination on the acceptability of the
cost allocation. The lessee shall submit all available data to support
its proposal. The initial proposal must be submitted by June 30, 1988 or
within 3 months after the last day of the month for which the lessee
requests a transportation allowance, whichever is later (unless MMS
approves a longer period). MMS shall then determine the oil
transportation allowance on the basis of the lessee's proposal and any
additional information MMS deems necessary.
(5) A lessee may apply to MMS for an exception from the requirement
that it compute actual costs in accordance with paragraphs (b)(1)
through (b)(4) of this section. MMS will grant the exception only if the
lessee has a tariff for the transportation system approved by the
Federal Energy Regulatory Commission (FERC) for Indian leases. MMS shall
deny the exception request if it determines that the tariff is excessive
as compared to arm's-length transportation charges by pipelines, owned
by the lessee or others, providing similar transportation services in
that area. If there are no arm's-length transportation charges, MMS
shall deny the exception request if:
(i) No FERC cost analysis exists and the FERC has declined to
investigate under MMS timely objections upon filing; and
(ii) the tariff significantly exceeds the lessee's actual costs for
transportation as determined under this section.
(c) Reporting requirements--(1) Arm's-length contracts. (i) With the
exception of those transportation allowances specified in paragraphs
(c)(1)(v) and (c)(1)(vi) of this section, the lessee shall submit page
one of the initial Form MMS-4110 (and Schedule 1), Oil Transportation
Allowance Report, prior to, or at the same time as, the transportation
allowance determined, under an arm's-length contract, is reported on
Form MMS-2014, Report of Sales and Royalty Remittance. A Form MMS-4110
received by the end of the month that the Form MMS-2014 is due shall be
considered to be timely received.
(ii) The initial Form MMS-4110 shall be effective for a reporting
period beginning the month that the lessee is first authorized to deduct
a transportation allowance and shall continue until the end of the
calendar year, or until the applicable contract or rate terminates or is
modified or amended, whichever is earlier.
(iii) After the initial reporting period and for succeeding
reporting periods, lessees must submit page one of Form MMS-4110 (and
Schedule 1) within 3 months after the end of the calendar year, or after
the applicable contract or rate terminates or is modified or amended,
whichever is earlier, unless MMS approves a longer period (during
[[Page 62]]
which period the lessee shall continue to use the allowance from the
previous reporting period).
(iv) MMS may require that a lessee submit arm's-length
transportation contracts, production agreements, operating agreements,
and related documents. Documents shall be submitted within a reasonable
time, as determined by MMS.
(v) Transportation allowances which are based on arm's-length
contracts and which are in effect at the time these regulations become
effective will be allowed to continue until such allowances terminate.
For the purposes of this section, only those allowances that have been
approved by MMS in writing shall qualify as being in effect at the time
these regulations become effective.
(vi) MMS may establish, in appropriate circumstances, reporting
requirements which are different from the requirements of this section.
(2) Non-arm's-length or no contract. (i) With the exception of those
transportation allowances specified in paragraphs (c)(2)(v), (c)(2)(vii)
and (c)(2)(viii) of this section, the lessee shall submit an initial
Form MMS-4110 prior to, or at the same time as, the transportation
allowance determined under a non-arm's-length contract or no-contract
situation is reported on Form MMS-2014. A Form MMS-4110 received by the
end of the month that the Form MMS-2014 is due shall be considered to be
timely received. The initial report may be based upon estimated costs.
(ii) The initial Form MMS-4110 shall be effective for a reporting
period beginning the month that the lessee first is authorized to deduct
a transportation allowance and shall continue until the end of the
calendar year, or until transportation under the non-arm's-length
contract or the no-contract situation terminates, whichever is earlier.
(iii) For calendar-year reporting periods succeeding the initial
reporting period, the lessee shall submit a completed Form MMS-4110
containing the actual costs for the previous reporting period. If oil
transportation is continuing, the lessee shall include on Form MMS-4110
its estimated costs for the next calendar year. The estimated oil
transportation allowance shall be based on the actual costs for the
previous reporting period plus or minus any adjustments which are based
on the lessee's knowledge of decreases or increases that will affect the
allowance. MMS must receive the Form MMS-4110 within 3 months after the
end of the previous reporting period, unless MMS approves a longer
period (during which period the lessee shall continue to use the
allowance from the previous reporting period).
(iv) For new transportation facilities or arrangements, the lessee's
initial Form MMS-4110 shall include estimates of the allowable oil
transportation costs for the applicable period. Cost estimates shall be
based upon the most recently available operations data for the
transportation system or, if such data are not available, the lessee
shall use estimates based upon industry data for similar transportation
systems.
(v) Non-arm's-length contract or no-contract transportation
allowances which are in effect at the time these regulations become
effective will be allowed to continue until such allowances terminate.
For the purposes of this section, only those allowances that have been
approved by MMS in writing shall qualify as being in effect at the time
these regulations become effective.
(vi) Upon request by MMS, the lessee shall submit all data used to
prepare its Form MMS-4110. The data shall be provided within a
reasonable period of time, as determined by MMS.
(vii) MMS may establish, in appropriate circumstances, reporting
requirements which are different from the requirements of this section.
(viii) If the lessee is authorized to use its FERC-approved tariff
as its transportation cost in accordance with paragraph (b)(5) of this
section, it shall follow the reporting requirements of paragraph (c)(1)
of this section.
(3) MMS may establish reporting dates for individual lessees
different from those specified in this subpart in order to provide more
effective administration. Lessees will be notified of any change in
their reporting period.
[[Page 63]]
(4) Transportation allowances must be reported as a separate line
item on Form MMS-2014, unless MMS approves a different reporting
procedure.
(d) Interest assessments for incorrect or late reports and for
failure to report. (1) If a lessee deducts a transportation allowance on
its Form MMS-2014 without complying with the requirements of this
section, the lessee shall pay interest only on the amount of such
deduction until the requirements of this section are complied with. The
lessee also shall repay the amount of any allowance which is disallowed
by this section.
(2) If a lessee erroneously reports a transportation allowance which
results in an underpayment of royalties, interest shall be paid on the
amount of that underpayment.
(3) Interest required to be paid by this section shall be determined
in accordance with 30 CFR 218.54.
(e) Adjustments. (1) If the actual transportation allowance is less
than the amount the lessee has taken on Form MMS-2014 for each month
during the allowance form reporting period, the lessee shall be required
to pay additional royalties due plus interest computed under 30 CFR
218.54, retroactive to the first day of the first month the lessee is
authorized to deduct a transportation allowance. If the actual
transportation allowance is greater than the amount the lessee has taken
on Form MMS-2014 for each month during the allowance form reporting
period, the lessee shall be entitled to a credit without interest.
(2) For lessees transporting production from Indian leases, the
lessee must submit a corrected Form MMS-2014 to reflect actual costs,
together with any payment, in accordance with instructions provided by
MMS.
(f) Actual or theoretical losses. Notwithstanding any other
provisions of this subpart, for other than arm's-length contracts, no
cost shall be allowed for oil transportation which results from payments
(either volumetric or for value) for actual or theoretical losses. This
section does not apply when the transportation allowance is based upon a
FERC or State regulatory agency approved tariff.
(g) Other transportation cost determinations. The provisions of this
section shall apply to determine transportation costs when establishing
value using a netback valuation procedure or any other procedure that
requires deduction of transportation costs.
Subpart C_Federal Oil
Source: 65 FR 14088, Mar. 15, 2000, unless otherwise noted.
Sec. 206.100 What is the purpose of this subpart?
(a) This subpart applies to all oil produced from Federal oil and
gas leases onshore and on the Outer Continental Shelf (OCS). It explains
how you as a lessee must calculate the value of production for royalty
purposes consistent with the mineral leasing laws, other applicable
laws, and lease terms.
(b) If you are a designee and if you dispose of production on behalf
of a lessee, the terms ``you'' and ``your'' in this subpart refer to you
and not to the lessee. In this circumstance, you must determine and
report royalty value for the lessee's oil by applying the rules in this
subpart to your disposition of the lessee's oil.
(c) If you are a designee and only report for a lessee, and do not
dispose of the lessee's production, references to ``you'' and ``your''
in this subpart refer to the lessee and not the designee. In this
circumstance, you as a designee must determine and report royalty value
for the lessee's oil by applying the rules in this subpart to the
lessee's disposition of its oil.
(d) If the regulations in this subpart are inconsistent with:
(1) A Federal statute;
(2) A settlement agreement between the United States and a lessee
resulting from administrative or judicial litigation;
(3) A written agreement between the lessee and the MMS Director
establishing a method to determine the value of production from any
lease that MMS expects at least would approximate the value established
under this subpart; or
(4) An express provision of an oil and gas lease subject to this
subpart, then the statute, settlement agreement,
[[Page 64]]
written agreement, or lease provision will govern to the extent of the
inconsistency.
(e) MMS may audit and adjust all royalty payments.
Sec. 206.101 What definitions apply to this subpart?
The following definitions apply to this subpart:
Affiliate means a person who controls, is controlled by, or is under
common control with another person. For purposes of this subpart:
(1) Ownership or common ownership of more than 50 percent of the
voting securities, or instruments of ownership, or other forms of
ownership, of another person constitutes control. Ownership of less than
10 percent constitutes a presumption of noncontrol that MMS may rebut.
(2) If there is ownership or common ownership of 10 through 50
percent of the voting securities or instruments of ownership, or other
forms of ownership, of another person, MMS will consider the following
factors in determining whether there is control under the circumstances
of a particular case:
(i) The extent to which there are common officers or directors;
(ii) With respect to the voting securities, or instruments of
ownership, or other forms of ownership: the percentage of ownership or
common ownership, the relative percentage of ownership or common
ownership compared to the percentage(s) of ownership by other persons,
whether a person is the greatest single owner, or whether there is an
opposing voting bloc of greater ownership;
(iii) Operation of a lease, plant, or other facility;
(iv) The extent of participation by other owners in operations and
day-to-day management of a lease, plant, or other facility; and
(v) Other evidence of power to exercise control over or common
control with another person.
(3) Regardless of any percentage of ownership or common ownership,
relatives, either by blood or marriage, are affiliates.
ANS means Alaska North Slope (ANS).
Area means a geographic region at least as large as the limits of an
oil field, in which oil has similar quality, economic, and legal
characteristics.
Arm's-length contract means a contract or agreement between
independent persons who are not affiliates and who have opposing
economic interests regarding that contract. To be considered arm's
length for any production month, a contract must satisfy this definition
for that month, as well as when the contract was executed.
Audit means a review, conducted under generally accepted accounting
and auditing standards, of royalty payment compliance activities of
lessees, designees or other persons who pay royalties, rents, or bonuses
on Federal leases.
BLM means the Bureau of Land Management of the Department of the
Interior.
Condensate means liquid hydrocarbons (normally exceeding 40 degrees
of API gravity) recovered at the surface without processing. Condensate
is the mixture of liquid hydrocarbons resulting from condensation of
petroleum hydrocarbons existing initially in a gaseous phase in an
underground reservoir.
Contract means any oral or written agreement, including amendments
or revisions, between two or more persons, that is enforceable by law
and that with due consideration creates an obligation.
Designee means the person the lessee designates to report and pay
the lessee's royalties for a lease.
Exchange agreement means an agreement where one person agrees to
deliver oil to another person at a specified location in exchange for
oil deliveries at another location. Exchange agreements may or may not
specify prices for the oil involved. They frequently specify dollar
amounts reflecting location, quality, or other differentials. Exchange
agreements include buy/sell agreements, which specify prices to be paid
at each exchange point and may appear to be two separate sales within
the same agreement. Examples of other types of exchange agreements
include, but are not limited to, exchanges of produced oil for specific
types of crude oil (e.g., West
[[Page 65]]
Texas Intermediate); exchanges of produced oil for other crude oil at
other locations (Location Trades); exchanges of produced oil for other
grades of oil (Grade Trades); and multi-party exchanges.
Field means a geographic region situated over one or more subsurface
oil and gas reservoirs and encompassing at least the outermost
boundaries of all oil and gas accumulations known within those
reservoirs, vertically projected to the land surface. State oil and gas
regulatory agencies usually name onshore fields and designate their
official boundaries. MMS names and designates boundaries of OCS fields.
Gathering means the movement of lease production to a central
accumulation or treatment point on the lease, unit, or communitized
area, or to a central accumulation or treatment point off the lease,
unit, or communitized area that BLM or MMS approves for onshore and
offshore leases, respectively.
Gross proceeds means the total monies and other consideration
accruing for the disposition of oil produced. Gross proceeds also
include, but are not limited to, the following examples:
(1) Payments for services such as dehydration, marketing,
measurement, or gathering which the lessee must perform at no cost to
the Federal Government;
(2) The value of services, such as salt water disposal, that the
producer normally performs but that the buyer performs on the producer's
behalf;
(3) Reimbursements for harboring or terminaling fees;
(4) Tax reimbursements, even though the Federal royalty interest may
be exempt from taxation;
(5) Payments made to reduce or buy down the purchase price of oil to
be produced in later periods, by allocating such payments over the
production whose price the payment reduces and including the allocated
amounts as proceeds for the production as it occurs; and
(6) Monies and all other consideration to which a seller is
contractually or legally entitled, but does not seek to collect through
reasonable efforts.
Lease means any contract, profit-share arrangement, joint venture,
or other agreement issued or approved by the United States under a
mineral leasing law that authorizes exploration for, development or
extraction of, or removal of oil or gas--or the land area covered by
that authorization, whichever the context requires.
Lessee means any person to whom the United States issues an oil and
gas lease, an assignee of all or a part of the record title interest, or
any person to whom operating rights in a lease have been assigned.
Location differential means an amount paid or received (whether in
money or in barrels of oil) under an exchange agreement that results
from differences in location between oil delivered in exchange and oil
received in the exchange. A location differential may represent all or
part of the difference between the price received for oil delivered and
the price paid for oil received under a buy/sell exchange agreement.
Market center means a major point MMS recognizes for oil sales,
refining, or transshipment. Market centers generally are locations where
MMS-approved publications publish oil spot prices.
Marketable condition means oil sufficiently free from impurities and
otherwise in a condition a purchaser will accept under a sales contract
typical for the field or area.
MMS-approved publication means a publication MMS approves for
determining ANS spot prices or WTI differentials.
Netting means reducing the reported sales value to account for
transportation instead of reporting a transportation allowance as a
separate entry on Form MMS-2014.
NYMEX price means the average of the New York Mercantile Exchange
(NYMEX) settlement prices for light sweet crude oil delivered at
Cushing, Oklahoma, calculated as follows:
(1) Sum the prices published for each day during the calendar month
of production (excluding weekends and holidays) for oil to be delivered
in the prompt month corresponding to each such day; and
(2) Divide the sum by the number of days on which those prices are
published (excluding weekends and holidays).
[[Page 66]]
Oil means a mixture of hydrocarbons that existed in the liquid phase
in natural underground reservoirs, remains liquid at atmospheric
pressure after passing through surface separating facilities, and is
marketed or used as a liquid. Condensate recovered in lease separators
or field facilities is oil.
Outer Continental Shelf (OCS) means all submerged lands lying
seaward and outside of the area of lands beneath navigable waters as
defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of
which the subsoil and seabed appertain to the United States and are
subject to its jurisdiction and control.
Person means any individual, firm, corporation, association,
partnership, consortium, or joint venture (when established as a
separate entity).
Prompt month means the nearest month of delivery for which NYMEX
futures prices are published during the trading month.
Quality differential means an amount paid or received under an
exchange agreement (whether in money or in barrels of oil) that results
from differences in API gravity, sulfur content, viscosity, metals
content, and other quality factors between oil delivered and oil
received in the exchange. A quality differential may represent all or
part of the difference between the price received for oil delivered and
the price paid for oil received under a buy/sell agreement.
Rocky Mountain Region means the States of Colorado, Montana, North
Dakota, South Dakota, Utah, and Wyoming, except for those portions of
the San Juan Basin and other oil-producing fields in the ``Four
Corners'' area that lie within Colorado and Utah.
Roll means an adjustment to the NYMEX price that is calculated as
follows:
Roll = .6667 x (P0-P1) + .3333 x
(P0-P2), where: P0 = the average of the
daily NYMEX settlement prices for deliveries during the prompt month
that is the same as the month of production, as published for each day
during the trading month for which the month of production is the prompt
month; P1 = the average of the daily NYMEX settlement prices
for deliveries during the month following the month of production,
published for each day during the trading month for which the month of
production is the prompt month; and P2 = the average of the
daily NYMEX settlement prices for deliveries during the second month
following the month of production, as published for each day during the
trading month for which the month of production is the prompt month.
Calculate the average of the daily NYMEX settlement prices using only
the days on which such prices are published (excluding weekends and
holidays).
(1) Example 1. Prices in Out Months are Lower Going Forward: The
month of production for which you must determine royalty value is March.
March was the prompt month (for year 2003) from January 22 through
February 20. April was the first month following the month of
production, and May was the second month following the month of
production. P0 therefore is the average of the daily NYMEX
settlement prices for deliveries during March published for each
business day between January 22 and February 20. P1 is the
average of the daily NYMEX settlement prices for deliveries during April
published for each business day between January 22 and February 20.
P2 is the average of the daily NYMEX settlement prices for
deliveries during May published for each business day between January 22
and February 20. In this example, assume that P0 = $28.00 per
bbl, P1 = $27.70 per bbl, and P2 = $27.10 per bbl.
In this example (a declining market), Roll = .6667 x ($28.00-$27.70) +
.3333 x ($28.00-$27.10) = $.20 + $.30 = $.50. You add this number to the
NYMEX price.
(2) Example 2. Prices in Out Months are Higher Going Forward: The
month of production for which you must determine royalty value is July.
July 2003 was the prompt month from May 21 through June 20. August was
the first month following the month of production, and September was the
second month following the month of production. P0 therefore
is the average of the daily NYMEX settlement prices for deliveries
during July published for each business day between May 21 and June 20.
P1 is the average of the daily NYMEX settlement prices for
deliveries during August published for each business day between May 21
and June
[[Page 67]]
20. P2 is the average of the daily NYMEX settlement prices
for deliveries during September published for each business day between
May 21 and June 20. In this example, assume that P0 = $28.00
per bbl, P1 = $28.90 per bbl, and P2 = $29.50 per
bbl. In this example (a rising market), Roll = .6667 x ($28.00-$28.90) +
.3333 x ($28.00-$29.50) = (-$.60) + (-$.50) = -$1.10. You add this
negative number to the NYMEX price (effectively a subtraction from the
NYMEX price).
Sale means a contract between two persons where:
(1) The seller unconditionally transfers title to the oil to the
buyer and does not retain any related rights such as the right to buy
back similar quantities of oil from the buyer elsewhere;
(2) The buyer pays money or other consideration for the oil; and
(3) The parties' intent is for a sale of the oil to occur.
Spot price means the price under a spot sales contract where:
(1) A seller agrees to sell to a buyer a specified amount of oil at
a specified price over a specified period of short duration;
(2) No cancellation notice is required to terminate the sales
agreement; and
(3) There is no obligation or implied intent to continue to sell in
subsequent periods.
Tendering program means a producer's offer of a portion of its crude
oil produced from a field or area for competitive bidding, regardless of
whether the production is offered or sold at or near the lease or unit
or away from the lease or unit.
Trading month means the period extending from the second business
day before the 25th day of the second calendar month preceding the
delivery month (or, if the 25th day of that month is a non-business day,
the second business day before the last business day preceding the 25th
day of that month) through the third business day before the 25th day of
the calendar month preceding the delivery month (or, if the 25th day of
that month is a non-business day, the third business day before the last
business day preceding the 25th day of that month), unless the NYMEX
publishes a different definition or different dates on its official Web
site, www.nymex.com, in which case the NYMEX definition will apply.
Transportation allowance means a deduction in determining royalty
value for the reasonable, actual costs of moving oil to a point of sale
or delivery off the lease, unit area, or communitized area. The
transportation allowance does not include gathering costs.
WTI differential means the average of the daily mean differentials
for location and quality between a grade of crude oil at a market center
and West Texas Intermediate (WTI) crude oil at Cushing published for
each day for which price publications perform surveys for deliveries
during the production month, calculated over the number of days on which
those differentials are published (excluding weekends and holidays).
Calculate the daily mean differentials by averaging the daily high and
low differentials for the month in the selected publication. Use only
the days and corresponding differentials for which such differentials
are published.
(1) Example. Assume the production month was March 2003. Industry
trade publications performed their price surveys and determined
differentials during January 26 through February 25 for oil delivered in
March. The WTI differential (for example, the West Texas Sour crude at
Midland, Texas, spread versus WTI) applicable to valuing oil produced in
the March 2003 production month would be determined using all the
business days for which differentials were published during the period
January 26 through February 25 excluding weekends and holidays (22
days). To calculate the WTI differential, add together all of the daily
mean differentials published for January 26 through February 25 and
divide that sum by 22.
(2) [Reserved]
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24975, May 5, 2004]
Sec. 206.102 How do I calculate royalty value for oil that I or my affiliate
sell(s) under an arm's-length contract?
(a) The value of oil under this section is the gross proceeds
accruing to the seller under the arm's-length contract, less applicable
allowances determined under Sec. Sec. 206.110 or 206.111. This value
[[Page 68]]
does not apply if you exercise an option to use a different value
provided in paragraph (d)(1) or (d)(2)(i) of this section, or if one of
the exceptions in paragraph (c) of this section applies. Use this
paragraph (a) to value oil that:
(1) You sell under an arm's-length sales contract; or
(2) You sell or transfer to your affiliate or another person under a
non-arm's-length contract and that affiliate or person, or another
affiliate of either of them, then sells the oil under an arm's-length
contract, unless you exercise the option provided in paragraph (d)(2)(i)
of this section.
(b) If you have multiple arm's-length contracts to sell oil produced
from a lease that is valued under paragraph (a) of this section, the
value of the oil is the volume-weighted average of the values
established under this section for each contract for the sale of oil
produced from that lease.
(c) This paragraph contains exceptions to the valuation rule in
paragraph (a) of this section. Apply these exceptions on an individual
contract basis.
(1) In conducting reviews and audits, if MMS determines that any
arm's-length sales contract does not reflect the total consideration
actually transferred either directly or indirectly from the buyer to the
seller, MMS may require that you value the oil sold under that contract
either under Sec. 206.103 or at the total consideration received.
(2) You must value the oil under Sec. 206.103 if MMS determines
that the value under paragraph (a) of this section does not reflect the
reasonable value of the production due to either:
(i) Misconduct by or between the parties to the arm's-length
contract; or
(ii) Breach of your duty to market the oil for the mutual benefit of
yourself and the lessor.
(A) MMS will not use this provision to simply substitute its
judgment of the market value of the oil for the proceeds received by the
seller under an arm's-length sales contract.
(B) The fact that the price received by the seller under an arm's
length contract is less than other measures of market price, such as
index prices, is insufficient to establish breach of the duty to market
unless MMS finds additional evidence that the seller acted unreasonably
or in bad faith in the sale of oil from the lease.
(d)(1) If you enter into an arm's-length exchange agreement, or
multiple sequential arm's-length exchange agreements, and following the
exchange(s) you or your affiliate sell(s) the oil received in the
exchange(s) under an arm's-length contract, then you may use either
Sec. 206.102(a) or Sec. 206.103 to value your production for royalty
purposes.
(i) If you use Sec. 206.102(a), your gross proceeds are the gross
proceeds under your or your affiliate's arm's-length sales contract
after the exchange(s) occur(s). You must adjust your gross proceeds for
any location or quality differential, or other adjustments, you received
or paid under the arm's-length exchange agreement(s). If MMS determines
that any arm's-length exchange agreement does not reflect reasonable
location or quality differentials, MMS may require you to value the oil
under Sec. 206.103. You may not otherwise use the price or differential
specified in an arm's-length exchange agreement to value your
production.
(ii) When you elect under Sec. 206.102(d)(1) to use Sec.
206.102(a) or Sec. 206.103, you must make the same election for all of
your production from the same unit, communitization agreement, or lease
(if the lease is not part of a unit or communitization agreement) sold
under arm's-length contracts following arm's-length exchange agreements.
You may not change your election more often than once every 2 years.
(2)(i) If you sell or transfer your oil production to your affiliate
and that affiliate or another affiliate then sells the oil under an
arm's-length contract, you may use either Sec. 206.102(a) or Sec.
206.103 to value your production for royalty purposes.
(ii) When you elect under Sec. 206.102(d)(2)(i) to use Sec.
206.102(a) or Sec. 206.103, you must make the same election for all of
your production from the same unit, communitization agreement, or lease
(if the lease is not part of a unit or communitization agreement) that
your affiliates resell at
[[Page 69]]
arm's length. You may not change your election more often than once
every 2 years.
(e) If you value oil under paragraph (a) of this section:
(1) MMS may require you to certify that your or your affiliate's
arm's-length contract provisions include all of the consideration the
buyer must pay, either directly or indirectly, for the oil.
(2) You must base value on the highest price the seller can receive
through legally enforceable claims under the contract.
(i) If the seller fails to take proper or timely action to receive
prices or benefits it is entitled to, you must pay royalty at a value
based upon that obtainable price or benefit. But you will owe no
additional royalties unless or until the seller receives monies or
consideration resulting from the price increase or additional benefits,
if:
(A) The seller makes timely application for a price increase or
benefit allowed under the contract;
(B) The purchaser refuses to comply; and
(C) The seller takes reasonable documented measures to force
purchaser compliance.
(ii) Paragraph (e)(2)(i) of this section will not permit you to
avoid your royalty payment obligation where a purchaser fails to pay,
pays only in part, or pays late. Any contract revisions or amendments
that reduce prices or benefits to which the seller is entitled must be
in writing and signed by all parties to the arm's-length contract.
Sec. 206.103 How do I value oil that is not sold under an arm's-length
contract?
This section explains how to value oil that you may not value under
Sec. 206.102 or that you elect under Sec. 206.102(d) to value under
this section. First determine whether paragraph (a), (b), or (c) of this
section applies to production from your lease, or whether you may apply
paragraph (d) or (e) with MMS approval.
(a) Production from leases in California or Alaska. Value is the
average of the daily mean ANS spot prices published in any MMS-approved
publication during the trading month most concurrent with the production
month. (For example, if the production month is June, compute the
average of the daily mean prices using the daily ANS spot prices
published in the MMS-approved publication for all the business days in
June.)
(1) To calculate the daily mean spot price, average the daily high
and low prices for the month in the selected publication.
(2) Use only the days and corresponding spot prices for which such
prices are published.
(3) You must adjust the value for applicable location and quality
differentials, and you may adjust it for transportation costs, under
Sec. 206.112.
(4) After you select an MMS-approved publication, you may not select
a different publication more often than once every 2 years, unless the
publication you use is no longer published or MMS revokes its approval
of the publication. If you are required to change publications, you must
begin a new 2-year period.
(b) Production from leases in the Rocky Mountain Region. This
paragraph provides methods and options for valuing your production under
different factual situations. You must consistently apply paragraph
(b)(1), (b)(2), or (b)(3) of this section to value all of your
production from the same unit, communitization agreement, or lease (if
the lease or a portion of the lease is not part of a unit or
communitization agreement) that you cannot value under Sec. 206.102 or
that you elect under Sec. 206.102(d) to value under this section.
(1) If you have an MMS-approved tendering program, you must value
oil produced from leases in the area the tendering program covers at the
highest winning bid price for tendered volumes.
(i) The minimum requirements for MMS to approve your tendering
program are:
(A) You must offer and sell at least 30 percent of your or your
affiliates' production from both Federal and non-Federal leases in the
area under your tendering program; and
[[Page 70]]
(B) You must receive at least three bids for the tendered volumes
from bidders who do not have their own tendering programs that cover
some or all of the same area.
(ii) If you do not have an MMS-approved tendering program, you may
elect to value your oil under either paragraph (b)(2) or (b)(3) of this
section. After you select either paragraph (b)(2) or (b)(3) of this
section, you may not change to the other method more often than once
every 2 years, unless the method you have been using is no longer
applicable and you must apply the other paragraph. If you change
methods, you must begin a new 2-year period.
(2) Value is the volume-weighted average of the gross proceeds
accruing to the seller under your or your affiliates' arm's-length
contracts for the purchase or sale of production from the field or area
during the production month.
(i) The total volume purchased or sold under those contracts must
exceed 50 percent of your and your affiliates' production from both
Federal and non-Federal leases in the same field or area during that
month.
(ii) Before calculating the volume-weighted average, you must
normalize the quality of the oil in your or your affiliates' arm's-
length purchases or sales to the same gravity as that of the oil
produced from the lease.
(3) Value is the NYMEX price (without the roll), adjusted for
applicable location and quality differentials and transportation costs
under Sec. 206.112.
(4) If you demonstrate to MMS's satisfaction that paragraphs (b)(1)
through (b)(3) of this section result in an unreasonable value for your
production as a result of circumstances regarding that production, the
MMS Director may establish an alternative valuation method.
(c) Production from leases not located in California, Alaska, or the
Rocky Mountain Region. (1) Value is the NYMEX price, plus the roll,
adjusted for applicable location and quality differentials and
transportation costs under Sec. 206.112.
(2) If the MMS Director determines that use of the roll no longer
reflects prevailing industry practice in crude oil sales contracts or
that the most common formula used by industry to calculate the roll
changes, MMS may terminate or modify use of the roll under paragraph
(c)(1) of this section at the end of each 2-year period following July
6, 2004, through notice published in the Federal Register not later than
60 days before the end of the 2-year period. MMS will explain the
rationale for terminating or modifying the use of the roll in this
notice.
(d) Unreasonable value. If MMS determines that the NYMEX price or
ANS spot price does not represent a reasonable royalty value in any
particular case, MMS may establish reasonable royalty value based on
other relevant matters.
(e) Production delivered to your refinery and the NYMEX price or ANS
spot price is an unreasonable value. (1) Instead of valuing your
production under paragraph (a), (b), or (c) of this section, you may
apply to the MMS Director to establish a value representing the market
at the refinery if:
(i) You transport your oil directly to your or your affiliate's
refinery, or exchange your oil for oil delivered to your or your
affiliate's refinery; and
(ii) You must value your oil under this section at the NYMEX price
or ANS spot price; and
(iii) You believe that use of the NYMEX price or ANS spot price
results in an unreasonable royalty value.
(2) You must provide adequate documentation and evidence
demonstrating the market value at the refinery. That evidence may
include, but is not limited to:
(i) Costs of acquiring other crude oil at or for the refinery;
(ii) How adjustments for quality, location, and transportation were
factored into the price paid for other oil;
(iii) Volumes acquired for and refined at the refinery; and
(iv) Any other appropriate evidence or documentation that MMS
requires.
(3) If the MMS Director establishes a value representing market
value at the refinery, you may not take an allowance against that value
under
[[Page 71]]
Sec. 206.112(b) unless it is included in the Director's approval.
[65 FR 14088, Mar. 15, 2002, as amended at 67 FR 19111, Apr. 18, 2002;
69 FR 24976, May 5, 2004]
Sec. 206.104 What publications are acceptable to MMS?
(a) MMS periodically will publish in the Federal Register a list of
acceptable publications for the NYMEX price and ANS spot price based on
certain criteria, including, but not limited to:
(1) Publications buyers and sellers frequently use;
(2) Publications frequently mentioned in purchase or sales
contracts;
(3) Publications that use adequate survey techniques, including
development of estimates based on daily surveys of buyers and sellers of
crude oil, and, for ANS spot prices, buyers and sellers of ANS crude
oil; and
(4) Publications independent from MMS, other lessors, and lessees.
(b) Any publication may petition MMS to be added to the list of
acceptable publications.
(c) MMS will specify the tables you must use in the acceptable
publications.
(d) MMS may revoke its approval of a particular publication if it
determines that the prices or differentials published in the publication
do not accurately represent NYMEX prices or differentials or ANS spot
market prices or differentials.
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24976, May 5, 2004]
Sec. 206.105 What records must I keep to support my calculations of value
under this subpart?
If you determine the value of your oil under this subpart, you must
retain all data relevant to the determination of royalty value.
(a) You must be able to show:
(1) How you calculated the value you reported, including all
adjustments for location, quality, and transportation, and
(2) How you complied with these rules.
(b) Recordkeeping requirements are found at part 207 of this
chapter.
(c) MMS may review and audit your data, and MMS will direct you to
use a different value if it determines that the reported value is
inconsistent with the requirements of this subpart.
Sec. 206.106 What are my responsibilities to place production into
marketable condition and to market production?
You must place oil in marketable condition and market the oil for
the mutual benefit of the lessee and the lessor at no cost to the
Federal Government. If you use gross proceeds under an arm's-length
contract in determining value, you must increase those gross proceeds to
the extent that the purchaser, or any other person, provides certain
services that the seller normally would be responsible to perform to
place the oil in marketable condition or to market the oil.
Sec. 206.107 How do I request a value determination?
(a) You may request a value determination from MMS regarding any
Federal lease oil production. Your request must:
(1) Be in writing;
(2) Identify specifically all leases involved, the record title or
operating rights owners of those leases, and the designees for those
leases;
(3) Completely explain all relevant facts. You must inform MMS of
any changes to relevant facts that occur before we respond to your
request;
(4) Include copies of all relevant documents;
(5) Provide your analysis of the issue(s), including citations to
all relevant precedents (including adverse precedents); and
(6) Suggest your proposed valuation method.
(b) MMS will reply to requests expeditiously. MMS may either:
(1) Issue a value determination signed by the Assistant Secretary,
Land and Minerals Management; or
(2) Issue a value determination by MMS; or
(3) Inform you in writing that MMS will not provide a value
determination. Situations in which MMS typically will not provide any
value determination include, but are not limited to:
(i) Requests for guidance on hypothetical situations; and
[[Page 72]]
(ii) Matters that are the subject of pending litigation or
administrative appeals.
(c)(1) A value determination signed by the Assistant Secretary, Land
and Minerals Management, is binding on both you and MMS until the
Assistant Secretary modifies or rescinds it.
(2) After the Assistant Secretary issues a value determination, you
must make any adjustments in royalty payments that follow from the
determination and, if you owe additional royalties, pay late payment
interest under 30 CFR 218.54.
(3) A value determination signed by the Assistant Secretary is the
final action of the Department and is subject to judicial review under 5
U.S.C. 701-706.
(d) A value determination issued by MMS is binding on MMS and
delegated States with respect to the specific situation addressed in the
determination unless the MMS (for MMS-issued value determinations) or
the Assistant Secretary modifies or rescinds it.
(1) A value determination by MMS is not an appealable decision or
order under 30 CFR part 290 subpart B.
(2) If you receive an order requiring you to pay royalty on the same
basis as the value determination, you may appeal that order under 30 CFR
part 290 subpart B.
(e) In making a value determination, MMS or the Assistant Secretary
may use any of the applicable valuation criteria in this subpart.
(f) A change in an applicable statute or regulation on which any
value determination is based takes precedence over the value
determination, regardless of whether the MMS or the Assistant Secretary
modifies or rescinds the value determination.
(g) The MMS or the Assistant Secretary generally will not
retroactively modify or rescind a value determination issued under
paragraph (d) of this section, unless:
(1) There was a misstatement or omission of material facts; or
(2) The facts subsequently developed are materially different from
the facts on which the guidance was based.
(h) MMS may make requests and replies under this section available
to the public, subject to the confidentiality requirements under Sec.
206.108.
Sec. 206.108 Does MMS protect information I provide?
Certain information you submit to MMS regarding valuation of oil,
including transportation allowances, may be exempt from disclosure. To
the extent applicable laws and regulations permit, MMS will keep
confidential any data you submit that is privileged, confidential, or
otherwise exempt from disclosure. All requests for information must be
submitted under the Freedom of Information Act regulations of the
Department of the Interior at 43 CFR part 2.
Sec. 206.109 When may I take a transportation allowance in determining
value?
(a) Transportation allowances permitted when value is based on gross
proceeds. MMS will allow a deduction for the reasonable, actual costs to
transport oil from the lease to the point off the lease under Sec. Sec.
206.110 or 206.111, as applicable. This paragraph applies when:
(1) You value oil under Sec. 206.102 based on gross proceeds from a
sale at a point off the lease, unit, or communitized area where the oil
is produced, and
(2) The movement to the sales point is not gathering.
(b) Transportation allowances and other adjustments that apply when
value is based on NYMEX prices or ANS spot prices. If you value oil
using NYMEX prices or ANS spot prices under Sec. 206.103, MMS will
allow an adjustment for certain location and quality differentials and
certain costs associated with transporting oil as provided under Sec.
206.112.
(c) Limits on transportation allowances. (1) Except as provided in
paragraph (c)(2) of this section, your transportation allowance may not
exceed 50 percent of the value of the oil as determined under Sec.
206.102 or Sec. 206.103 of this subpart. You may not use transportation
costs incurred to move a particular volume of production to reduce
royalties owed on production for which those costs were not incurred.
(2) You may ask MMS to approve a transportation allowance in excess
of the limitation in paragraph (c)(1) of
[[Page 73]]
this section. You must demonstrate that the transportation costs
incurred were reasonable, actual, and necessary. Your application for
exception (using Form MMS-4393, Request to Exceed Regulatory Allowance
Limitation) must contain all relevant and supporting documentation
necessary for MMS to make a determination. You may never reduce the
royalty value of any production to zero.
(d) Allocation of transportation costs. You must allocate
transportation costs among all products produced and transported as
provided in Sec. Sec. 206.110 and 206.111. You must express
transportation allowances for oil as dollars per barrel.
(e) Liability for additional payments. If MMS determines that you
took an excessive transportation allowance, then you must pay any
additional royalties due, plus interest under 30 CFR 218.54. You also
could be entitled to a credit with interest under applicable rules if
you understated your transportation allowance. If you take a deduction
for transportation on Form MMS-2014 by improperly netting the allowance
against the sales value of the oil instead of reporting the allowance as
a separate entry, MMS may assess you an amount under Sec. 206.116.
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24976, May 5, 2004]
Sec. 206.110 How do I determine a transportation allowance under an arm's-
length transportation contract?
(a) If you or your affiliate incur transportation costs under an
arm's-length transportation contract, you may claim a transportation
allowance for the reasonable, actual costs incurred as more fully
explained in paragraph (b) of this section, except as provided in
paragraphs (a)(1) and (a)(2) of this section and subject to the
limitation in Sec. 206.109(c). You must be able to demonstrate that
your or your affiliate's contract is at arm's length. You do not need
MMS approval before reporting a transportation allowance for costs
incurred under an arm's-length transportation contract.
(1) If MMS determines that the contract reflects more than the
consideration actually transferred either directly or indirectly from
you or your affiliate to the transporter for the transportation, MMS may
require that you calculate the transportation allowance under Sec.
206.111.
(2) You must calculate the transportation allowance under Sec.
206.111 if MMS determines that the consideration paid under an arm's-
length transportation contract does not reflect the reasonable value of
the transportation due to either:
(i) Misconduct by or between the parties to the arm's-length
contract; or
(ii) Breach of your duty to market the oil for the mutual benefit of
yourself and the lessor.
(A) MMS will not use this provision to simply substitute its
judgment of the reasonable oil transportation costs incurred by you or
your affiliate under an arm's-length transportation contract.
(B) The fact that the cost you or your affiliate incur in an arm's
length transaction is higher than other measures of transportation
costs, such as rates paid by others in the field or area, is
insufficient to establish breach of the duty to market unless MMS finds
additional evidence that you or your affiliate acted unreasonably or in
bad faith in transporting oil from the lease.
(b) You may deduct any of the following actual costs you (including
your affiliates) incur for transporting oil. You may not use as a
deduction any cost that duplicates all or part of any other cost that
you use under this paragraph.
(1) The amount that you pay under your arm's-length transportation
contract or tariff.
(2) Fees paid (either in volume or in value) for actual or
theoretical line losses.
(3) Fees paid for administration of a quality bank.
(4) The cost of carrying on your books as inventory a volume of oil
that the pipeline operator requires you to maintain, and that you do
maintain, in the line as line fill. You must calculate this cost as
follows:
(i) Multiply the volume that the pipeline requires you to maintain,
and that you do maintain, in the pipeline by the value of that volume
for the
[[Page 74]]
current month calculated under Sec. 206.102 or Sec. 206.103, as
applicable; and
(ii) Multiply the value calculated under paragraph (b)(4)(i) of this
section by the monthly rate of return, calculated by dividing the rate
of return specified in Sec. 206.111(i)(2) by 12.
(5) Fees paid to a terminal operator for loading and unloading of
crude oil into or from a vessel, vehicle, pipeline, or other conveyance.
(6) Fees paid for short-term storage (30 days or less) incidental to
transportation as required by a transporter.
(7) Fees paid to pump oil to another carrier's system or vehicles as
required under a tariff.
(8) Transfer fees paid to a hub operator associated with physical
movement of crude oil through the hub when you do not sell the oil at
the hub. These fees do not include title transfer fees.
(9) Payments for a volumetric deduction to cover shrinkage when
high-gravity petroleum (generally in excess of 51 degrees API) is mixed
with lower-gravity crude oil for transportation.
(10) Costs of securing a letter of credit, or other surety, that the
pipeline requires you as a shipper to maintain.
(c) You may not deduct any costs that are not actual costs of
transporting oil, including but not limited to the following:
(1) Fees paid for long-term storage (more than 30 days).
(2) Administrative, handling, and accounting fees associated with
terminalling.
(3) Title and terminal transfer fees.
(4) Fees paid to track and match receipts and deliveries at a market
center or to avoid paying title transfer fees.
(5) Fees paid to brokers.
(6) Fees paid to a scheduling service provider.
(7) Internal costs, including salaries and related costs, rent/space
costs, office equipment costs, legal fees, and other costs to schedule,
nominate, and account for sale or movement of production.
(8) Gauging fees.
(d) If your arm's-length transportation contract includes more than
one liquid product, and the transportation costs attributable to each
product cannot be determined from the contract, then you must allocate
the total transportation costs to each of the liquid products
transported.
(1) Your allocation must use the same proportion as the ratio of the
volume of each product (excluding waste products with no value) to the
volume of all liquid products (excluding waste products with no value).
(2) You may not claim an allowance for the costs of transporting
lease production that is not royalty-bearing.
(3) You may propose to MMS a cost allocation method on the basis of
the values of the products transported. MMS will approve the method
unless it is not consistent with the purposes of the regulations in this
subpart.
(e) If your arm's-length transportation contract includes both
gaseous and liquid products, and the transportation costs attributable
to each product cannot be determined from the contract, then you must
propose an allocation procedure to MMS.
(1) You may use your proposed procedure to calculate a
transportation allowance until MMS accepts or rejects your cost
allocation. If MMS rejects your cost allocation, you must amend your
Form MMS-2014 for the months that you used the rejected method and pay
any additional royalty and interest due.
(2) You must submit your initial proposal, including all available
data, within 3 months after first claiming the allocated deductions on
Form MMS-2014.
(f) If your payments for transportation under an arm's-length
contract are not on a dollar-per-unit basis, you must convert whatever
consideration is paid to a dollar-value equivalent.
(g) If your arm's-length sales contract includes a provision
reducing the contract price by a transportation factor, do not
separately report the transportation factor as a transportation
allowance on Form MMS-2014.
(1) You may use the transportation factor in determining your gross
proceeds for the sale of the product.
(2) You must obtain MMS approval before claiming a transportation
factor
[[Page 75]]
in excess of 50 percent of the base price of the product.
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24976, May 5, 2004]
Sec. 206.111 How do I determine a transportation allowance if I do not have
an arm's-length transportation contract or arm's-length tariff?
(a) This section applies if you or your affiliate do not have an
arm's-length transportation contract, including situations where you or
your affiliate provide your own transportation services. Calculate your
transportation allowance based on your or your affiliate's reasonable,
actual costs for transportation during the reporting period using the
procedures prescribed in this section.
(b) Your or your affiliate's actual costs include the following:
(1) Operating and maintenance expenses under paragraphs (d) and (e)
of this section;
(2) Overhead under paragraph (f) of this section;
(3) Depreciation under paragraphs (g) and (h) of this section;
(4) A return on undepreciated capital investment under paragraph (i)
of this section; and
(5) Once the transportation system has been depreciated below ten
percent of total capital investment, a return on ten percent of total
capital investment under paragraph (j) of this section.
(6) To the extent not included in costs identified in paragraphs (d)
through (j) of this section, you may also deduct the following actual
costs. You may not use any cost as a deduction that duplicates all or
part of any other cost that you use under this section:
(i) Volumetric adjustments for actual (not theoretical) line losses.
(ii) The cost of carrying on your books as inventory a volume of oil
that the pipeline operator requires you as a shipper to maintain, and
that you do maintain, in the line as line fill. You must calculate this
cost as follows:
(A) Multiply the volume that the pipeline requires you to maintain,
and that you do maintain, in the pipeline by the value of that volume
for the current month calculated under Sec. 206.102 or Sec. 206.103,
as applicable; and
(B) Multiply the value calculated under paragraph (b)(6)(ii)(A) of
this section by the monthly rate of return, calculated by dividing the
rate of return specified in Sec. 206.111(i)(2) by 12.
(iii) Fees paid to a non-affiliated terminal operator for loading
and unloading of crude oil into or from a vessel, vehicle, pipeline, or
other conveyance.
(iv) Transfer fees paid to a hub operator associated with physical
movement of crude oil through the hub when you do not sell the oil at
the hub. These fees do not include title transfer fees.
(v) A volumetric deduction to cover shrinkage when high-gravity
petroleum (generally in excess of 51 degrees API) is mixed with lower-
gravity crude oil for transportation.
(vi) Fees paid to a non-affiliated quality bank administrator for
administration of a quality bank.
(7) You may not deduct any costs that are not actual costs of
transporting oil, including but not limited to the following:
(i) Fees paid for long-term storage (more than 30 days).
(ii) Administrative, handling, and accounting fees associated with
terminalling.
(iii) Title and terminal transfer fees.
(iv) Fees paid to track and match receipts and deliveries at a
market center or to avoid paying title transfer fees.
(v) Fees paid to brokers.
(vi) Fees paid to a scheduling service provider.
(vii) Internal costs, including salaries and related costs, rent/
space costs, office equipment costs, legal fees, and other costs to
schedule, nominate, and account for sale or movement of production.
(viii) Theoretical line losses.
(ix) Gauging fees.
(c) Allowable capital costs are generally those for depreciable
fixed assets (including costs of delivery and installation of capital
equipment) which are an integral part of the transportation system.
(d) Allowable operating expenses include:
(i) Operations supervision and engineering;
(ii) Operations labor;
[[Page 76]]
(iii) Fuel;
(iv) Utilities;
(v) Materials;
(vi) Ad valorem property taxes;
(vii) Rent;
(viii) Supplies; and
(ix) Any other directly allocable and attributable operating expense
which you can document.
(e) Allowable maintenance expenses include:
(i) Maintenance of the transportation system;
(ii) Maintenance of equipment;
(iii) Maintenance labor; and
(iv) Other directly allocable and attributable maintenance expenses
which you can document.
(f) Overhead directly attributable and allocable to the operation
and maintenance of the transportation system is an allowable expense.
State and Federal income taxes and severance taxes and other fees,
including royalties, are not allowable expenses.
(g) To compute depreciation, you may elect to use either a straight-
line depreciation method based on the life of equipment or on the life
of the reserves which the transportation system services, or a unit-of-
production method. After you make an election, you may not change
methods without MMS approval. You may not depreciate equipment below a
reasonable salvage value.
(h) This paragraph describes the basis for your depreciation
schedule.
(1) If you or your affiliate own a transportation system on June 1,
2000, you must base your depreciation schedule used in calculating
actual transportation costs for production after June 1, 2000, on your
total capital investment in the system (including your original purchase
price or construction cost and subsequent reinvestment).
(2) If you or your affiliate purchased the transportation system at
arm's length before June 1, 2000, you must incorporate depreciation on
the schedule based on your purchase price (and subsequent reinvestment)
into your transportation allowance calculations for production after
June 1, 2000, beginning at the point on the depreciation schedule
corresponding to that date. You must prorate your depreciation for
calendar year 2000 by claiming part-year depreciation for the period
from June 1, 2000 until December 31, 2000. You may not adjust your
transportation costs for production before June 1, 2000, using the
depreciation schedule based on your purchase price.
(3) If you are the original owner of the transportation system on
June 1, 2000, or if you purchased your transportation system before
March 1, 1988, you must continue to use your existing depreciation
schedule in calculating actual transportation costs for production in
periods after June 1, 2000.
(4) If you or your affiliate purchase a transportation system at
arm's length from the original owner after June 1, 2000, you must base
your depreciation schedule used in calculating actual transportation
costs on your total capital investment in the system (including your
original purchase price and subsequent reinvestment). You must prorate
your depreciation for the year in which you or your affiliate purchased
the system to reflect the portion of that year for which you or your
affiliate own the system.
(5) If you or your affiliate purchase a transportation system at
arm's length after June 1, 2000, from anyone other than the original
owner, you must assume the depreciation schedule of the person from whom
you bought the system. Include in the depreciation schedule any
subsequent reinvestment.
(i)(1) To calculate a return on undepreciated capital investment,
multiply the remaining undepreciated capital balance as of the beginning
of the period for which you are calculating the transportation allowance
by the rate of return provided in paragraph (i)(2) of this section.
(2) The rate of return is 1.3 times the industrial bond yield index
for Standard & Poor's BBB bond rating. Use the monthly average rate
published in ``Standard & Poor's Bond Guide'' for the first month of the
reporting period for which the allowance applies. Calculate the rate at
the beginning of each subsequent transportation allowance reporting
period.
(j)(1) After a transportation system has been depreciated at or
below a value equal to ten percent of your total capital investment, you
may continue to include in the allowance calculation
[[Page 77]]
a cost equal to ten percent of your total capital investment in the
transportation system multiplied by a rate of return under paragraph
(i)(2) of this section.
(2) You may apply this paragraph to a transportation system that
before June 1, 2000, was depreciated at or below a value equal to ten
percent of your total capital investment.
(k) Calculate the deduction for transportation costs based on your
or your affiliate's cost of transporting each product through each
individual transportation system. Where more than one liquid product is
transported, allocate costs consistently and equitably to each of the
liquid products transported. Your allocation must use the same
proportion as the ratio of the volume of each liquid product (excluding
waste products with no value) to the volume of all liquid products
(excluding waste products with no value).
(1) You may not take an allowance for transporting lease production
that is not royalty-bearing.
(2) You may propose to MMS a cost allocation method on the basis of
the values of the products transported. MMS will approve the method if
it is consistent with the purposes of the regulations in this subpart.
(l)(1) Where you transport both gaseous and liquid products through
the same transportation system, you must propose a cost allocation
procedure to MMS.
(2) You may use your proposed procedure to calculate a
transportation allowance until MMS accepts or rejects your cost
allocation. If MMS rejects your cost allocation, you must amend your
Form MMS-2014 for the months that you used the rejected method and pay
any additional royalty and interest due.
(3) You must submit your initial proposal, including all available
data, within 3 months after first claiming the allocated deductions on
Form MMS-2014.
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24977, May 5, 2004]
Sec. 206.112 What adjustments and transportation allowances apply when I
value oil production from my lease using NYMEX prices or ANS spot prices?
This section applies when you use NYMEX prices or ANS spot prices to
calculate the value of production under Sec. 206.103. As specified in
this section, adjust the NYMEX price to reflect the difference in value
between your lease and Cushing, Oklahoma, or adjust the ANS spot price
to reflect the difference in value between your lease and the
appropriate MMS-recognized market center at which the ANS spot price is
published (for example, Long Beach, California, or San Francisco,
California). Paragraph (a) of this section explains how you adjust the
value between the lease and the market center, and paragraph (b) of this
section explains how you adjust the value between the market center and
Cushing when you use NYMEX prices. Paragraph (c) of this section
explains how adjustments may be made for quality differentials that are
not accounted for through exchange agreements. Paragraph (d) of this
section gives some examples. References in this section to ``you''
include your affiliates as applicable.
(a) To adjust the value between the lease and the market center:
(1)(i) For oil that you exchange at arm's length between your lease
and the market center (or between any intermediate points between those
locations), you must calculate a lease-to-market center differential by
the applicable location and quality differentials derived from your
arm's-length exchange agreement applicable to production during the
production month.
(ii) For oil that you exchange between your lease and the market
center (or between any intermediate points between those locations)
under an exchange agreement that is not at arm's length, you must obtain
approval from MMS for a location and quality differential. Until you
obtain such approval, you may use the location and quality differential
derived from that exchange agreement applicable to production during the
production month. If MMS prescribes a different differential, you must
apply MMS's differential to all periods for which you used
[[Page 78]]
your proposed differential. You must pay any additional royalties owed
resulting from using MMS's differential plus late payment interest from
the original royalty due date, or you may report a credit for any
overpaid royalties plus interest under 30 U.S.C. 1721(h).
(2) For oil that you transport between your lease and the market
center (or between any intermediate points between those locations), you
may take an allowance for the cost of transporting that oil between the
relevant points as determined under Sec. 206.110 or Sec. 206.111, as
applicable.
(3) If you transport or exchange at arm's length (or both transport
and exchange) at least 20 percent, but not all, of your oil produced
from the lease to a market center, determine the adjustment between the
lease and the market center for the oil that is not transported or
exchanged (or both transported and exchanged) to or through a market
center as follows:
(i) Determine the volume-weighted average of the lease-to-market
center adjustment calculated under paragraphs (a)(1) and (a)(2) of this
section for the oil that you do transport or exchange (or both transport
and exchange) from your lease to a market center.
(ii) Use that volume-weighted average lease-to-market center
adjustment as the adjustment for the oil that you do not transport or
exchange (or both transport and exchange) from your lease to a market
center.
(4) If you transport or exchange (or both transport and exchange)
less than 20 percent of the crude oil produced from your lease between
the lease and a market center, you must propose to MMS an adjustment
between the lease and the market center for the portion of the oil that
you do not transport or exchange (or both transport and exchange) to a
market center. Until you obtain such approval, you may use your proposed
adjustment. If MMS prescribes a different adjustment, you must apply
MMS's adjustment to all periods for which you used your proposed
adjustment. You must pay any additional royalties owed resulting from
using MMS's adjustment plus late payment interest from the original
royalty due date, or you may report a credit for any overpaid royalties
plus interest under 30 U.S.C. 1721(h).
(5) You may not both take a transportation allowance and use a
location and quality adjustment or exchange differential for the same
oil between the same points.
(b) For oil that you value using NYMEX prices, adjust the value
between the market center and Cushing, Oklahoma, as follows:
(1) If you have arm's-length exchange agreements between the market
center and Cushing under which you exchange to Cushing at least 20
percent of all the oil you own at the market center during the
production month, you must use the volume-weighted average of the
location and quality differentials from those agreements as the
adjustment between the market center and Cushing for all the oil that
you produce from the leases during that production month for which that
market center is used.
(2) If paragraph (b)(1) of this section does not apply, you must use
the WTI differential published in an MMS-approved publication for the
market center nearest your lease, for crude oil most similar in quality
to your production, as the adjustment between the market center and
Cushing. (For example, for light sweet crude oil produced offshore of
Louisiana, use the WTI differential for Light Louisiana Sweet crude oil
at St. James, Louisiana.) After you select an MMS-approved publication,
you may not select a different publication more often than once every 2
years, unless the publication you use is no longer published or MMS
revokes its approval of the publication. If you are required to change
publications, you must begin a new 2-year period.
(3) If neither paragraph (b)(1) nor (b)(2) of this section applies,
you may propose an alternative differential to MMS. Until you obtain
such approval, you may use your proposed differential. If MMS prescribes
a different differential, you must apply MMS's differential to all
periods for which you used your proposed differential. You must pay any
additional royalties owed resulting from using MMS's differential plus
late payment interest from the original royalty due date, or you
[[Page 79]]
may report a credit for any overpaid royalties plus interest under 30
U.S.C. 1721(h).
(c)(1) If you adjust for location and quality differentials or for
transportation costs under paragraphs (a) and (b) of this section, also
adjust the NYMEX price or ANS spot price for quality based on premiums
or penalties determined by pipeline quality bank specifications at
intermediate commingling points or at the market center if those points
are downstream of the royalty measurement point approved by MMS or BLM,
as applicable. Make this adjustment only if and to the extent that such
adjustments were not already included in the location and quality
differentials determined from your arm's-length exchange agreements.
(2) If the quality of your oil as adjusted is still different from
the quality of the representative crude oil at the market center after
making the quality adjustments described in paragraphs (a), (b) and
(c)(1) of this section, you may make further gravity adjustments using
posted price gravity tables. If quality bank adjustments do not
incorporate or provide for adjustments for sulfur content, you may make
sulfur adjustments, based on the quality of the representative crude oil
at the market center, of 5.0 cents per one-tenth percent difference in
sulfur content, unless MMS approves a higher adjustment.
(d) The examples in this paragraph illustrate how to apply the
requirement of this section.
(1) Example. Assume that a Federal lessee produces crude oil from a
lease near Artesia, New Mexico. Further, assume that the lessee
transports the oil to Roswell, New Mexico, and then exchanges the oil to
Midland, Texas. Assume the lessee refines the oil received in exchange
at Midland. Assume that the NYMEX price is $30.00/bbl, adjusted for the
roll; that the WTI differential (Cushing to Midland) is -$.10/bbl; that
the lessee's exchange agreement between Roswell and Midland results in a
location and quality differential of -$.08/bbl; and that the lessee's
actual cost of transporting the oil from Artesia to Roswell is $.40/bbl.
In this example, the royalty value of the oil is $30.00-$.10-$.08--$.40
= $29.42/bbl.
(2) Example. Assume the same facts as in the example in paragraph
(1), except that the lessee transports and exchanges to Midland 40
percent of the production from the lease near Artesia, and transports
the remaining 60 percent directly to its own refinery in Ohio. In this
example, the 40 percent of the production would be valued at $29.42/bbl,
as explained in the previous example. In this example, the other 60
percent also would be valued at $29.42/bbl.
(3) Example. Assume that a Federal lessee produces crude oil from a
lease near Bakersfield, California. Further, assume that the lessee
transports the oil to Hynes Station, and then exchanges the oil to
Cushing which it further exchanges with oil it refines. Assume that the
ANS spot price is $20.00/bbl, and that the lessee's actual cost of
transporting the oil from Bakersfield to Hynes Station is $.28/bbl. The
lessee must request approval from MMS for a location and quality
adjustment between Hynes Station and Long Beach. For example, the lessee
likely would propose using the tariff on Line 63 from Hynes Station to
Long Beach as the adjustment between those points. Assume that
adjustment to be $.72, including the sulfur and gravity bank
adjustments, and that MMS approves the lessee's request. In this
example, the preliminary (because the location and quality adjustment is
subject to MMS review) royalty value of the oil is $20.00-$.72-$.28 =
$19.00/bbl. The fact that oil was exchanged to Cushing does not change
use of ANS spot prices for royalty valuation.
[69 FR 24978, May 5, 2004]
Sec. 206.113 How will MMS identify market centers?
MMS periodically will publish in the Federal Register a list of
market centers. MMS will monitor market activity and, if necessary, add
to or modify the list of market centers and will publish such
modifications in the Federal Register. MMS will consider the following
factors and conditions in specifying market centers:
[[Page 80]]
(a) Points where MMS-approved publications publish prices useful for
index purposes;
(b) Markets served;
(c) Input from industry and others knowledgeable in crude oil
marketing and transportation;
(d) Simplification; and
(e) Other relevant matters.
Sec. 206.114 What are my reporting requirements under an arm's-length
transportation contract?
You or your affiliate must use a separate entry on Form MMS-2014 to
notify MMS of an allowance based on transportation costs you or your
affiliate incur. MMS may require you or your affiliate to submit arm's-
length transportation contracts, production agreements, operating
agreements, and related documents. Recordkeeping requirements are found
at part 207 of this chapter.
Sec. 206.115 What are my reporting requirements under a non-arm's-length
transportation arrangement?
(a) You or your affiliate must use a separate entry on Form MMS-2014
to notify MMS of an allowance based on transportation costs you or your
affiliate incur.
(b) For new transportation facilities or arrangements, base your
initial deduction on estimates of allowable oil transportation costs for
the applicable period. Use the most recently available operations data
for the transportation system or, if such data are not available, use
estimates based on data for similar transportation systems. Section
206.117 will apply when you amend your report based on your actual
costs.
(c) MMS may require you or your affiliate to submit all data used to
calculate the allowance deduction. Recordkeeping requirements are found
at part 207 of this chapter.
Sec. 206.116 What interest and assessments apply if I improperly report a
transportation allowance?
(a) If you or your affiliate net a transportation allowance rather
than report it as a separate entry against the royalty value on Form
MMS-2014, you will be assessed an amount up to 10 percent of the netted
allowance, not to exceed $250 per lease selling arrangement per sales
period.
(b) If you or your affiliate deduct a transportation allowance on
Form MMS-2014 that exceeds 50 percent of the value of the oil
transported without obtaining MMS's prior approval under Sec. 206.109,
you must pay interest on the excess allowance amount taken from the date
that amount is taken to the date you or your affiliate file an exception
request that MMS approves. If you do not file an exception request, or
if MMS does not approve your request, you must pay interest on the
excess allowance amount taken from the date that amount is taken until
the date you pay the additional royalties owed.
Sec. 206.117 What reporting adjustments must I make for transportation
allowances?
(a) If your or your affiliate's actual transportation allowance is
less than the amount you claimed on Form MMS-2014 for each month during
the allowance reporting period, you must pay additional royalties plus
interest computed under 30 CFR 218.54 from the date you took the
deduction to the date you repay the difference.
(b) If the actual transportation allowance is greater than the
amount you claimed on Form MMS-2014 for any month during the allowance
form reporting period, you are entitled to a credit plus interest under
applicable rules.
Sec. 206.119 How are royalty quantity and quality determined?
(a) Compute royalties based on the quantity and quality of oil as
measured at the point of settlement approved by BLM for onshore leases
or MMS for offshore leases.
(b) If the value of oil determined under this subpart is based upon
a quantity or quality different from the quantity or quality at the
point of royalty settlement approved by the BLM for onshore leases or
MMS for offshore leases, adjust the value for those differences in
quantity or quality.
(c) Any actual loss that you may incur before the royalty settlement
metering or measurement point is not subject to royalty if BLM or MMS,
as
[[Page 81]]
appropriate, determines that the loss is unavoidable.
(d) Except as provided in paragraph (b) of this section, royalties
are due on 100 percent of the volume measured at the approved point of
royalty settlement. You may not claim a reduction in that measured
volume for actual losses beyond the approved point of royalty settlement
or for theoretical losses that are claimed to have taken place either
before or after the approved point of royalty settlement.
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24979, May 5, 2004]
Sec. 206.120 How are operating allowances determined?
MMS may use an operating allowance for the purpose of computing
payment obligations when specified in the notice of sale and the lease.
MMS will specify the allowance amount or formula in the notice of sale
and in the lease agreement.
Subpart D_Federal Gas
Source: 53 FR 1272, Jan. 15, 1988, unless otherwise noted.
Sec. 206.150 Purpose and scope.
(a) This subpart is applicable to all gas production from Federal
oil and gas leases. The purpose of this subpart is to establish the
value of production for royalty purposes consistent with the mineral
leasing laws, other applicable laws and lease terms.
(b) If the regulations in this subpart are inconsistent with:
(1) A Federal statute;
(2) A settlement agreement between the United States and a lessee
resulting from administrative or judicial litigation;
(3) A written agreement between the lessee and the MMS Director
establishing a method to determine the value of production from any
lease that MMS expects at least would approximate the value established
under this subpart; or
(4) An express provision of an oil and gas lease subject to this
subpart; then the statute, settlement agreement, written agreement, or
lease provision will govern to the extent of the inconsistency.
(c) All royalty payments made to MMS are subject to audit and
adjustment.
(d) The regulations in this subpart are intended to ensure that the
administration of oil and gas leases is discharged in accordance with
the requirements of the governing mineral leasing laws and lease terms.
[61 FR 5464, Feb. 12, 1996, as amended at 70 FR 11877, Mar. 10, 2005]
Sec. 206.151 Definitions.
For purposes of this subpart:
Affiliate means a person who controls, is controlled by, or is under
common control with another person. For purposes of this subpart:
(1) Ownership or common ownership of more than 50 percent of the
voting securities, or instruments of ownership, or other forms of
ownership, of another person constitutes control. Ownership of less than
10 percent constitutes a presumption of noncontrol that MMS may rebut.
(2) If there is ownership or common ownership of 10 through 50
percent of the voting securities or instruments of ownership, or other
forms of ownership, of another person, MMS will consider the following
factors in determining whether there is control under the circumstances
of a particular case:
(i) The extent to which there are common officers or directors;
(ii) With respect to the voting securities, or instruments of
ownership, or other forms of ownership: The percentage of ownership or
common ownership, the relative percentage of ownership or common
ownership compared to the percentage(s) of ownership by other persons,
whether a person is the greatest single owner, or whether there is an
opposing voting bloc of greater ownership;
(iii) Operation of a lease, plant, pipeline, or other facility;
(iv) The extent of participation by other owners in operations and
day-to-day management of a lease, plant, pipeline, or other facility;
and
(v) Other evidence of power to exercise control over or common
control with another person.
[[Page 82]]
(3) Regardless of any percentage of ownership or common ownership,
relatives, either by blood or marriage, are affiliates.
Allowance means a deduction in determining value for royalty
purposes. Processing allowance means an allowance for the reasonable,
actual costs of processing gas determined under this subpart.
Transportation allowance means an allowance for the reasonable, actual
costs of moving unprocessed gas, residue gas, or gas plant products to a
point of sale or delivery off the lease, unit area, or communitized
area, or away from a processing plant. The transportation allowance does
not include gathering costs.
Area means a geographic region at least as large as the defined
limits of an oil and/or gas field, in which oil and/or gas lease
products have similar quality, economic, and legal characteristics.
Arm's-length contract means a contract or agreement between
independent persons who are not affiliates and who have opposing
economic interests regarding that contract. To be considered arm's
length for any production month, a contract must satisfy this definition
for that month, as well as when the contract was executed.
Audit means a review, conducted in accordance with generally
accepted accounting and auditing standards, of royalty payment
compliance activities of lessees or other interest holders who pay
royalties, rents, or bonuses on Federal leases.
BLM means the Bureau of Land Management of the Department of the
Interior.
Compression means the process of raising the pressure of gas.
Condensate means liquid hydrocarbons (normally exceeding 40 degrees
of API gravity) recovered at the surface without resorting to
processing. Condensate is the mixture of liquid hydrocarbons that
results from condensation of petroleum hydrocarbons existing initially
in a gaseous phase in an underground reservoir.
Contract means any oral or written agreement, including amendments
or revisions thereto, between two or more persons and enforceable by law
that with due consideration creates an obligation.
Field means a geographic region situated over one or more subsurface
oil and gas reservoirs encompassing at least the outermost boundaries of
all oil and gas accumulations known to be within those reservoirs
vertically projected to the land surface. Onshore fields are usually
given names and their official boundaries are often designated by oil
and gas regulatory agencies in the respective States in which the fields
are located. Outer Continental Shelf (OCS) fields are named and their
boundaries are designated by MMS.
Gas means any fluid, either combustible or noncombustible,
hydrocarbon or nonhydrocarbon, which is extracted from a reservoir and
which has neither independent shape nor volume, but tends to expand
indefinitely. It is a substance that exists in a gaseous or rarefied
state under standard temperature and pressure conditions.
Gas plant products means separate marketable elements, compounds, or
mixtures, whether in liquid, gaseous, or solid form, resulting from
processing gas, excluding residue gas.
Gathering means the movement of lease production to a central
accumulation and/or treatment point on the lease, unit or communitized
area, or to a central accumulation or treatment point off the lease,
unit or communitized area as approved by BLM or MMS OCS operations
personnel for onshore and OCS leases, respectively.
Gross proceeds (for royalty payment purposes) means the total monies
and other consideration accruing to an oil and gas lessee for the
disposition of the gas, residue gas, and gas plant products produced.
Gross proceeds includes, but is not limited to, payments to the lessee
for certain services such as dehydration, measurement, and/or gathering
to the extent that the lessee is obligated to perform them at no cost to
the Federal Government. Tax reimbursements are part of the gross
proceeds accruing to a lessee even though the Federal royalty interest
may be exempt from taxation. Monies and other consideration, including
the forms of
[[Page 83]]
consideration identified in this paragraph, to which a lessee is
contractually or legally entitled but which it does not seek to collect
through reasonable efforts are also part of gross proceeds.
Lease means any contract, profit-share arrangement, joint venture,
or other agreement issued or approved by the United States under a
mineral leasing law that authorizes exploration for, development or
extraction of, or removal of lease products--or the land area covered by
that authorization, whichever is required by the context.
Lease products means any leased minerals attributable to,
originating from, or allocated to Outer Continental Shelf or onshore
Federal leases.
Lessee means any person to whom the United States issues a lease,
and any person who has been assigned an obligation to make royalty or
other payments required by the lease. This includes any person who has
an interest in a lease as well as an operator or payor who has no
interest in the lease but who has assumed the royalty payment
responsibility.
Like-quality lease products means lease products which have similar
chemical, physical, and legal characteristics.
Marketable condition means lease products which are sufficiently
free from impurities and otherwise in a condition that they will be
accepted by a purchaser under a sales contract typical for the field or
area.
Marketing affiliate means an affiliate of the lessee whose function
is to acquire only the lessee's production and to market that
production.
Minimum royalty means that minimum amount of annual royalty that the
lessee must pay as specified in the lease or in applicable leasing
regulations.
Net-back method (or work-back method) means a method for calculating
market value of gas at the lease. Under this method, costs of
transportation, processing, or manufacturing are deducted from the
proceeds received for the gas, residue gas or gas plant products, and
any extracted, processed, or manufactured products, or from the value of
the gas, residue gas or gas plant products, and any extracted,
processed, or manufactured products, at the first point at which
reasonable values for any such products may be determined by a sale
pursuant to an arm's-length contract or comparison to other sales of
such products, to ascertain value at the lease.
Net output means the quantity of residue gas and each gas plant
product that a processing plant produces.
Net profit share (for applicable Federal leases) means the specified
share of the net profit from production of oil and gas as provided in
the agreement.
Netting is the deduction of an allowance from the sales value by
reporting a one line net sales value, instead of correctly reporting the
deduction as a separate line item on the Form MMS-2014.
Outer Continental Shelf (OCS) means all submerged lands lying
seaward and outside of the area of land beneath navigable waters as
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of
which the subsoil and seabed appertain to the United States and are
subject to its jurisdiction and control.
Person means any individual, firm, corporation, association,
partnership, consortium, or joint venture (when established as a
separate entity).
Posted price means the price, net of all adjustments for quality and
location, specified in publicly available price bulletins or other price
notices available as part of normal business operations for quantities
of unprocessed gas, residue gas, or gas plant products in marketable
condition.
Processing means any process designed to remove elements or
compounds (hydrocarbon and nonhydrocarbon) from gas, including
absorption, adsorption, or refrigeration. Field processes which normally
take place on or near the lease, such as natural pressure reduction,
mechanical separation, heating, cooling, dehydration, and compression,
are not considered processing. The changing of pressures and/or
temperatures in a reservoir is not considered processing.
Residue gas means that hydrocarbon gas consisting principally of
methane resulting from processing gas.
[[Page 84]]
Section 6 lease means an OCS lease subject to section 6 of the Outer
Continental Shelf Lands Act, as amended, 43 U.S.C. 1335.
Selling arrangement means the individual contractual arrangements
under which sales or dispositions of gas, residue gas and gas plant
products are made. Selling arrangements are described by illustration in
the MMS Royalty Management Program Oil and Gas Payor Handbook.
Spot sales agreement means a contract wherein a seller agrees to
sell to a buyer a specified amount of unprocessed gas, residue gas, or
gas plant products at a specified price over a fixed period, usually of
short duration, which does not normally require a cancellation notice to
terminate, and which does not contain an obligation, nor imply an
intent, to continue in subsequent periods.
Warranty contract means a long-term contract entered into prior to
1970, including any amendments thereto, for the sale of gas wherein the
producer agrees to sell a specific amount of gas and the gas delivered
in satisfaction of this obligation may come from fields or sources
outside of the designated fields.
[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45084, Nov. 8, 1988; 61
FR 5464, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999; 70 FR 11878, Mar.
10, 2005]
Sec. 206.152 Valuation standards--unprocessed gas.
(a)(1) This section applies to the valuation of all gas that is not
processed and all gas that is processed but is sold or otherwise
disposed of by the lessee pursuant to an arm's-length contract prior to
processing (including all gas where the lessee's arm's-length contract
for the sale of that gas prior to processing provides for the value to
be determined on the basis of a percentage of the purchaser's proceeds
resulting from processing the gas). This section also applies to
processed gas that must be valued prior to processing in accordance with
Sec. 206.155 of this part. Where the lessee's contract includes a
reservation of the right to process the gas and the lessee exercises
that right, Sec. 206.153 of this part shall apply instead of this
section.
(2) The value of production, for royalty purposes, of gas subject to
this subpart shall be the value of gas determined under this section
less applicable allowances.
(b)(1)(i) The value of gas sold under an arm's-length contract is
the gross proceeds accruing to the lessee except as provided in
paragraphs (b)(1)(ii), (iii), and (iv) of this section. The lessee shall
have the burden of demonstrating that its contract is arm's-length. The
value which the lessee reports, for royalty purposes, is subject to
monitoring, review, and audit. For purposes of this section, gas which
is sold or otherwise transferred to the lessee's marketing affiliate and
then sold by the marketing affiliate pursuant to an arm's-length
contract shall be valued in accordance with this paragraph based upon
the sale by the marketing affiliate. Also, where the lessee's arm's-
length contract for the sale of gas prior to processing provides for the
value to be determined based upon a percentage of the purchaser's
proceeds resulting from processing the gas, the value of production, for
royalty purposes, shall never be less than a value equivalent to 100
percent of the value of the residue gas attributable to the processing
of the lessee's gas.
(ii) In conducting reviews and audits, MMS will examine whether the
contract reflects the total consideration actually transferred either
directly or indirectly from the buyer to the seller for the gas. If the
contract does not reflect the total consideration, then the MMS may
require that the gas sold pursuant to that contract be valued in
accordance with paragraph (c) of this section. Value may not be less
than the gross proceeds accruing to the lessee, including the additional
consideration.
(iii) If the MMS determines that the gross proceeds accruing to the
lessee pursuant to an arm's-length contract do not reflect the
reasonable value of the production because of misconduct by or between
the contracting parties, or because the lessee otherwise has breached
its duty to the lessor to market the production for the mutual benefit
of the lessee and the lessor, then MMS shall require that the gas
production be valued pursuant to paragraph
[[Page 85]]
(c)(2) or (c)(3) of this section, and in accordance with the
notification requirements of paragraph (e) of this section. When MMS
determines that the value may be unreasonable, MMS will notify the
lessee and give the lessee an opportunity to provide written information
justifying the lessee's value.
(iv) How to value over-delivered volumes under a cash-out program.
This paragraph applies to situations where a pipeline purchases gas from
a lessee according to a cash-out program under a transportation
contract. For all over-delivered volumes, the royalty value is the price
the pipeline is required to pay for volumes within the tolerances for
over-delivery specified in the transportation contract. Use the same
value for volumes that exceed the over-delivery tolerances even if those
volumes are subject to a lower price under the transportation contract.
However, if MMS determines that the price specified in the
transportation contract for over-delivered volumes is unreasonably low,
the lessee must value all over-delivered volumes under paragraph (c)(2)
or (c)(3) of this section.
(2) Notwithstanding the provisions of paragraph (b)(1) of this
section, the value of gas sold pursuant to a warranty contract shall be
determined by MMS, and due consideration will be given to all valuation
criteria specified in this section. The lessee must request a value
determination in accordance with paragraph (g) of this section for gas
sold pursuant to a warranty contract; provided, however, that any value
determination for a warranty contract in effect on the effective date of
these regulations shall remain in effect until modified by MMS.
(3) MMS may require a lessee to certify that its arm's-length
contract provisions include all of the consideration to be paid by the
buyer, either directly or indirectly, for the gas.
(c) The value of gas subject to this section which is not sold
pursuant to an arm's-length contract shall be the reasonable value
determined in accordance with the first applicable of the following
methods:
(1) The gross proceeds accruing to the lessee pursuant to a sale
under its non-arm's-length contract (or other disposition other than by
an arm's-length contract), provided that those gross proceeds are
equivalent to the gross proceeds derived from, or paid under, comparable
arm's-length contracts for purchases, sales, or other dispositions of
like-quality gas in the same field (or, if necessary to obtain a
reasonable sample, from the same area). In evaluating the comparability
of arm's-length contracts for the purposes of these regulations, the
following factors shall be considered: price, time of execution,
duration, market or markets served, terms, quality of gas, volume, and
such other factors as may be appropriate to reflect the value of the
gas;
(2) A value determined by consideration of other information
relevant in valuing like-quality gas, including gross proceeds under
arm's-length contracts for like-quality gas in the same field or nearby
fields or areas, posted prices for gas, prices received in arm's-length
spot sales of gas, other reliable public sources of price or market
information, and other information as to the particular lease operation
or the saleability of the gas; or
(3) A net-back method or any other reasonable method to determine
value.
(d)(1) Notwithstanding any other provisions of this section, except
paragraph (h) of this section, if the maximum price permitted by Federal
law at which gas may be sold is less than the value determined pursuant
to this section, then MMS shall accept such maximum price as the value.
For purposes of this section, price limitations set by any State or
local government shall not be considered as a maximum price permitted by
Federal law.
(2) The limitation prescribed in paragraph (d)(1) of this section
shall not apply to gas sold pursuant to a warranty contract and valued
pursuant to paragraph (b)(2) of this section.
(e)(1) Where the value is determined pursuant to paragraph (c) of
this section, the lessee shall retain all data relevant to the
determination of royalty value. Such data shall be subject to review and
audit, and MMS will direct a lessee to use a different value if it
determines that the reported value is inconsistent with the requirements
of these regulations.
[[Page 86]]
(2) Any Federal lessee will make available upon request to the
authorized MMS or State representatives, to the Office of the Inspector
General of the Department of the Interior, or other person authorized to
receive such information, arm's-length sales and volume data for like-
quality production sold, purchased or otherwise obtained by the lessee
from the field or area or from nearby fields or areas.
(3) A lessee shall notify MMS if it has determined value pursuant to
paragraph (c)(2) or (c)(3) of this section. The notification shall be by
letter to the MMS Associate Director for Minerals Revenue Management or
his/her designee. The letter shall identify the valuation method to be
used and contain a brief description of the procedure to be followed.
The notification required by this paragraph is a one-time notification
due no later than the end of the month following the month the lessee
first reports royalties on a Form MMS-2014 using a valuation method
authorized by paragraph (c)(2) or (c)(3) of this section, and each time
there is a change in a method under paragraph (c)(2) or (c)(3) of this
section.
(f) If MMS determines that a lessee has not properly determined
value, the lessee shall pay the difference, if any, between royalty
payments made based upon the value it has used and the royalty payments
that are due based upon the value established by MMS. The lessee shall
also pay interest on that difference computed pursuant to 30 CFR 218.54.
If the lessee is entitled to a credit, MMS will provide instructions for
the taking of that credit.
(g) The lessee may request a value determination from MMS. In that
event, the lessee shall propose to MMS a value determination method, and
may use that method in determining value for royalty purposes until MMS
issues its decision. The lessee shall submit all available data relevant
to its proposal. The MMS shall expeditiously determine the value based
upon the lessee's proposal and any additional information MMS deems
necessary. In making a value determination MMS may use any of the
valuation criteria authorized by this subpart. That determination shall
remain effective for the period stated therein. After MMS issues its
determination, the lessee shall make the adjustments in accordance with
paragraph (f) of this section.
(h) Notwithstanding any other provision of this section, under no
circumstances shall the value of production for royalty purposes be less
than the gross proceeds accruing to the lessee for lease production,
less applicable allowances.
(i) The lessee must place gas in marketable condition and market the
gas for the mutual benefit of the lessee and the lessor at no cost to
the Federal Government. Where the value established under this section
is determined by a lessee's gross proceeds, that value will be increased
to the extent that the gross proceeds have been reduced because the
purchaser, or any other person, is providing certain services the cost
of which ordinarily is the responsibility of the lessee to place the gas
in marketable condition or to market the gas.
(j) Value shall be based on the highest price a prudent lessee can
receive through legally enforceable claims under its contract. If there
is no contract revision or amendment, and the lessee fails to take
proper or timely action to receive prices or benefits to which it is
entitled, it must pay royalty at a value based upon that obtainable
price or benefit. Contract revisions or amendments shall be in writing
and signed by all parties to an arm's-length contract. If the lessee
makes timely application for a price increase or benefit allowed under
its contract but the purchaser refuses, and the lessee takes reasonable
measures, which are documented, to force purchaser compliance, the
lessee will owe no additional royalties unless or until monies or
consideration resulting from the price increase or additional benefits
are received. This paragraph shall not be construed to permit a lessee
to avoid its royalty payment obligation in situations where a purchaser
fails to pay, in whole or in part or timely, for a quantity of gas.
(k) Notwithstanding any provision in these regulations to the
contrary, no review, reconciliation, monitoring, or other like process
that results in a redetermination by MMS of value under this section
shall be considered final or
[[Page 87]]
binding as against the Federal Government or its beneficiaries until the
audit period is formally closed.
(l) Certain information submitted to MMS to support valuation
proposals, including transportation or extraordinary cost allowances, is
exempted from disclosure by the Freedom of Information Act, 5 U.S.C.
Sec. 552, or other Federal law. Any data specified by law to be
privileged, confidential, or otherwise exempt will be maintained in a
confidential manner in accordance with applicable law and regulations.
All requests for information about determinations made under this
subpart are to be submitted in accordance with the Freedom of
Information Act regulation of the Department of the Interior, 43 CFR
part 2.
[53 FR 1272, Jan. 15, 1988, as amended at 56 FR 46530, Sept. 13, 1991;
61 FR 5464, Feb. 12, 1996; 62 FR 65761, 65762, Dec. 16, 1997]
Sec. 206.153 Valuation standards--processed gas.
(a)(1) This section applies to the valuation of all gas that is
processed by the lessee and any other gas production to which this
subpart applies and that is not subject to the valuation provisions of
Sec. 206.152 of this part. This section applies where the lessee's
contract includes a reservation of the right to process the gas and the
lessee exercises that right.
(2) The value of production, for royalty purposes, of gas subject to
this section shall be the combined value of the residue gas and all gas
plant products determined pursuant to this section, plus the value of
any condensate recovered downstream of the point of royalty settlement
without resorting to processing determined pursuant to Sec. 206.102 of
this part, less applicable transportation allowances and processing
allowances determined pursuant to this subpart.
(b)(1)(i) The value of residue gas or any gas plant product sold
under an arm's-length contract is the gross proceeds accruing to the
lessee, except as provided in paragraphs (b)(1)(ii), (iii), and (iv) of
this section. The lessee shall have the burden of demonstrating that its
contract is arm's-length. The value that the lessee reports for royalty
purposes is subject to monitoring, review, and audit. For purposes of
this section, residue gas or any gas plant product which is sold or
otherwise transferred to the lessee's marketing affiliate and then sold
by the marketing affiliate pursuant to an arm's-length contract shall be
valued in accordance with this paragraph based upon the sale by the
marketing affiliate.
(ii) In conducting these reviews and audits, MMS will examine
whether or not the contract reflects the total consideration actually
transferred either directly or indirectly from the buyer to the seller
for the residue gas or gas plant product. If the contract does not
reflect the total consideration, then the MMS may require that the
residue gas or gas plant product sold pursuant to that contract be
valued in accordance with paragraph (c) of this section. Value may not
be less than the gross proceeds accruing to the lessee, including the
additional consideration.
(iii) If the MMS determines that the gross proceeds accruing to the
lessee pursuant to an arm's-length contract do not reflect the
reasonable value of the residue gas or gas plant product because of
misconduct by or between the contracting parties, or because the lessee
otherwise has breached its duty to the lessor to market the production
for the mutual benefit of the lessee and the lessor, then MMS shall
require that the residue gas or gas plant product be valued pursuant to
paragraph (c)(2) or (c)(3) of this section, and in accordance with the
notification requirements of paragraph (e) of this section. When MMS
determines that the value may be unreasonable, MMS will notify the
lessee and give the lessee an opportunity to provide written information
justifying the lessee's value.
(iv) How to value over-delivered volumes under a cash-out program.
This paragraph applies to situations where a pipeline purchases gas from
a lessee according to a cash-out program under a transportation
contract. For all over-delivered volumes, the royalty value is the price
the pipeline is required to pay for volumes within the tolerances for
over-delivery specified in the transportation contract. Use the same
value for volumes that exceed the over-delivery tolerances even if those
volumes are subject to a lower price under the
[[Page 88]]
transportation contract. However, if MMS determines that the price
specified in the transportation contract for over-delivered volumes is
unreasonably low, the lessee must value all over-delivered volumes under
paragraph (c)(2) or (c)(3) of this section.
(2) Notwithstanding the provisions of paragraph (b)(1) of this
section, the value of residue gas sold pursuant to a warranty contract
shall be determined by MMS, and due consideration will be given to all
valuation criteria specified in this section. The lessee must request a
value determination in accordance with paragraph (g) of this section for
gas sold pursuant to a warranty contract; provided, however, that any
value determination for a warranty contract in effect on the effective
date of these regulations shall remain in effect until modified by MMS.
(3) MMS may require a lessee to certify that its arm's-length
contract provisions include all of the consideration to be paid by the
buyer, either directly or indirectly, for the residue gas or gas plant
product.
(c) The value of residue gas or any gas plant product which is not
sold pursuant to an arm's-length contract shall be the reasonable value
determined in accordance with the first applicable of the following
methods:
(1) The gross proceeds accruing to the lessee pursuant to a sale
under its non-arm's-length contract (or other disposition other than by
an arm's-length contract), provided that those gross proceeds are
equivalent to the gross proceeds derived from, or paid under, comparable
arm's-length contracts for purchases, sales, or other dispositions of
like quality residue gas or gas plant products from the same processing
plant (or, if necessary to obtain a reasonable sample, from nearby
plants). In evaluating the comparability of arm's-length contracts for
the purposes of these regulations, the following factors shall be
considered: price, time of execution, duration, market or markets
served, terms, quality of residue gas or gas plant products, volume, and
such other factors as may be appropriate to reflect the value of the
residue gas or gas plant products;
(2) A value determined by consideration of other information
relevant in valuing like-quality residue gas or gas plant products,
including gross proceeds under arm's-length contracts for like-quality
residue gas or gas plant products from the same gas plant or other
nearby processing plants, posted prices for residue gas or gas plant
products, prices received in spot sales of residue gas or gas plant
products, other reliable public sources of price or market information,
and other information as to the particular lease operation or the
saleability of such residue gas or gas plant products; or
(3) A net-back method or any other reasonable method to determine
value.
(d)(1) Notwithstanding any other provisions of this section, except
paragraph (h) of this section, if the maximum price permitted by Federal
law at which any residue gas or gas plant products may be sold is less
than the value determined pursuant to this section, then MMS shall
accept such maximum price as the value. For the purposes of this
section, price limitations set by any State or local government shall
not be considered as a maximum price permitted by Federal law.
(2) The limitation prescribed by paragraph (d)(1) of this section
shall not apply to residue gas sold pursuant to a warranty contract and
valued pursuant to paragraph (b)(2) of this section.
(e)(1) Where the value is determined pursuant to paragraph (c) of
this section, the lessee shall retain all data relevant to the
determination of royalty value. Such data shall be subject to review and
audit, and MMS will direct a lessee to use a different value if it
determines upon review or audit that the reported value is inconsistent
with the requirements of these regulations.
(2) Any Federal lessee will make available upon request to the
authorized MMS or State representatives, to the Office of the Inspector
General of the Department of the Interior, or other persons authorized
to receive such information, arm's-length sales and volume data for
like-quality residue gas and gas plant products sold, purchased or
otherwise obtained by the lessee from the same processing plant or from
nearby processing plants.
(3) A lessee shall notify MMS if it has determined any value
pursuant to paragraph (c)(2) or (c)(3) of this section.
[[Page 89]]
The notification shall be by letter to the MMS Associate Director for
Minerals Revenue Management or his/her designee. The letter shall
identify the valuation method to be used and contain a brief description
of the procedure to be followed. The notification required by this
paragraph is a one-time notification due no later than the end of the
month following the month the lessee first reports royalties on a Form
MMS-2014 using a valuation method authorized by paragraph (c)(2) or
(c)(3) of this section, and each time there is a change in a method
under paragraph (c)(2) or (c)(3) of this section.
(f) If MMS determines that a lessee has not properly determined
value, the lessee shall pay the difference, if any, between royalty
payments made based upon the value it has used and the royalty payments
that are due based upon the value established by MMS. The lessee shall
also pay interest computed on that difference pursuant to 30 CFR 218.54.
If the lessee is entitled to a credit, MMS will provide instructions for
the taking of that credit.
(g) The lessee may request a value determination from MMS. In that
event, the lessee shall propose to MMS a value determination method, and
may use that method in determining value for royalty purposes until MMS
issues its decision. The lessee shall submit all available data relevant
to its proposal. The MMS shall expeditiously determine the value based
upon the lessee's proposal and any additional information MMS deems
necessary. In making a value determination, MMS may use any of the
valuation criteria authorized by this subpart. That determination shall
remain effective for the period stated therein. After MMS issues its
determination, the lessee shall make the adjustments in accordance with
paragraph (f) of this section.
(h) Notwithstanding any other provision of this section, under no
circumstances shall the value of production for royalty purposes be less
than the gross proceeds accruing to the lessee for residue gas and/or
any gas plant products, less applicable transportation allowances and
processing allowances determined pursuant to this subpart.
(i) The lessee must place residue gas and gas plant products in
marketable condition and market the residue gas and gas plant products
for the mutual benefit of the lessee and the lessor at no cost to the
Federal Government. Where the value established under this section is
determined by a lessee's gross proceeds, that value will be increased to
the extent that the gross proceeds have been reduced because the
purchaser, or any other person, is providing certain services the cost
of which ordinarily is the responsibility of the lessee to place the
residue gas or gas plant products in marketable condition or to market
the residue gas and gas plant products.
(j) Value shall be based on the highest price a prudent lessee can
receive through legally enforceable claims under its contract. Absent
contract revision or amendment, if the lessee fails to take proper or
timely action to receive prices or benefits to which it is entitled it
must pay royalty at a value based upon that obtainable price or benefit.
Contract revisions or amendments shall be in writing and signed by all
parties to an arm's-length contract. If the lessee makes timely
application for a price increase or benefit allowed under its contract
but the purchaser refuses, and the lessee takes reasonable measures,
which are documented, to force purchaser compliance, the lessee will owe
no additional royalties unless or until monies or consideration
resulting from the price increase or additional benefits are received.
This paragraph shall not be construed to permit a lessee to avoid its
royalty payment obligation in situations where a purchaser fails to pay,
in whole or in part, or timely, for a quantity of residue gas or gas
plant product.
(k) Notwithstanding any provision in these regulations to the
contrary, no review, reconciliation, monitoring, or other like process
that results in a redetermination by MMS of value under this section
shall be considered final or binding against the Federal Government or
its beneficiaries until the audit period is formally closed.
(l) Certain information submitted to MMS to support valuation
proposals, including transportation allowances, processing allowances or
extraordinary
[[Page 90]]
cost allowances, is exempted from disclosure by the Freedom of
Information Act, 5 U.S.C. 552, or other Federal law. Any data specified
by law to be privileged, confidential, or otherwise exempt, will be
maintained in a confidential manner in accordance with applicable law
and regulations. All requests for information about determinations made
under this part are to be submitted in accordance with the Freedom of
Information Act regulation of the Department of the Interior, 43 CFR
part 2.
[53 FR 1272, Jan. 15, 1988, as amended at 56 FR 46530, Sept. 13, 1991;
61 FR 5465, Feb. 12, 1996; 62 FR 65762, Dec. 16, 1997]
Sec. 206.154 Determination of quantities and qualities for computing
royalties.
(a)(1) Royalties shall be computed on the basis of the quantity and
quality of unprocessed gas at the point of royalty settlement approved
by BLM or MMS for onshore and OCS leases, respectively.
(2) If the value of gas determined pursuant to Sec. 206.152 of this
subpart is based upon a quantity and/or quality that is different from
the quantity and/or quality at the point of royalty settlement, as
approved by BLM or MMS, that value shall be adjusted for the differences
in quantity and/or quality.
(b)(1) For residue gas and gas plant products, the quantity basis
for computing royalties due is the monthly net output of the plant even
though residue gas and/or gas plant products may be in temporary
storage.
(2) If the value of residue gas and/or gas plant products determined
pursuant to Sec. 206.153 of this subpart is based upon a quantity and/
or quality of residue gas and/or gas plant products that is different
from that which is attributable to a lease, determined in accordance
with paragraph (c) of this section, that value shall be adjusted for the
differences in quantity and/or quality.
(c) The quantity of the residue gas and gas plant products
attributable to a lease shall be determined according to the following
procedure:
(1) When the net output of the processing plant is derived from gas
obtained from only one lease, the quantity of the residue gas and gas
plant products on which computations of royalty are based is the net
output of the plant.
(2) When the net output of a processing plant is derived from gas
obtained from more than one lease producing gas of uniform content, the
quantity of the residue gas and gas plant products allocable to each
lease shall be in the same proportions as the ratios obtained by
dividing the amount of gas delivered to the plant from each lease by the
total amount of gas delivered from all leases.
(3) When the net output of a processing plant is derived from gas
obtained from more than one lease producing gas of nonuniform content,
the quantity of the residue gas allocable to each lease will be
determined by multiplying the amount of gas delivered to the plant from
the lease by the residue gas content of the gas, and dividing the
arithmetical product thus obtained by the sum of the similar
arithmetical products separately obtained for all leases from which gas
is delivered to the plant, and then multiplying the net output of the
residue gas by the arithmetic quotient obtained. The net output of gas
plant products allocable to each lease will be determined by multiplying
the amount of gas delivered to the plant from the lease by the gas plant
product content of the gas, and dividing the arithmetical product thus
obtained by the sum of the similar arithmetical products separately
obtained for all leases from which gas is delivered to the plant, and
then multiplying the net output of each gas plant product by the
arithmetic quotient obtained.
(4) A lessee may request MMS approval of other methods for
determining the quantity of residue gas and gas plant products allocable
to each lease. If approved, such method will be applicable to all gas
production from Federal leases that is processed in the same plant.
(d)(1) No deductions may be made from the royalty volume or royalty
value for actual or theoretical losses. Any actual loss of unprocessed
gas that may be sustained prior to the royalty settlement metering or
measurement point will not be subject to royalty provided that such loss
is determined
[[Page 91]]
to have been unavoidable by BLM or MMS, as appropriate.
(2) Except as provided in paragraph (d)(1) of this section and 30
CFR 202.151(c), royalties are due on 100 percent of the volume
determined in accordance with paragraphs (a) through (c) of this
section. There can be no reduction in that determined volume for actual
losses after the quantity basis has been determined or for theoretical
losses that are claimed to have taken place. Royalties are due on 100
percent of the value of the unprocessed gas, residue gas, and/or gas
plant products as provided in this subpart, less applicable allowances.
There can be no deduction from the value of the unprocessed gas, residue
gas, and/or gas plant products to compensate for actual losses after the
quantity basis has been determined, or for theoretical losses that are
claimed to have taken place.
[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5465, Feb. 12, 1996]
Sec. 206.155 Accounting for comparison.
(a) Except as provided in paragraph (b) of this section, where the
lessee (or a person to whom the lessee has transferred gas pursuant to a
non-arm's-length contract or without a contract) processes the lessee's
gas and after processing the gas the residue gas is not sold pursuant to
an arm's-length contract, the value, for royalty purposes, shall be the
greater of (1) the combined value, for royalty purposes, of the residue
gas and gas plant products resulting from processing the gas determined
pursuant to Sec. 206.153 of this subpart, plus the value, for royalty
purposes, of any condensate recovered downstream of the point of royalty
settlement without resorting to processing determined pursuant to Sec.
206.102 of this subpart; or (2) the value, for royalty purposes, of the
gas prior to processing determined in accordance with Sec. 206.152 of
this subpart.
(b) The requirement for accounting for comparison contained in the
terms of leases will govern as provided in Sec. 206.150(b) of this
subpart. When accounting for comparison is required by the lease terms,
such accounting for comparison shall be determined in accordance with
paragraph (a) of this section.
[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5465, Feb. 12, 1996]
Sec. 206.156 Transportation allowances--general.
(a) Where the value of gas has been determined pursuant to Sec.
206.152 or Sec. 206.153 of this subpart at a point (e.g., sales point
or point of value determination) off the lease, MMS shall allow a
deduction for the reasonable actual costs incurred by the lessee to
transport unprocessed gas, residue gas, and gas plant products from a
lease to a point off the lease including, if appropriate, transportation
from the lease to a gas processing plant off the lease and from the
plant to a point away from the plant.
(b) Transportation costs must be allocated among all products
produced and transported as provided in Sec. 206.157.
(c)(1) Except as provided in paragraph (c)(3) of this section, for
unprocessed gas valued in accordance with Sec. 206.152 of this subpart,
the transportation allowance deduction on the basis of a selling
arrangement shall not exceed 50 percent of the value of the unprocessed
gas determined in accordance with Sec. 206.152 of this subpart.
(2) Except as provided in paragraph (c)(3) of this section, for gas
production valued in accordance with Sec. 206.153 of this subpart the
transportation allowance deduction on the basis of a selling arrangement
shall not exceed 50 percent of the value of the residue gas or gas plant
product determined in accordance with Sec. 206.153 of this subpart. For
purposes of this section, natural gas liquids shall be considered one
product.
(3) Upon request of a lessee, MMS may approve a transportation
allowance deduction in excess of the limitations prescribed by
paragraphs (c)(1) and (c)(2) of this section. The lessee must
demonstrate that the transportation costs incurred in excess of the
limitations prescribed in paragraphs (c)(1) and (c)(2) of this section
were reasonable, actual, and necessary. An application for exception
(using Form MMS-4393, Request to Exceed Regulatory Allowance Limitation)
shall contain all relevant and supporting
[[Page 92]]
documentation necessary for MMS to make a determination. Under no
circumstances shall the value for royalty purposes under any selling
arrangement be reduced to zero.
(d) If, after a review and/or audit, MMS determines that a lessee
has improperly determined a transportation allowance authorized by this
subpart, then the lessee shall pay any additional royalties, plus
interest, determined in accordance with 30 CFR 218.54, or shall be
entitled to a credit, without interest. If the lessee takes a deduction
for transportation on the Form MMS-2014 by improperly netting the
allowance against the sales value of the unprocessed gas, residue gas,
and gas plant products instead of reporting the allowance as a separate
line item, he may be assessed an additional amount under 206.157(d).
[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5465, Feb. 12, 1996; 64
FR 43288, Aug. 10, 1999]
Sec. 206.157 Determination of transportation allowances.
(a) Arm's-length transportation contracts. (1)(i) For transportation
costs incurred by a lessee under an arm's-length contract, the
transportation allowance shall be the reasonable, actual costs incurred
by the lessee for transporting the unprocessed gas, residue gas and/or
gas plant products under that contract, except as provided in paragraphs
(a)(1)(ii) and (a)(1)(iii) of this section, subject to monitoring,
review, audit, and adjustment. The lessee shall have the burden of
demonstrating that its contract is arm's-length. MMS' prior approval is
not required before a lessee may deduct costs incurred under an arm's-
length contract. Such allowances shall be subject to the provisions of
paragraph (f) of this section. The lessee must claim a transportation
allowance by reporting it as a separate line entry on the Form MMS-2014.
(ii) In conducting reviews and audits, MMS will examine whether or
not the contract reflects more than the consideration actually
transferred either directly or indirectly from the lessee to the
transporter for the transportation. If the contract reflects more than
the total consideration, then the MMS may require that the
transportation allowance be determined in accordance with paragraph (b)
of this section.
(iii) If the MMS determines that the consideration paid pursuant to
an arm's-length transportation contract does not reflect the reasonable
value of the transportation because of misconduct by or between the
contracting parties, or because the lessee otherwise has breached its
duty to the lessor to market the production for the mutual benefit of
the lessee and the lessor, then MMS shall require that the
transportation allowance be determined in accordance with paragraph (b)
of this section. When MMS determines that the value of the
transportation may be unreasonable, MMS will notify the lessee and give
the lessee an opportunity to provide written information justifying the
lessee's transportation costs.
(2)(i) If an arm's-length transportation contract includes more than
one product in a gaseous phase and the transportation costs attributable
to each product cannot be determined from the contract, the total
transportation costs shall be allocated in a consistent and equitable
manner to each of the products transported in the same proportion as the
ratio of the volume of each product (excluding waste products which have
no value) to the volume of all products in the gaseous phase (excluding
waste products which have no value). Except as provided in this
paragraph, no allowance may be taken for the costs of transporting lease
production which is not royalty bearing without MMS approval.
(ii) Notwithstanding the requirements of paragraph (i), the lessee
may propose to MMS a cost allocation method on the basis of the values
of the products transported. MMS shall approve the method unless it
determines that it is not consistent with the purposes of the
regulations in this part.
(3) If an arm's-length transportation contract includes both gaseous
and liquid products and the transportation costs attributable to each
cannot be determined from the contract, the lessee shall propose an
allocation procedure to MMS. The lessee may use the transportation
allowance determined
[[Page 93]]
in accordance with its proposed allocation procedure until MMS issues
its determination on the acceptability of the cost allocation. The
lessee shall submit all relevant data to support its proposal. MMS shall
then determine the gas transportation allowance based upon the lessee's
proposal and any additional information MMS deems necessary. The lessee
must submit the allocation proposal within 3 months of claiming the
allocated deduction on the Form MMS-2014.
(4) Where the lessee's payments for transportation under an arm's-
length contract are not based on a dollar per unit, the lessee shall
convert whatever consideration is paid to a dollar value equivalent for
the purposes of this section.
(5) Where an arm's-length sales contract price or a posted price
includes a provision whereby the listed price is reduced by a
transportation factor, MMS will not consider the transportation factor
to be a transportation allowance. The transportation factor may be used
in determining the lessee's gross proceeds for the sale of the product.
The transportation factor may not exceed 50 percent of the base price of
the product without MMS approval.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length transportation contract or has no contract, including those
situations where the lessee performs transportation services for itself,
the transportation allowance will be based upon the lessee's reasonable
actual costs as provided in this paragraph. All transportation
allowances deducted under a non-arm's-length or no contract situation
are subject to monitoring, review, audit, and adjustment. The lessee
must claim a transportation allowance by reporting it as a separate line
entry on the Form MMS-2014. When necessary or appropriate, MMS may
direct a lessee to modify its estimated or actual transportation
allowance deduction.
(2) The transportation allowance for non-arm's-length or no-contract
situations shall be based upon the lessee's actual costs for
transportation during the reporting period, including operating and
maintenance expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph
(b)(2)(iv)(A) of this section, or a cost equal to the initial
depreciable investment in the transportation system multiplied by a rate
of return in accordance with paragraph (b)(2)(iv)(B) of this section.
Allowable capital costs are generally those costs for depreciable fixed
assets (including costs of delivery and installation of capital
equipment) which are an integral part of the transportation system.
(i) Allowable operating expenses include: Operations supervision and
engineering; operations labor; fuel; utilities; materials; ad valorem
property taxes; rent; supplies; and any other directly allocable and
attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the
transportation system; maintenance of equipment; maintenance labor; and
other directly allocable and attributable maintenance expenses which the
lessee can document.
(iii) Overhead directly attributable and allocable to the operation
and maintenance of the transportation system is an allowable expense.
State and Federal income taxes and severance taxes and other fees,
including royalties, are not allowable expenses.
(iv) A lessee may use either depreciation or a return on depreciable
capital investment. After a lessee has elected to use either method for
a transportation system, the lessee may not later elect to change to the
other alternative without approval of the MMS.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the transportation system services, or a
unit of production method. After an election is made, the lessee may not
change methods without MMS approval. A change in ownership of a
transportation system shall not alter the depreciation schedule
established by the original transporter/lessee for purposes of the
allowance calculation. With or without a change in ownership, a
transportation system shall be depreciated only once. Equipment shall
not be depreciated below a reasonable salvage value.
[[Page 94]]
(B) The MMS shall allow as a cost an amount equal to the allowable
initial capital investment in the transportation system multiplied by
the rate of return determined pursuant to paragraph (b)(2)(v) of this
section. No allowance shall be provided for depreciation. This
alternative shall apply only to transportation facilities first placed
in service after March 1, 1988.
(v) The rate of return must be 1.3 times the industrial rate
associated with Standard & Poor's BBB rating. The BBB rate must be the
monthly average rate as published in Standard & Poor's Bond Guide for
the first month for which the allowance is applicable. The rate must be
redetermined at the beginning of each subsequent calendar year.
(3)(i) The deduction for transportation costs shall be determined on
the basis of the lessee's cost of transporting each product through each
individual transportation system. Where more than one product in a
gaseous phase is transported, the allocation of costs to each of the
products transported shall be made in a consistent and equitable manner
in the same proportion as the ratio of the volume of each product
(excluding waste products which have no value) to the volume of all
products in the gaseous phase (excluding waste products which have no
value). Except as provided in this paragraph, the lessee may not take an
allowance for transporting a product which is not royalty bearing
without MMS approval.
(ii) Notwithstanding the requirements of paragraph (b)(3)(i), the
lessee may propose to the MMS a cost allocation method on the basis of
the values of the products transported. MMS shall approve the method
unless it determines that it is not consistent with the purposes of the
regulations in this part.
(4) Where both gaseous and liquid products are transported through
the same transportation system, the lessee shall propose a cost
allocation procedure to MMS. The lessee may use the transportation
allowance determined in accordance with its proposed allocation
procedure until MMS issues its determination on the acceptability of the
cost allocation. The lessee shall submit all relevant data to support
its proposal. MMS shall then determine the transportation allowance
based upon the lessee's proposal and any additional information MMS
deems necessary. The lessee must submit the allocation proposal within 3
months of claiming the allocated deduction on the Form MMS-2014.
(5) You may apply for an exception from the requirement to compute
actual costs under paragraphs (b)(1) through (b)(4) of this section.
(i) The MMS will grant the exception if:
(A) The transportation system has a tariff filed with the Federal
Energy Regulatory Commission (FERC) or a state regulatory agency, that
FERC or the state regulatory agency has permitted to become effective,
and
(B) Third parties are paying prices, including discounted prices,
under the tariff to transport gas on the system under arm's-length
transportation contracts.
(ii) If MMS approves the exception, you must calculate your
transportation allowance for each production month based on the lesser
of the volume-weighted average of the rates paid by the third parties
under arm's-length transportation contracts during that production month
or the non-arm's-length payment by the lessee to the pipeline.
(iii) If during any production month there are no prices paid under
the tariff by third parties to transport gas on the system under arm's-
length transportation contracts, you may use the volume-weighted average
of the rates paid by third parties under arm's-length transportation
contracts in the most recent preceding production month in which the
tariff remains in effect and third parties paid such rates, for up to
five successive production months. You must use the non-arm's-length
payment by the lessee to the pipeline if it is less than the volume-
weighted average of the rates paid by third parties under arm's-length
contracts.
(c) Reporting requirements--(1) Arm's-length contracts. (i) You must
use a separate entry on Form MMS-2014 to notify MMS of a transportation
allowance.
[[Page 95]]
(ii) The MMS may require you to submit arm's-length transportation
contracts, production agreements, operating agreements, and related
documents. Recordkeeping requirements are found at part 207 of this
chapter.
(iii) You may not use a transportation allowance that was in effect
before March 1, 1988. You must use the provisions of this subpart to
determine your transportation allowance.
(2) Non-arm's-length or no contract. (i) You must use a separate
entry on Form MMS-2014 to notify MMS of a transportation allowance.
(ii) For new transportation facilities or arrangements, base your
initial deduction on estimates of allowable gas transportation costs for
the applicable period. Use the most recently available operations data
for the transportation system or, if such data are not available, use
estimates based on data for similar transportation systems. Paragraph
(e) of this section will apply when you amend your report based on your
actual costs.
(iii) The MMS may require you to submit all data used to calculate
the allowance deduction. Recordkeeping requirements are found at part
207 of this chapter.
(iv) If you are authorized under paragraph (b)(5) of this section to
use an exception to the requirement to calculate your actual
transportation costs, you must follow the reporting requirements of
paragraph (c)(1) of this section.
(v) You may not use a transportation allowance that was in effect
before March 1, 1988. You must use the provisions of this subpart to
determine your transportation allowance.
(d) Interest and assessments. (1) If a lessee nets a transportation
allowance against the royalty value on the Form MMS-2014, the lessee
shall be assessed an amount of up to 10 percent of the allowance netted
not to exceed $250 per lease selling arrangement per sales period.
(2) If a lessee deducts a transportation allowance on its Form MMS-
2014 that exceeds 50 percent of the value of the gas transported without
obtaining prior approval of MMS under Sec. 206.156, the lessee shall
pay interest on the excess allowance amount taken from the date such
amount is taken to the date the lessee files an exception request with
MMS.
(3) If a lessee erroneously reports a transportation allowance which
results in an underpayment of royalties, interest shall be paid on the
amount of that underpayment.
(4) Interest required to be paid by this section shall be determined
in accordance with 30 CFR 218.54.
(e) Adjustments. (1) If the actual transportation allowance is less
than the amount the lessee has taken on Form MMS-2014 for each month
during the allowance reporting period, the lessee shall be required to
pay additional royalties due plus interest computed under 30 CFR 218.54
from the allowance reporting period when the lessee took the deduction
to the date the lessee repays the difference to MMS. If the actual
transportation allowance is greater than the amount the lessee has taken
on Form MMS-2014 for each month during the allowance reporting period,
the lessee shall be entitled to a credit without interest.
(2) For lessees transporting production from onshore Federal leases,
the lessee must submit a corrected Form MMS-2014 to reflect actual
costs, together with any payment, in accordance with instructions
provided by MMS.
(3) For lessees transporting gas production from leases on the OCS,
if the lessee's estimated transportation allowance exceeds the allowance
based on actual costs, the lessee must submit a corrected Form MMS-2014
to reflect actual costs, together with its payment, in accordance with
instructions provided by MMS. If the lessee's estimated transportation
allowance is less than the allowance based on actual costs, the refund
procedure will be specified by MMS.
(f) Allowable costs in determining transportation allowances. You
may include, but are not limited to (subject to the requirements of
paragraph (g) of this section), the following costs in determining the
arm's-length transportation allowance under paragraph (a) of this
section or the non-arm's-length transportation allowance under paragraph
(b) of this section. You may not
[[Page 96]]
use any cost as a deduction that duplicates all or part of any other
cost that you use under this paragraph.
(1) Firm demand charges paid to pipelines. You may deduct firm
demand charges or capacity reservation fees paid to a pipeline,
including charges or fees for unused firm capacity that you have not
sold before you report your allowance. If you receive a payment from any
party for release or sale of firm capacity after reporting a
transportation allowance that included the cost of that unused firm
capacity, or if you receive a payment or credit from the pipeline for
penalty refunds, rate case refunds, or other reasons, you must reduce
the firm demand charge claimed on the Form MMS-2014 by the amount of
that payment. You must modify the Form MMS-2014 by the amount received
or credited for the affected reporting period, and pay any resulting
royalty and late payment interest due;
(2) Gas supply realignment (GSR) costs. The GSR costs result from a
pipeline reforming or terminating supply contracts with producers to
implement the restructuring requirements of FERC Orders in 18 CFR part
284;
(3) Commodity charges. The commodity charge allows the pipeline to
recover the costs of providing service;
(4) Wheeling costs. Hub operators charge a wheeling cost for
transporting gas from one pipeline to either the same or another
pipeline through a market center or hub. A hub is a connected manifold
of pipelines through which a series of incoming pipelines are
interconnected to a series of outgoing pipelines;
(5) Gas Research Institute (GRI) fees. The GRI conducts research,
development, and commercialization programs on natural gas related
topics for the benefit of the U.S. gas industry and gas customers. GRI
fees are allowable provided such fees are mandatory in FERC-approved
tariffs;
(6) Annual Charge Adjustment (ACA) fees. FERC charges these fees to
pipelines to pay for its operating expenses;
(7) Payments (either volumetric or in value) for actual or
theoretical losses. However, theoretical losses are not deductible in
non-arm's-length transportation arrangements unless the transportation
allowance is based on arm's-length transportation rates charged under a
FERC- or state regulatory-approved tariff under paragraph (b)(5) of this
section. If you receive volumes or credit for line gain, you must reduce
your transportation allowance accordingly and pay any resulting
royalties and late payment interest due;
(8) Temporary storage services. This includes short duration storage
services offered by market centers or hubs (commonly referred to as
``parking'' or ``banking''), or other temporary storage services
provided by pipeline transporters, whether actual or provided as a
matter of accounting. Temporary storage is limited to 30 days or less;
and
(9) Supplemental costs for compression, dehydration, and treatment
of gas. MMS allows these costs only if such services are required for
transportation and exceed the services necessary to place production
into marketable condition required under Sec. Sec. 206.152(i) and
206.153(i) of this part.
(10) Costs of surety. You may deduct the costs of securing a letter
of credit, or other surety, that the pipeline requires you as a shipper
to maintain under an arm's-length transportation contract.
(g) Nonallowable costs in determining transportation allowances.
Lessees may not include the following costs in determining the arm's-
length transportation allowance under paragraph (a) of this section or
the non-arm's-length transportation allowance under paragraph (b) of
this section:
(1) Fees or costs incurred for storage. This includes storing
production in a storage facility, whether on or off the lease, for more
than 30 days;
(2) Aggregator/marketer fees. This includes fees you pay to another
person (including your affiliates) to market your gas, including
purchasing and reselling the gas, or finding or maintaining a market for
the gas production;
(3) Penalties you incur as shipper. These penalties include, but are
not limited to:
(i) Over-delivery cash-out penalties. This includes the difference
between the price the pipeline pays you for over-delivered volumes
outside the tolerances and the price you receive for
[[Page 97]]
over-delivered volumes within the tolerances;
(ii) Scheduling penalties. This includes penalties you incur for
differences between daily volumes delivered into the pipeline and
volumes scheduled or nominated at a receipt or delivery point;
(iii) Imbalance penalties. This includes penalties you incur
(generally on a monthly basis) for differences between volumes delivered
into the pipeline and volumes scheduled or nominated at a receipt or
delivery point; and
(iv) Operational penalties. This includes fees you incur for
violation of the pipeline's curtailment or operational orders issued to
protect the operational integrity of the pipeline;
(4) Intra-hub transfer fees. These are fees you pay to hub operators
for administrative services (e.g., title transfer tracking) necessary to
account for the sale of gas within a hub;
(5) Fees paid to brokers. This includes fees paid to parties who
arrange marketing or transportation, if such fees are separately
identified from aggregator/marketer fees;
(6) Fees paid to scheduling service providers. This includes fees
paid to parties who provide scheduling services, if such fees are
separately identified from aggregator/marketer fees;
(7) Internal costs. This includes salaries and related costs, rent/
space costs, office equipment costs, legal fees, and other costs to
schedule, nominate, and account for sale or movement of production; and
(8) Other nonallowable costs. Any cost you incur for services you
are required to provide at no cost to the lessor.
(h) Other transportation cost determinations. Use this section when
calculating transportation costs to establish value using a netback
procedure or any other procedure that requires deduction of
transportation costs.
[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45762, Nov. 14, 1988; 61
FR 5465, Feb. 12, 1996; 62 FR 65762, Dec. 16, 1997; 70 FR 11878, Mar.
10, 2005]
Sec. 206.158 Processing allowances--general.
(a) Where the value of gas is determined pursuant to Sec. 206.153
of this subpart, a deduction shall be allowed for the reasonable actual
costs of processing.
(b) Processing costs must be allocated among the gas plant products.
A separate processing allowance must be determined for each gas plant
product and processing plant relationship. Natural gas liquids (NGL's)
shall be considered as one product.
(c)(1) Except as provided in paragraph (d)(2) of this section, the
processing allowance shall not be applied against the value of the
residue gas. Where there is no residue gas MMS may designate an
appropriate gas plant product against which no allowance may be applied.
(2) Except as provided in paragraph (c)(3) of this section, the
processing allowance deduction on the basis of an individual product
shall not exceed 66\2/3\ percent of the value of each gas plant product
determined in accordance with Sec. 206.153 of this subpart (such value
to be reduced first for any transportation allowances related to
postprocessing transportation authorized by Sec. 206.156 of this
subpart).
(3) Upon request of a lessee, MMS may approve a processing allowance
in excess of the limitation prescribed by paragraph (c)(2) of this
section. The lessee must demonstrate that the processing costs incurred
in excess of the limitation prescribed in paragraph (c)(2) of this
section were reasonable, actual, and necessary. An application for
exception (using Form MMS-4393, Request to Exceed Regulatory Allowance
Limitation) shall contain all relevant and supporting documentation for
MMS to make a determination. Under no circumstances shall the value for
royalty purposes of any gas plant product be reduced to zero.
(d)(1) Except as provided in paragraph (d)(2) of this section, no
processing cost deduction shall be allowed for the costs of placing
lease products in marketable condition, including dehydration,
separation, compression, or storage, even if those functions are
performed off the lease or at a processing plant. Where gas is processed
for the removal of acid gases, commonly referred to as ``sweetening,''
no processing cost deduction shall be allowed for such costs unless the
acid gases removed are further processed into a gas
[[Page 98]]
plant product. In such event, the lessee shall be eligible for a
processing allowance as determined in accordance with this subpart.
However, MMS will not grant any processing allowance for processing
lease production which is not royalty bearing.
(2)(i) If the lessee incurs extraordinary costs for processing gas
production from a gas production operation, it may apply to MMS for an
allowance for those costs which shall be in addition to any other
processing allowance to which the lessee is entitled pursuant to this
section. Such an allowance may be granted only if the lessee can
demonstrate that the costs are, by reference to standard industry
conditions and practice, extraordinary, unusual, or unconventional.
(ii) Prior MMS approval to continue an extraordinary processing cost
allowance is not required. However, to retain the authority to deduct
the allowance the lessee must report the deduction to MMS in a form and
manner prescribed by MMS.
(e) If MMS determines that a lessee has improperly determined a
processing allowance authorized by this subpart, then the lessee shall
pay any additional royalties, plus interest determined in accordance
with 30 CFR 218.54, or shall be entitled to a credit, without interest.
If the lessee takes a deduction for processing on the Form MMS-2014 by
improperly netting the allowance against the sales value of the gas
plant products instead of reporting the allowance as a separate line
item, he may be assessed an additional amount under 206.159(d).
[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5466, Feb. 12, 1996; 64
FR 43288, Aug. 10, 1999]
Sec. 206.159 Determination of processing allowances.
(a) Arm's-length processing contracts. (1)(i) For processing costs
incurred by a lessee under an arm's-length contract, the processing
allowance shall be the reasonable actual costs incurred by the lessee
for processing the gas under that contract, except as provided in
paragraphs (a)(1)(ii) and (a)(1)(iii) of this section, subject to
monitoring, review, audit, and adjustment. The lessee shall have the
burden of demonstrating that its contract is arm's-length. MMS' prior
approval is not required before a lessee may deduct costs incurred under
an arm's-length contract. The lessee must claim a processing allowance
by reporting it as a separate line entry on the Form MMS-2014.
(ii) In conducting reviews and audits, MMS will examine whether the
contract reflects more than the consideration actually transferred
either directly or indirectly from the lessee to the processor for the
processing. If the contract reflects more than the total consideration,
then the MMS may require that the processing allowance be determined in
accordance with paragraph (b) of this section.
(iii) If MMS determines that the consideration paid pursuant to an
arm's-length processing contract does not reflect the reasonable value
of the processing because of misconduct by or between the contracting
parties, or because the lessee otherwise has breached its duty to the
lessor to market the production for the mutual benefit of the lessee and
lessor, then MMS shall require that the processing allowance be
determined in accordance with paragraph (b) of this section. When MMS
determines that the value of the processing may be unreasonable, MMS
will notify the lessee and give the lessee an opportunity to provide
written information justifying the lessee's processing costs.
(2) If an arm's-length processing contract includes more than one
gas plant product and the processing costs attributable to each product
can be determined from the contract, then the processing costs for each
gas plant product shall be determined in accordance with the contract.
No allowance may be taken for the costs of processing lease production
which is not royalty-bearing.
(3) If an arm's-length processing contract includes more than one
gas plant product and the processing costs attributable to each product
cannot be determined from the contract, the lessee shall propose an
allocation procedure to MMS. The lessee may use its proposed allocation
procedure until MMS issues its determination. The lessee shall submit
all relevant data to support its proposal. MMS shall then
[[Page 99]]
determine the processing allowance based upon the lessee's proposal and
any additional information MMS deems necessary. No processing allowance
will be granted for the costs of processing lease production which is
not royalty bearing. The lessee must submit the allocation proposal
within 3 months of claiming the allocated deduction on Form MMS-2014.
(4) Where the lessee's payments for processing under an arm's-length
contract are not based on a dollar per unit basis, the lessee shall
convert whatever consideration is paid to a dollar value equivalent for
the purposes of this section.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length processing contract or has no contract, including those
situations where the lessee performs processing for itself, the
processing allowance will be based upon the lessee's reasonable actual
costs as provided in this paragraph. All processing allowances deducted
under a non-arm's-length or no-contract situation are subject to
monitoring, review, audit, and adjustment. The lessee must claim a
processing allowance by reflecting it as a separate line entry on the
Form MMS-2014. When necessary or appropriate, MMS may direct a lessee to
modify its estimated or actual processing allowance.
(2) The processing allowance for non-arm's-length or no-contract
situations shall be based upon the lessee's actual costs for processing
during the reporting period, including operating and maintenance
expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph
(b)(2)(iv)(A) of this section, or a cost equal to the initial
depreciable investment in the processing plant multiplied by a rate of
return in accordance with paragraph (b)(2)(iv)(B) of this section.
Allowable capital costs are generally those costs for depreciable fixed
assets (including costs of delivery and installation of capital
equipment) which are an integral part of the processing plant.
(i) Allowable operating expenses include: Operations supervision and
engineering; operations labor; fuel; utilities; materials; ad valorem
property taxes; rent; supplies; and any other directly allocable and
attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the
processing plant; maintenance of equipment; maintenance labor; and other
directly allocable and attributable maintenance expenses which the
lessee can document.
(iii) Overhead directly attributable and allocable to the operation
and maintenance of the processing plant is an allowable expense. State
and Federal income taxes and severance taxes, including royalties, are
not allowable expenses.
(iv) A lessee may use either depreciation or a return on depreciable
capital investment. When a lessee has elected to use either method for a
processing plant, the lessee may not later elect to change to the other
alternative without approval of the MMS.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the processing plant services, or a unit-
of-production method. After an election is made, the lessee may not
change methods without MMS approval. A change in ownership of a
processing plant shall not alter the depreciation schedule established
by the original processor/lessee for purposes of the allowance
calculation. With or without a change in ownership, a processing plant
shall be depreciated only once. Equipment shall not be depreciated below
a reasonable salvage value.
(B) The MMS shall allow as a cost an amount equal to the allowable
initial capital investment in the processing plant multiplied by the
rate of return determined pursuant to paragraph (b)(2)(v) of this
section. No allowance shall be provided for depreciation. This
alternative shall apply only to plants first placed in service after
March 1, 1988.
(v) The rate of return must be the industrial rate associated with
Standard and Poor's BBB rating. The rate of return must be the monthly
average rate as published in Standard and Poor's Bond Guide for the
first month for which the allowance is applicable. The
[[Page 100]]
rate must be redetermined at the beginning of each subsequent calendar
year.
(3) The processing allowance for each gas plant product shall be
determined based on the lessee's reasonable and actual cost of
processing the gas. Allocation of costs to each gas plant product shall
be based upon generally accepted accounting principles. The lessee may
not take an allowance for the costs of processing lease production which
is not royalty bearing.
(4) A lessee may apply to MMS for an exception from the requirement
that it compute actual costs in accordance with paragraphs (b)(1)
through (b)(3) of this section. The MMS may grant the exception only if:
(i) The lessee has arm's-length contracts for processing other gas
production at the same processing plant; and (ii) at least 50 percent of
the gas processed annually at the plant is processed pursuant to arm's-
length processing contracts; if the MMS grants the exception, the lessee
shall use as its processing allowance the volume weighted average prices
charged other persons pursuant to arm's-length contracts for processing
at the same plant.
(c) Reporting requirements--(1) Arm's-length contracts. (i) The
lessee must notify MMS of an allowance based on incurred costs by using
a separate line entry on the Form MMS-2014.
(ii) The MMS may require that a lessee submit arm's-length
processing contracts and related documents. Documents shall be submitted
within a reasonable time, as determined by MMS.
(2) Non-arm's-length or no contract. (i) The lessee must notify MMS
of an allowance based on the incurred costs by using a separate line
entry on the Form MMS-2014.
(ii) For new processing plants, the lessee's initial deduction shall
include estimates of the allowable gas processing costs for the
applicable period. Cost estimates shall be based upon the most recently
available operations data for the plant or, if such data are not
available, the lessee shall use estimates based upon industry data for
similar gas processing plants.
(iii) Upon request by MMS, the lessee shall submit all data used to
prepare the allowance deduction. The data shall be provided within a
reasonable period of time, as determined by MMS.
(iv) If the lessee is authorized to use the volume weighted average
prices charged other persons as its processing allowance in accordance
with paragraph (b)(4) of this section, it shall follow the reporting
requirements of paragraph (c)(1) of this section.
(d) Interest and assessments. (1) If a lessee nets a processing
allowance against the royalty value on the Form MMS-2014, the lessee
shall be assessed an amount of up to 10 percent of the allowance netted
not to exceed $250 per lease selling arrangement per sales period.
(2) If a lessee deducts a processing allowance on its Form MMS-2014
that exceeds 66\2/3\ percent of the value of the gas processed without
obtaining prior approval of MMS under Sec. 206.158, the lessee shall
pay interest on the excess allowance amount taken from the date such
amount is taken to the date the lessee files an exception request with
MMS.
(3) If a lessee erroneously reports a processing allowance which
results in an underpayment of royalties, interest shall be paid on the
amount of that underpayment.
(4) Interest required to be paid by this section shall be determined
in accordance with 30 CFR 218.54.
(e) Adjustments. (1) If the actual processing allowance is less than
the amount the lessee has taken on Form MMS-2014 for each month during
the allowance reporting period, the lessee shall pay additional
royalties due plus interest computed under 30 CFR 218.54 from the
allowance reporting period when the lessee took the deduction to the
date the lessee repays the difference to MMS. If the actual processing
allowance is greater than the amount the lessee has taken on Form MMS-
2014 for each month during the allowance reporting period, the lessee
shall be entitled to a credit without interest.
(2) For lessees processing production from onshore Federal leases,
the lessee must submit a corrected Form MMS-2014 to reflect actual
costs, together with any payment, in accordance with instructions
provided by MMS.
[[Page 101]]
(3) For lessees processing gas production from leases on the OCS, if
the lessee's estimated processing allowance exceeds the allowance based
on actual costs, the lessee must submit a corrected Form MMS-2014 to
reflect actual costs, together with its payment, in accordance with
instructions provided by MMS. If the lessee's estimated costs were less
than the actual costs, the refund procedure will be specified by MMS.
(f) Other processing cost determinations. The provisions of this
section shall apply to determine processing costs when establishing
value using a net back valuation procedure or any other procedure that
requires deduction of processing costs.
[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45762, Nov. 14, 1988; 61
FR 5466, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999]
Sec. 206.160 Operating allowances.
Notwithstanding any other provisions in these regulations, an
operating allowance may be used for the purpose of computing payment
obligations when specified in the notice of sale and the lease. The
allowance amount or formula shall be specified in the notice of sale and
in the lease agreement.
[61 FR 3804, Feb. 2, 1996]
Subpart E_Indian Gas
Source: 64 FR 43515, Aug. 10, 1999, unless otherwise noted.
Sec. 206.170 What does this subpart contain?
This subpart contains royalty valuation provisions applicable to
Indian lessees.
(a) This subpart applies to all gas production from Indian (tribal
and allotted) oil and gas leases (except leases on the Osage Indian
Reservation). The purpose of this subpart is to establish the value of
production for royalty purposes consistent with the mineral leasing
laws, other applicable laws, and lease terms. This subpart does not
apply to Federal leases.
(b) If the specific provisions of any Federal statute, treaty,
negotiated agreement, settlement agreement resulting from any
administrative or judicial proceeding, or Indian oil and gas lease are
inconsistent with any regulation in this subpart, then the Federal
statute, treaty, negotiated agreement, settlement agreement, or lease
will govern to the extent of that inconsistency.
(c) You may calculate the value of production for royalty purposes
under methods other than those the regulations in this title require,
but only if you, the tribal lessor, and MMS jointly agree to the
valuation methodology. For leases on Indian allotted lands, you and MMS
must agree to the valuation methodology.
(d) All royalty payments you make to MMS are subject to monitoring,
review, audit, and adjustment.
(e) The regulations in this subpart are intended to ensure that the
trust responsibilities of the United States with respect to the
administration of Indian oil and gas leases are discharged in accordance
with the requirements of the governing mineral leasing laws, treaties,
and lease terms.
Sec. 206.171 What definitions apply to this subpart?
The following definitions apply to this subpart and to subpart J of
part 202 of this title:
Accounting for comparison means the same as dual accounting.
Active spot market means a market where one or more MMS-acceptable
publications publish bidweek prices (or if bidweek prices are not
available, first of the month prices) for at least one index-pricing
point in the index zone.
Allowance means a deduction in determining value for royalty
purposes. Processing allowance means an allowance for the reasonable,
actual costs of processing gas determined under this subpart.
Transportation allowance means an allowance for the reasonable, actual
cost of transportation determined under this subpart.
Approved Federal Agreement (AFA) means a unit or communitization
agreement approved under departmental regulations.
Area means a geographic region at least as large as the defined
limits of an oil or gas field, in which oil or gas lease products have
similar quality,
[[Page 102]]
economic, or legal characteristics. An area may be all lands within the
boundaries of an Indian reservation.
Arm's-length contract means a contract or agreement that has been
arrived at in the marketplace between independent, nonaffiliated persons
with opposing economic interests regarding that contract. For purposes
of this subpart, two persons are affiliated if one person controls, is
controlled by, or is under common control with another person. The
following percentages (based on the instruments of ownership of the
voting securities of an entity, or based on other forms of ownership)
determine if persons are affiliated:
(1) Ownership in excess of 50 percent constitutes control.
(2) Ownership of 10 through 50 percent creates a presumption of
control.
(3) Ownership of less than 10 percent creates a presumption of
noncontrol which MMS may rebut if it demonstrates actual or legal
control, including the existence of interlocking directorates.
Notwithstanding any other provisions of this subpart, contracts between
relatives, either by blood or by marriage, are not arm's-length
contracts. MMS may require the lessee to certify the percentage of
ownership or control of the entity. To be considered arm's-length for
any production month, a contract must meet the requirements of this
definition for that production month as well as when the contract was
executed.
Audit means a review, conducted under generally accepted accounting
and auditing standards, of royalty payment compliance activities of
lessees or other persons who pay royalties, rents, or bonuses on Indian
leases.
BIA means the Bureau of Indian Affairs of the Department of the
Interior.
BLM means the Bureau of Land Management of the Department of the
Interior.
Compression means raising the pressure of gas.
Condensate means liquid hydrocarbons (normally exceeding 40 degrees
of API gravity) recovered at the surface without resorting to
processing. Condensate is the mixture of liquid hydrocarbons that
results from condensation of petroleum hydrocarbons existing initially
in a gaseous phase in an underground reservoir.
Contract means any oral or written agreement, including amendments
or revisions thereto, between two or more persons and enforceable by law
that with due consideration creates an obligation.
Dedicated means a contractual commitment to deliver gas production
(or a specified portion of production) from a lease or well when that
production is specified in a sales contract and that production must be
sold pursuant to that contract to the extent that production occurs from
that lease or well.
Drip condensate means any condensate recovered downstream of the
facility measurement point without resorting to processing. Drip
condensate includes condensate recovered as a result of its becoming a
liquid during the transportation of the gas removed from the lease or
recovered at the inlet of a gas processing plant by mechanical means,
often referred to as scrubber condensate.
Dual Accounting (or accounting for comparison) refers to the
requirement to pay royalty based on a value which is the higher of the
value of gas prior to processing less any applicable allowances as
compared to the combined value of drip condensate, residue gas, and gas
plant products after processing, less applicable allowances.
Entitlement (or entitled share) means the gas production from a
lease, or allocable to lease acreage under the terms of an AFA,
multiplied by the operating rights owner's percentage of interest
ownership in the lease or the acreage.
Facility measurement point (or point of royalty settlement) means
the point where the BLM-approved measurement device is located for
determining the volume of gas removed from the lease. The facility
measurement point may be on the lease or off-lease with BLM approval.
Field means a geographic region situated over one or more subsurface
oil and gas reservoirs encompassing at least the outermost boundaries of
all oil and gas accumulations known to be within those reservoirs
vertically projected to the land surface. Onshore fields are usually
given names and
[[Page 103]]
their official boundaries are often designated by oil and gas regulatory
agencies in the respective States in which the fields are located.
Gas means any fluid, either combustible or noncombustible,
hydrocarbon or nonhydrocarbon, which is extracted from a reservoir and
which has neither independent shape nor volume, but tends to expand
indefinitely. It is a substance that exists in a gaseous or rarefied
state under standard temperature and pressure conditions.
Gas plant products means separate marketable elements, compounds, or
mixtures, whether in liquid, gaseous, or solid form, resulting from
processing gas. However, it does not include residue gas.
Gathering means the movement of lease production to a central
accumulation or treatment point on the lease, unit, or communitized
area; or a central accumulation or treatment point off the lease, unit,
or communitized area as approved by BLM operations personnel.
Gross proceeds (for royalty payment purposes) means the total monies
and other consideration accruing to an oil and gas lessee for the
disposition of unprocessed gas, residue gas, and gas plant products
produced. Gross proceeds includes, but is not limited to, payments to
the lessee for certain services such as compression, dehydration,
measurement, or field gathering to the extent that the lessee is
obligated to perform them at no cost to the Indian lessor, and payments
for gas processing rights. Gross proceeds, as applied to gas, also
includes but is not limited to reimbursements for severance taxes and
other reimbursements. Tax reimbursements are part of the gross proceeds
accruing to a lessee even though the Indian royalty interest is exempt
from taxation. Monies and other consideration, including the forms of
consideration identified in this paragraph, to which a lessee is
contractually or legally entitled but which it does not seek to collect
through reasonable efforts are also part of gross proceeds.
Index means the calculated composite price ($/MMBtu) of spot-market
sales published by a publication that meets MMS-established criteria for
acceptability at the index-pricing point.
Index-pricing point (IPP) means any point on a pipeline for which
there is an index.
Index zone means a field or an area with an active spot market and
published indices applicable to that field or area that are acceptable
to MMS under Sec. 206.172(d)(2).
Indian allottee means any Indian for whom land or an interest in
land is held in trust by the United States or who holds title subject to
Federal restriction against alienation.
Indian tribe means any Indian tribe, band, nation, pueblo,
community, rancheria, colony, or other group of Indians for which any
land or interest in land is held in trust by the United States or which
is subject to Federal restriction against alienation.
Lease means any contract, profit-share arrangement, joint venture,
or other agreement issued or approved by the United States under a
mineral leasing law that authorizes exploration for, development or
extraction of, or removal of lease products--or the land area covered by
that authorization, whichever is required by the context. For purposes
of this subpart, this definition excludes Federal leases.
Lease products means any leased minerals attributable to,
originating from, or allocated to a lease.
Lessee means any person to whom the United States, a tribe, and/or
individual Indian landowner issues a lease, and any person who has been
assigned an obligation to make royalty or other payments required by the
lease. This includes any person who has an interest in a lease
(including operating rights owners) as well as an operator or payor who
has no interest in the lease but who has assumed the royalty payment
responsibility.
Like-quality lease products means lease products which have similar
chemical, physical, and legal characteristics.
Marketable condition means a condition in which lease products are
sufficiently free from impurities and otherwise so conditioned that a
purchaser will accept them under a sales contract typical for the field
or area.
MMS means the Minerals Management Service, Department of the
Interior. MMS includes, where appropriate,
[[Page 104]]
tribal auditors acting under agreements under the Federal Oil and Gas
Royalty Management Act of 1982, 30 U.S.C. 1701 et seq. or other
applicable agreements.
Minimum royalty means that minimum amount of annual royalty that the
lessee must pay as specified in the lease or in applicable leasing
regulations.
Natural gas liquids (NGL's) means those gas plant products
consisting of ethane, propane, butane, or heavier liquid hydrocarbons.
Net-back method (or work-back method) means a method for calculating
market value of gas at the lease under which costs of transportation,
processing, and manufacturing are deducted from the proceeds received
for, or the value of, the gas, residue gas, or gas plant products, and
any extracted, processed, or manufactured products, at the first point
at which reasonable values for any such products may be determined by a
sale under an arm's-length contract or comparison to other sales of such
products.
Net output means the quantity of residue gas and each gas plant
product that a processing plant produces.
Net profit share means the specified share of the net profit from
production of oil and gas as provided in the agreement.
Operating rights owner (or working interest owner) means any person
who owns operating rights in a lease subject to this subpart. A record
title owner is the owner of operating rights under a lease except to the
extent that the operating rights or a portion thereof have been
transferred from record title (see BLM regulations at 43 CFR 3100.0-
5(d)).
Person means any individual, firm, corporation, association,
partnership, consortium, or joint venture (when established as a
separate entity).
Point of royalty measurement means the same as facility measurement
point.
Processing means any process designed to remove elements or
compounds (hydrocarbon and nonhydrocarbon) from gas, including
absorption, adsorption, or refrigeration. Field processes which normally
take place on or near the lease, such as natural pressure reduction,
mechanical separation, heating, cooling, dehydration, desulphurization
(or ``sweetening''), and compression, are not considered processing. The
changing of pressures and/or temperatures in a reservoir is not
considered processing.
Residue gas means that hydrocarbon gas consisting principally of
methane resulting from processing gas.
Selling arrangement means the individual contractual arrangements
under which sales or dispositions of gas, residue gas and gas plant
products are made. Selling arrangements are described by illustration in
the ``MMS Royalty Management Program Oil and Gas Payor Handbook.''
Spot sales agreement means a contract wherein a seller agrees to
sell to a buyer a specified amount of unprocessed gas, residue gas, or
gas plant products at a specified price over a fixed period, usually of
short duration. It also does not normally require a cancellation notice
to terminate, and does not contain an obligation, or imply an intent, to
continue in subsequent periods.
Takes means when the operating rights owner sells or removes
production from, or allocated to, the lease, or when such sale or
removal occurs for the benefit of an operating rights owner.
Work-back method means the same as net-back method.
Sec. 206.172 How do I value gas produced from leases in an index zone?
(a) What leases this section applies to. This section explains how
lessees must value, for royalty purposes, gas produced from Indian
leases located in an index zone. For other leases, value must be
determined under Sec. 206.174.
(1) You must use the valuation provision of this section if your
lease is in an index zone and meets one of the following two
requirements:
(i) Has a major portion provision;
(ii) Does not have a major portion provision, but provides for the
Secretary to determine the value of production.
(2) This section does not apply to carbon dioxide, nitrogen, or
other non-hydrocarbon components of the gas stream. However, if they are
recovered and sold separately from the gas
[[Page 105]]
stream, you must determine the value of these products under Sec.
206.174.
(b) Valuing residue gas and gas before processing. (1) Except as
provided in paragraphs (e), (f), and (g) of this section, this paragraph
(b) explains how you must value the following four types of gas:
(i) Gas production before processing;
(ii) Gas production that you certify on Form MMS-4410, Certification
for Not Performing Accounting for Comparison (Dual Accounting), is not
processed before it flows into a pipeline with an index but which may be
processed later;
(iii) Residue gas after processing; and
(iv) Gas that is never processed.
(2) The value of gas production that is not sold under an arm's-
length dedicated contract is the index-based value determined under
paragraph (d) of this section unless the gas was subject to a previous
contract which was part of a gas contract settlement. If the previous
contract was subject to a gas contract settlement and if the royalty-
bearing contract settlement proceeds per MMBtu added to the 80 percent
of the safety net prices calculated at Sec. 206.172(e)(4)(i) exceeds
the index-based value that applies to the gas under this section
(including any adjustments required under Sec. 206.176), then the value
of the gas is the higher of the value determined under this section
(including any adjustments required under Sec. 206.176) or Sec.
206.174.
(3) The value of gas production that is sold under an arm's-length
dedicated contract is the higher of the index-based value under
paragraph (d) of this section or the value of that production determined
under Sec. 206.174(b).
(c) Valuing gas that is processed before it flows into a pipeline
with an index. Except as provided in paragraphs (e), (f), and (g) of
this section, this paragraph (c) explains how you must value gas that is
processed before it flows into a pipeline with an index. You must value
this gas production based on the higher of the following two values:
(1) The value of the gas before processing determined under
paragraph (b) of this section.
(2) The value of the gas after processing, which is either the
alternative dual accounting value under Sec. 206.173 or the sum of the
following three values:
(i) The value of the residue gas determined under paragraph (b)(2)
or (3) of this section, as applicable;
(ii) The value of the gas plant products determined under Sec.
206.174, less any applicable processing and/or transportation allowances
determined under this subpart; and
(iii) The value of any drip condensate associated with the processed
gas determined under subpart B of this part.
(d) Determining the index-based value for gas production. (1) To
determine the index-based value per MMBtu for production from a lease in
an index zone, you must use the following procedures:
(i) For each MMS-approved publication, calculate the average of the
highest reported prices for all index-pricing points in the index zone,
except for any prices excluded under paragraph (d)(6) of this section;
(ii) Sum the averages calculated in paragraph (d)(1)(i) of this
section and divide by the number of publications; and
(iii) Reduce the number calculated under paragraph (d)(1)(ii) of
this section by 10 percent, but not by less than 10 cents per MMBtu or
more than 30 cents per MMBtu. The result is the index-based value per
MMBtu for production from all leases in that index zone.
(2) MMS will publish in the Federal Register the index zones that
are eligible for the index-based valuation method under this paragraph.
MMS will monitor the market activity in the index zones and, if
necessary, hold a technical conference to add or modify a particular
index zone. Any change to the index zones will be published in the
Federal Register. MMS will consider the following five factors and
conditions in determining eligible index zones:
(i) Areas for which MMS-approved publications establish index prices
that accurately reflect the value of production in the field or area
where the production occurs;
(ii) Common markets served;
(iii) Common pipeline systems;
(iv) Simplification; and
[[Page 106]]
(v) Easy identification in MMS's systems, such as counties or Indian
reservations.
(3) If market conditions change so that an index-based method for
determining value is no longer appropriate for an index zone, MMS will
hold a technical conference to consider disqualification of an index
zone. MMS will publish notice in the Federal Register if an index zone
is disqualified. If an index zone is disqualified, then production from
leases in that index zone cannot be valued under this paragraph.
(4) MMS periodically will publish in the Federal Register a list of
acceptable publications based on certain criteria, including, but not
limited to the following five criteria:
(i) Publications buyers and sellers frequently use;
(ii) Publications frequently referenced in purchase or sales
contracts;
(iii) Publications that use adequate survey techniques, including
the gathering of information from a substantial number of sales;
(iv) Publications that publish the range of reported prices they use
to calculate their index; and
(v) Publications independent from DOI, lessors, and lessees.
(5) Any publication may petition MMS to be added to the list of
acceptable publications.
(6) MMS may exclude an individual index price for an index zone in
an MMS-approved publication if MMS determines that the index price does
not accurately reflect the value of production in that index zone. MMS
will publish a list of excluded indices in the Federal Register.
(7) MMS will reference which tables in the publications you must use
for determining the associated index prices.
(8) The index-based values determined under this paragraph are not
subject to deductions for transportation or processing allowances
determined under Sec. Sec. 206.177, 206.178, 206.179, and 206.180.
(e) Determining the minimum value for royalty purposes of gas sold
beyond the first index pricing point. (1) Notwithstanding any other
provision of this section, the value for royalty purposes of gas
production from an Indian lease that is sold beyond the first index
pricing point through which it flows cannot be less than the value
determined under this paragraph (e).
(2) By June 30 following any calendar year, you must calculate for
each month of that calendar year your safety net price per MMBtu using
the procedures in paragraph (e)(3) of this section. You must calculate a
safety net price for each month and for each index zone where you have
an Indian lease for which you report and pay royalties.
(3) Your safety net price (S) for an index zone is the volume-
weighted average contract price per delivered MMBtu under your or your
affiliate's arm's-length contracts for the disposition of residue gas or
unprocessed gas produced from your Indian leases in that index zone as
computed under this paragraph (e)(3).
(i) Include in your calculation only sales under those contracts
that establish a delivery point beyond the first index pricing point
through which the gas flows, and that include any gas produced from or
allocable to one or more of your Indian leases in that index zone, even
if the contract also includes gas produced from Federal, State, or fee
properties. Include in your volume-weighted average calculation those
volumes that are allocable to your Indian leases in that index zone.
(ii) Do not reduce the contract price for any transportation costs
incurred to deliver the gas to the purchaser.
(iii) For purposes of this paragraph (e), the contract price will
not include the following amounts:
(A) Any amounts you receive in compromise or settlement of a
predecessor contract for that gas;
(B) Deductions for you or any other person to put gas production
into marketable condition or to market the gas; and
(C) Any amounts related to marketable securities associated with the
sales contract.
(4) Next, you must determine for each month the safety net
differential (SND). You must perform this calculation separately for
each index zone.
(i) For each index zone, the safety net differential is equal to:
SND = [(0.80 x S) - (1.25 x I)] where (I) is the index-
[[Page 107]]
based value determined under 30 CFR 206.172(d).
(ii) If the safety net differential is positive you owe additional
royalties.
(5)(i) To calculate the additional royalties you owe, make the
following calculation for each of your Indian leases in that index zone
that produced gas that was sold beyond the first index-pricing point
through which the gas flowed and that was used in the calculation in
paragraph (e)(3) of this section:
Lease royalties owed = SND x V x R, where R = the lease royalty rate
and V = the volume allocable to the lease which produced gas that was
sold beyond the first index pricing point.
(ii) If gas produced from any of your Indian leases is commingled or
pooled with gas produced from non-Indian properties, and if any of the
combined gas is sold at a delivery point beyond the first index pricing
point through which the gas flows, then the volume allocable to each
Indian lease for which gas was sold beyond the first index pricing point
in the calculation under paragraph (e)(5)(i) of this section is the
volume produced from the lease multiplied by the proportion that the
total volume of gas sold beyond the first index pricing point bears to
the total volume of gas commingled or pooled from all properties.
(iii) Add the numbers calculated for each lease under paragraph
(e)(5)(i) of this section. The total is the additional royalty you owe.
(6) You have the following responsibilities to comply with the
minimum value for royalty purposes:
(i) You must report the safety net price for each index zone to MMS
on Form MMS-4411, Safety Net Report, no later than June 30 following
each calendar year;
(ii) You must pay and report on Form MMS-2014 additional royalties
due no later than June 30 following each calendar year; and
(iii) MMS may order you to amend your safety net price within one
year from the date your Form MMS-4411 is due or is filed, whichever is
later. If MMS does not order any amendments within that one-year period,
your safety net price calculation is final.
(f) Excluding some or all tribal leases from valuation under this
section. (1) An Indian tribe may ask MMS to exclude some or all of its
leases from valuation under this section. MMS will consult with BIA
regarding the request.
(i) If MMS approves the request for your lease, you must value your
production under Sec. 206.174 beginning with production on the first
day of the second month following the date MMS publishes notice of its
decision in the Federal Register.
(ii) If an Indian tribe requests exclusion from an index zone for
less than all of its leases, MMS will approve the request only if the
excluded leases may be segregated into one or more groups based on
separate fields within the reservation.
(2) An Indian tribe may ask MMS to terminate exclusion of its leases
from valuation under this section. MMS will consult with BIA regarding
the request.
(i) If MMS approves the request, you must value your production
under Sec. 206.172 beginning with production on the first day of the
second month following the date MMS publishes notice of its decision in
the Federal Register.
(ii) Termination of an exclusion under paragraph (f)(2)(i) of this
section cannot take effect earlier than 1 year after the first day of
the production month that the exclusion was effective.
(3) The Indian tribe's request to MMS under either paragraph (f)(1)
or (2) of this section must be in the form of a tribal resolution.
(g) Excluding Indian allotted leases from valuation under this
section. (1)(i) MMS may exclude any Indian allotted leases from
valuation under this section. MMS will consult with BIA regarding the
exclusion.
(ii) If MMS excludes your lease, you must value your production
under Sec. 206.174 beginning with production on the first day of the
second month following the date MMS publishes notice of its decision in
the Federal Register.
(iii) If MMS excludes any Indian allotted leases under this
paragraph (g)(1), it will exclude all Indian allotted leases in the same
field.
[[Page 108]]
(2)(i) MMS may terminate the exclusion of any Indian allotted leases
from valuation under this section. MMS will consult with BIA regarding
the termination.
(ii) If MMS terminates the exclusion, you must value your production
under Sec. 206.172 beginning with production on the first day of the
second month following the date MMS publishes notice of its decision in
the Federal Register.
Sec. 206.173 How do I calculate the alternative methodology for dual
accounting?
(a) Electing a dual accounting method. (1) If you are required to
perform the accounting for comparison (dual accounting) under Sec.
206.176, you have two choices. You may elect to perform the dual
accounting calculation according to either Sec. 206.176(a) (called
actual dual accounting), or paragraph (b) of this section (called the
alternative methodology for dual accounting).
(2) You must make a separate election to use the alternative
methodology for dual accounting for your Indian leases in each MMS-
designated area. Your election for a designated area must apply to all
of your Indian leases in that area.
(i) MMS will publish in the Federal Register a list of the lease
prefixes that will be associated with each designated area for purposes
of this section. The MMS-designated areas are as follows:
(A) Alabama-Coushatta;
(B) Blackfeet Reservation;
(C) Crow Reservation;
(D) Fort Belknap Reservation;
(E) Fort Berthold Reservation;
(F) Fort Peck Reservation;
(G) Jicarilla Apache Reservation;
(H) MMS-designated groups of counties in the State of Oklahoma;
(I) Navajo Reservation;
(J) Northern Cheyenne Reservation;
(K) Rocky Boys Reservation;
(L) Southern Ute Reservation;
(M) Turtle Mountain Reservation;
(N) Ute Mountain Ute Reservation;
(O) Uintah and Ouray Reservation;
(P) Wind River Reservation; and
(Q) Any other area that MMS designates. MMS will publish a new area
designation in the Federal Register.
(ii) You may elect to begin using the alternative methodology for
dual accounting at the beginning of any month. The first election to use
the alternative methodology will be effective from the time of election
through the end of the following calendar year. Thereafter, each
election to use the alternative methodology must remain in effect for 2
calendar years. You may return to the actual dual accounting method only
at the beginning of the next election period or with the written
approval of MMS and the tribal lessor for tribal leases, and MMS for
Indian allottee leases in the designated area.
(iii) When you elect to use the alternative methodology for a
designated area, you must also use the alternative methodology for any
new wells commenced and any new leases acquired in the designated area
during the term of the election.
(b) Calculating value using the alternative methodology for dual
accounting. (1) The alternative methodology adjusts the value of gas
before processing determined under either Sec. 206.172 or Sec. 206.174
to provide the value of the gas after processing. You must use the value
of the gas after processing for royalty payment purposes. The amount of
the increase depends on your relationship with the owner(s) of the plant
where the gas is processed. If you have no direct or indirect ownership
interest in the processing plant, then the increase is lower, as
provided in the table in paragraph (b)(2)(ii) of this section. If you
have a direct or indirect ownership interest in the plant where the gas
is processed, the increase is higher, as provided in paragraph
(b)(2)(ii) of this section.
(2) To calculate the value of the gas after processing using the
alternative methodology for dual accounting, you must apply the increase
to the value before processing, determined in either Sec. 206.172 or
Sec. 206.174, as follows:
(i) Value of gas after processing = (value determined under either
Sec. 206.172 or Sec. 206.174, as applicable) x (1 + increment for dual
accounting); and
(ii) In this equation, the increment for dual accounting is the
number you
[[Page 109]]
take from the applicable Btu range, determined under paragraph (b)(3) of
this section, in the following table:
------------------------------------------------------------------------
Increment Increment
if Lessee if lessee
has no has an
BTU range ownership ownership
interest in interest in
plant plant
------------------------------------------------------------------------
1001 to 1050.................................. .0275 .0375
1051 to 1100.................................. .0400 .0625
1101 to 1150.................................. .0425 .0750
1151 to 1200.................................. .0700 .1225
1201 to 1250.................................. .0975 .1700
1251 to 1300.................................. .1175 .2050
1301 to 1350.................................. .1400 .2400
1351 to 1400.................................. .1450 .2500
1401 to 1450.................................. .1500 .2600
1451 to 1500.................................. .1550 .2700
1501 to 1550.................................. .1600 .2800
1551 to 1600.................................. .1650 .2900
1601 to 1650.................................. .1850 .3225
1651 to 1700.................................. .1950 .3425
1701+......................................... .2000 .3550
------------------------------------------------------------------------
(3) The applicable Btu for purposes of this section is the volume
weighted-average Btu for the lease computed from measurements at the
facility measurement point(s) for gas production from the lease.
(4) If any of your gas from the lease is processed during a month,
use the following two paragraphs to determine which amounts are subject
to dual accounting and which dual accounting method you must use.
(i) Weighted-average Btu content determined under paragraph (b)(3)
of this section is greater than 1,000 Btu's per cubic foot (Btu/cf). All
gas production from the lease is subject to dual accounting and you must
use the alternative method for all that gas production if you elected to
use the alternative method under this section.
(ii) Weighted-average Btu content determined under paragraph (b)(3)
of this section is less than or equal to 1,000 Btu/cf. Only the volumes
of lease production measured at facility measurement points whose
quality exceeds 1,000 Btu/cf are subject to dual accounting, and you may
use the alternative methodology for these volumes. For gas measured at
facility measurement points for these leases where the quality is equal
to or less than 1,000 Btu/cf, you are not required to do dual
accounting.
Sec. 206.174 How do I value gas production when an index-based method cannot
be used?
(a) Situations in which an index-based method cannot be used. (1)
Gas production must be valued under this section in the following
situations.
(i) Your lease is not in an index zone (or MMS has excluded your
lease from an index zone).
(ii) If your lease is in an index zone and you sell your gas under
an arm's-length dedicated contract, then the value of your gas is the
higher of the value received under the dedicated contract determined
under Sec. 206.174(b) or the value under Sec. 206.172.
(iii) Also use this section to value any other gas production that
cannot be valued under Sec. 206.172, as well as gas plant products, and
to value components of the gas stream that have no Btu value (for
example, carbon dioxide, nitrogen, etc.).
(2) The value for royalty purposes of gas production subject to this
subpart is the value of gas determined under this section less
applicable allowances determined under this subpart.
(3) You must determine the value of gas production that is processed
and is subject to accounting for comparison using the procedure in Sec.
206.176.
(4) This paragraph applies if your lease has a major portion
provision. It also applies if your lease does not have a major portion
provision but the lease provides for the Secretary to determine value.
(i) The value of production you must initially report and pay is the
value determined in accordance with the other paragraphs of this
section.
(ii) MMS will determine the major portion value and notify you in
the Federal Register of that value. The value of production for royalty
purposes for your lease is the higher of either the value determined
under this section which you initially used to report and pay royalties,
or the major portion value calculated under this paragraph (a)(4). If
the major portion value is higher, you must submit an amended Form MMS-
2014 to MMS by the due date specified in the written notice from MMS of
the major portion value. Late-payment interest under 30 CFR 218.54 on
any underpayment will
[[Page 110]]
not begin to accrue until the date the amended Form MMS-2014 is due to
MMS.
(iii) Except as provided in paragraph (a)(4)(iv) of this section,
MMS will calculate the major portion value for each designated area
(which are the same designated areas as under Sec. 206.173) using
values reported for unprocessed gas and residue gas on Form MMS-2014 for
gas produced from leases on that Indian reservation or other designated
area. MMS will array the reported prices from highest to lowest price.
The major portion value is that price at which 25 percent (by volume) of
the gas (starting from the highest) is sold. MMS cannot unilaterally
change the major portion value after you are notified in writing of what
that value is for your leases.
(iv) MMS may calculate the major portion value using different data
than the data described in paragraph (a)(4)(iii) of this section or data
to augment the data described in paragraph (a)(4)(iii) of this section.
This may include price data reported to the State tax authority or price
data from leases MMS has reviewed in the designated area. MMS may use
this alternate or the augmented data source beginning with production on
the first day of the month following the date MMS publishes notice in
the Federal Register that it is calculating the major portion using a
method in this paragraph (a)(4)(iv) of this section.
(b) Arm's-length contracts. (1) The value of gas, residue gas, or
any gas plant product you sell under an arm's-length contract is the
gross proceeds accruing to you or your affiliate, except as provided in
paragraphs (b)(1)(ii)-(iv) of this section.
(i) You have the burden of demonstrating that your contract is
arm's-length.
(ii) In conducting reviews and audits for gas valued based upon
gross proceeds under this paragraph, MMS will examine whether or not
your contract reflects the total consideration actually transferred
either directly or indirectly from the buyer to you or your affiliate
for the gas, residue gas, or gas plant product. If the contract does not
reflect the total consideration, then MMS may require that the gas,
residue gas, or gas plant product sold under that contract be valued in
accordance with paragraph (c) of this section. Value may not be less
than the gross proceeds accruing to you or your affiliate, including the
additional consideration.
(iii) If MMS determines for gas valued under this paragraph that the
gross proceeds accruing to you or your affiliate under an arm's-length
contract do not reflect the value of the gas, residue gas, or gas plant
products because of misconduct by or between the contracting parties, or
because you otherwise have breached your duty to the lessor to market
the production for the mutual benefit of you and the lessor, then MMS
will require that the gas, residue gas, or gas plant product be valued
under paragraphs (c)(2) or (3) of this section. In these circumstances,
MMS will notify you and give you an opportunity to provide written
information justifying your value.
(iv) This paragraph applies to situations where a pipeline purchases
gas from a lessee according to a cash-out program under a transportation
contract. For all over-delivered volumes, the royalty value is the price
the pipeline is required to pay for volumes within the tolerances for
over-delivery specified in the transportation contract. Use the same
value for volumes that exceed the over-delivery tolerances even if those
volumes are subject to a lower price specified in the transportation
contract. However, if MMS determines that the price specified in the
transportation contract for over-delivered volumes is unreasonably low,
the lessees must value all over-delivered volumes under paragraph (c)(2)
or (3) of this section.
(2) MMS may require you to certify that your arm's-length contract
provisions include all of the consideration the buyer pays, either
directly or indirectly, for the gas, residue gas, or gas plant product.
(c) Non-arm's-length contracts. If your gas, residue gas, or any gas
plant product is not sold under an arm's-length contract, then you must
value the production using the first applicable method of the following
three methods:
[[Page 111]]
(1) The gross proceeds accruing to you under your non-arm's-length
contract sale (or other disposition other than by an arm's-length
contract), provided that those gross proceeds are equivalent to the
gross proceeds derived from, or paid under, comparable arm's-length
contracts for purchases, sales, or other dispositions of like-quality
gas in the same field (or, if necessary to obtain a reasonable sample,
from the same area). For residue gas or gas plant products, the
comparable arm's-length contracts must be for gas from the same
processing plant (or, if necessary to obtain a reasonable sample, from
nearby plants). In evaluating the comparability of arm's-length
contracts for the purposes of these regulations, the following factors
will be considered: price, time of execution, duration, market or
markets served, terms, quality of gas, residue gas, or gas plant
products, volume, and such other factors as may be appropriate to
reflect the value of the gas, residue gas, or gas plant products.
(2) A value determined by consideration of other information
relevant in valuing like-quality gas, residue gas, or gas plant
products, including gross proceeds under arm's-length contracts for
like-quality gas in the same field or nearby fields or areas, or for
residue gas or gas plant products from the same gas plant or other
nearby processing plants. Other factors to consider include prices
received in spot sales of gas, residue gas or gas plant products, other
reliable public sources of price or market information, and other
information as to the particular lease operation or the salability of
such gas, residue gas, or gas plant products.
(3) A net-back method or any other reasonable method to determine
value.
(d) Supporting data. If you determine the value of production under
paragraph (c) of this section, you must retain all data relevant to the
determination of royalty value.
(1) Such data will be subject to review and audit, and MMS will
direct you to use a different value if we determine upon review or audit
that the value you reported is inconsistent with the requirements of
these regulations.
(2) You must make all such data available upon request to the
authorized MMS or Indian representatives, to the Office of the Inspector
General of the Department, or other authorized persons. This includes
your arm's-length sales and volume data for like-quality gas, residue
gas, and gas plant products that are sold, purchased, or otherwise
obtained from the same processing plant or from nearby processing
plants, or from the same or nearby field or area.
(e) Improper values. If MMS determines that you have not properly
determined value, you must pay the difference, if any, between royalty
payments made based upon the value you used and the royalty payments
that are due based upon the value MMS established. You also must pay
interest computed on that difference under 30 CFR 218.54. If you are
entitled to a credit, MMS will provide instructions on how to take that
credit.
(f) Value guidance. You may ask MMS for guidance in determining
value. You may propose a valuation method to MMS. Submit all available
data related to your proposal and any additional information MMS deems
necessary. MMS will promptly review your proposal and provide you with a
non-binding determination of the guidance you request.
(g) Minimum value of production. (1) For gas, residue gas, and gas
plant products valued under this section, under no circumstances may the
value of production for royalty purposes be less than the gross proceeds
accruing to the lessee (including its affiliates) for gas, residue gas
and/or any gas plant products, less applicable transportation allowances
and processing allowances determined under this subpart.
(2) For gas plant products valued under this section and not valued
under Sec. 206.173, the alternative methodology for dual accounting,
the minimum value of production for each gas plant product is as
follows:
(i) Leases in certain States and areas have specific minimum values.
(A) For production from leases in Colorado in the San Juan Basin,
New Mexico, and Texas, the monthly average minimum price reported in
commercial price bulletins for the gas plant product at Mont Belvieu,
Texas, minus 8.0 cents per gallon.
[[Page 112]]
(B) For production in Arizona, in Colorado outside the San Juan
Basin, Minnesota, Montana, North Dakota, Oklahoma, South Dakota, Utah,
and Wyoming, the monthly average minimum price reported in commercial
price bulletins for the gas plant product at Conway, Kansas, minus 7.0
cents per gallon;
(ii) You may use any commercial price bulletin, but you must use the
same bulletin for all of the calendar year. If the commercial price
bulletin you are using stops publication, you may use a different
commercial price bulletin for the remaining part of the calendar year;
and (iii) If you use a commercial price bulletin that is published
monthly, the monthly average minimum price is the bulletin's minimum
price. If you use a commercial price bulletin that is published weekly,
the monthly average minimum price is the arithmetic average of the
bulletin's weekly minimum prices. If you use a commercial price bulletin
that is published daily, the monthly average minimum price is the
arithmetic average of the bulletin's minimum prices for each Wednesday
in the month.
(h) Marketable condition/Marketing. You are required to place gas,
residue gas, and gas plant products in marketable condition and market
the gas for the mutual benefit of the lessee and the lessor at no cost
to the Indian lessor. When your gross proceeds establish the value under
this section, that value must be increased to the extent that the gross
proceeds have been reduced because the purchaser, or any other person,
is providing certain services to place the gas, residue gas, or gas
plant products in marketable condition or to market the gas, the cost of
which ordinarily is your responsibility.
(i) Highest obtainable price or benefit. For gas, residue gas, and
gas plant products valued under this section, value must be based on the
highest price a prudent lessee can receive through legally enforceable
claims under its contract. Absent contract revision or amendment, if you
fail to take proper or timely action to receive prices or benefits to
which you are entitled, you must pay royalty at a value based upon that
obtainable price or benefit. Contract revisions or amendments must be in
writing and signed by all parties to an arm's-length contract. If you
make timely application for a price increase or benefit allowed under
your contract but the purchaser refuses, and you take reasonable
measures, which are documented, to force purchaser compliance, you will
owe no additional royalties unless or until monies or consideration
resulting from the price increase or additional benefits are received.
This paragraph is not intended to permit you to avoid your royalty
payment obligation in situations where your purchaser fails to pay, in
whole or in part, or timely, for a quantity of gas, residue gas, or gas
plant product.
(j) Non-binding MMS reviews. Notwithstanding any provision in these
regulations to the contrary, no review, reconciliation, monitoring, or
other like process that results in an MMS redetermination of value under
this section will be considered final or binding against the Federal
Government or its beneficiaries until the audit period is formally
closed.
(k) Confidential information. Certain information submitted to MMS
to support valuation proposals, including transportation allowances and
processing allowances, may be exempted from disclosure under the Freedom
of Information Act, 5 U.S.C. 552, or other Federal law. Any data
specified by law to be privileged, confidential, or otherwise exempt,
will be maintained in a confidential manner in accordance with
applicable laws and regulations. All requests for information about
determinations made under this subpart must be submitted in accordance
with the Freedom of Information Act regulation of the Department of the
Interior, 43 CFR part 2.
[64 FR 43515, Aug. 10, 1999, as amended at 65 FR 62614, Oct. 19, 2000]
Sec. 206.175 How do I determine quantities and qualities of production for
computing royalties?
(a) For unprocessed gas, you must pay royalties on the quantity and
quality at the facility measurement point BLM either allowed or
approved.
(b) For residue gas and gas plant products, you must pay royalties
on your share of the monthly net output
[[Page 113]]
of the plant even though residue gas and/or gas plant products may be in
temporary storage.
(c) If you have no ownership interest in the processing plant and
you do not operate the plant, you may use the contract volume allocation
to determine your share of plant products.
(d) If you have an ownership interest in the plant or if you operate
it, use the following procedure to determine the quantity of the residue
gas and gas plant products attributable to you for royalty payment
purposes:
(1) When the net output of the processing plant is derived from gas
obtained from only one lease, the quantity of the residue gas and gas
plant products on which you must pay royalty is the net output of the
plant.
(2) When the net output of a processing plant is derived from gas
obtained from more than one lease producing gas of uniform content, the
quantity of the residue gas and gas plant products allocable to each
lease must be in the same proportions as the ratios obtained by dividing
the amount of gas delivered to the plant from each lease by the total
amount of gas delivered from all leases.
(3) When the net output of a processing plant is derived from gas
obtained from more than one lease producing gas of non-uniform content,
the volumes of residue gas and gas plant products allocable to each
lease are based on theoretical volumes of residue gas and gas plant
products measured in the lease gas stream. You must calculate the
portion of net plant output of residue gas and gas plant products
attributable to each lease as follows:
(i) First, compute the theoretical volumes of residue gas and of gas
plant products attributable to the lease by multiplying the lease volume
of the gas stream by the tested residue gas content (mole percentage) or
gas plant product (GPM) content of the gas stream;
(ii) Second, calculate the theoretical volumes of residue gas and of
gas plant products delivered from all leases by summing the theoretical
volumes of residue gas and of gas plant products delivered from each
lease; and
(iii) Third, calculate the theoretical quantities of net plant
output of residue gas and of gas plant products attributable to each
lease by multiplying the net plant output of residue gas, or gas plant
products, by the ratio in which the theoretical volumes of residue gas,
or gas plant products, is the numerator and the theoretical volume of
residue gas, or gas plant products, delivered from all leases is the
denominator.
(4) You may request MMS approval of other methods for determining
the quantity of residue gas and gas plant products allocable to each
lease. If MMS approves a different method, it will be applicable to all
gas production from your Indian leases that is processed in the same
plant.
(e) You may not take any deductions from the royalty volume or
royalty value for actual or theoretical losses. Any actual loss of
unprocessed gas incurred prior to the facility measurement point will
not be subject to royalty if BLM determines that the loss was
unavoidable.
Sec. 206.176 How do I perform accounting for comparison?
(a) This section applies if the gas produced from your Indian lease
is processed and that Indian lease requires accounting for comparison
(also referred to as actual dual accounting). Except as provided in
paragraphs (b) and (c) of this section, the actual dual accounting
value, for royalty purposes, is the greater of the following two values:
(1) The combined value of the following products:
(i) The residue gas and gas plant products resulting from processing
the gas determined under either Sec. 206.172 or Sec. 206.174, less any
applicable allowances; and
(ii) Any drip condensate associated with the processed gas recovered
downstream of the point of royalty settlement without resorting to
processing determined under Sec. 206.52, less applicable allowances.
(2) The value of the gas prior to processing determined under either
Sec. 206.172 or Sec. 206.174, including any applicable allowances.
(b) If you are required to account for comparison, you may elect to
use the alternative dual accounting methodology provided for in Sec.
206.173 instead of
[[Page 114]]
the provisions in paragraph (a) of this section.
(c) Accounting for comparison is not required for gas if no gas from
the lease is processed until after the gas flows into a pipeline with an
index located in an index zone or into a mainline pipeline not in an
index zone. If you do not perform dual accounting, you must certify to
MMS that gas flows into such a pipeline before it is processed.
(d) Except as provided in paragraph (e) of this section, if you
value any gas production from a lease for a month using the dual
accounting provisions of this section or the alternative dual accounting
methodology of Sec. 206.173, then the value of that gas is the minimum
value for any other gas production from that lease for that month
flowing through the same facility measurement point.
(e) If the weighted-average Btu quality for your lease is less than
1,000 Btu's per cubic foot, see Sec. 206.173(b)(4)(ii) to determine if
you must perform a dual accounting calculation.
Transportation Allowances
Sec. 206.177 What general requirements regarding transportation allowances
apply to me?
(a) When you value gas under Sec. 206.174 at a point off the lease,
unit, or communitized area (for example, sales point or point of value
determination), you may deduct from value a transportation allowance to
reflect the value, for royalty purposes, at the lease, unit, or
communitized area. The allowance is based on the reasonable actual costs
you incurred to transport unprocessed gas, residue gas, or gas plant
products from a lease to a point off the lease, unit, or communitized
area. This would include, if appropriate, transportation from the lease
to a gas processing plant off the lease, unit, or communitized area and
from the plant to a point away from the plant. You may not deduct any
allowance for gathering costs.
(b) You must allocate transportation costs among all products you
produce and transport as provided in Sec. 206.178.
(c)(1) Except as provided in paragraphs (c)(2) and (3) of this
section, your transportation allowance deduction for each selling
arrangement may not exceed 50 percent of the value of the unprocessed
gas, residue gas, or gas plant product. For purposes of this section,
natural gas liquids are considered one product.
(2) If you ask MMS, MMS may approve a transportation allowance
deduction in excess of the limitations in paragraph (c)(1) of this
section. To receive this approval, you must demonstrate that the
transportation costs incurred in excess of the limitations in paragraph
(c)(1) of this section were reasonable, actual, and necessary. Under no
circumstances may an allowance reduce the value for royalty purposes
under any selling arrangement to zero.
(3) Your application for exception (using Form MMS-4393, Request to
Exceed Regulatory Allowance Limitation) must contain all relevant and
supporting documentation necessary for MMS to make a determination.
(d) If MMS conducts a review or audit and determines that you have
improperly determined a transportation allowance authorized by this
subpart, then you will be required to pay any additional royalties, plus
interest determined in accordance with 30 CFR 218.54. Alternatively, you
may be entitled to a credit, but you will not receive any interest on
your overpayment.
Sec. 206.178 How do I determine a transportation allowance?
(a) Determining a transportation allowance under an arm's-length
contract. (1) This paragraph explains how to determine your allowance if
you have an arm's-length transportation contract.
(i) If you have an arm's-length contract for transportation of your
production, the transportation allowance is the reasonable, actual costs
you incur for transporting the unprocessed gas, residue gas and/or gas
plant products under that contract. Paragraphs (a)(1)(ii) and (iii) of
this section provide a limited exception. You have the burden of
demonstrating that your contract is arm's-length. Your allowances also
are subject to paragraph (e) of this section. You are required to submit
to MMS a copy of your arm's-length transportation contract(s) and all
subsequent amendments to the contract(s)
[[Page 115]]
within 2 months of the date MMS receives your report which claims the
allowance on the Form MMS-2014.
(ii) When either MMS or a tribe conducts reviews and audits, they
will examine whether or not the contract reflects more than the
consideration actually transferred either directly or indirectly from
you to the transporter of the transportation. If the contract reflects
more than the total consideration, then MMS may require that the
transportation allowance be determined under paragraph (b) of this
section.
(iii) If MMS determines that the consideration paid under an arm's-
length transportation contract does not reflect the value of the
transportation because of misconduct by or between the contracting
parties, or because you otherwise have breached your duty to the lessor
to market the production for the mutual benefit of you and the lessor,
then MMS will require that the transportation allowance be determined
under paragraph (b) of this section. In these circumstances, MMS will
notify you and give you an opportunity to provide written information
justifying your transportation costs.
(2) This paragraph explains how to allocate the costs to each
product if your arm's-length transportation contract includes more than
one product in a gaseous phase and the transportation costs attributable
to each product cannot be determined from the contract.
(i) If your arm's-length transportation contract includes more than
one product in a gaseous phase and the transportation costs attributable
to each product cannot be determined from the contract, the total
transportation costs must be allocated in a consistent and equitable
manner to each of the products transported. To make this allocation, use
the same proportion as the ratio that the volume of each product
(excluding waste products which have no value) bears to the volume of
all products in the gaseous phase (excluding waste products which have
no value). Except as provided in this paragraph, you cannot take an
allowance for the costs of transporting lease production that is not
royalty bearing without MMS approval, or without lessor approval on
tribal leases.
(ii) As an alternative to paragraph (a)(2)(i) of this section, you
may propose to MMS a cost allocation method based on the values of the
products transported. MMS will approve the method if we determine that
it meets one of the two following requirements:
(A) The methodology in paragraph (a)(2)(i) of this section cannot be
applied; and
(B) Your proposal is more reasonable than the methodology in
paragraph (a)(2)(i) of this section.
(3) This paragraph explains how to allocate costs to each product if
your arm's-length transportation contract includes both gaseous and
liquid products and the transportation costs attributable to each cannot
be determined from the contract.
(i) If your arm's-length transportation contract includes both
gaseous and liquid products and the transportation costs attributable to
each cannot be determined from the contract, you must propose an
allocation procedure to MMS. You may use the transportation allowance
determined in accordance with your proposed allocation procedure until
MMS decides whether to accept your cost allocation.
(ii) You are required to submit all relevant data to support your
allocation proposal. MMS will then determine the gas transportation
allowance based upon your proposal and any additional information MMS
deems necessary.
(4) If your payments for transportation under an arm's-length
contract are not based on a dollar per unit price, you must convert
whatever consideration is paid to a dollar value equivalent for the
purposes of this section.
(5) Where an arm's-length sales contract price includes a reduction
for a transportation factor, MMS will not consider the transportation
factor to be a transportation allowance. You may use the transportation
factor to determine your gross proceeds for the sale of the product.
However, the transportation factor may not exceed 50 percent of the base
price of the product without MMS approval.
(b) Determining a transportation allowance under a non-arm's-length
or no contract. (1) This paragraph explains how to determine your
allowance if you
[[Page 116]]
have a non-arm's-length transportation contract or no contract.
(i) When you have a non-arm's-length transportation contract or no
contract, including those situations where you perform transportation
services for yourself, the transportation allowance is based upon your
reasonable, allowable, actual costs for transportation as provided in
this paragraph.
(ii) All transportation allowances deducted under a non-arm's-length
or no contract situation are subject to monitoring, review, audit, and
adjustment. You must submit the actual cost information to support the
allowance to MMS on Form MMS-4295, Gas Transportation Allowance Report,
within 3 months after the end of the 12-month period to which the
allowance applies. However, MMS may approve a longer time period. MMS
will monitor the allowance deductions to ensure that deductions are
reasonable and allowable. When necessary or appropriate, MMS may require
you to modify your actual transportation allowance deduction.
(2) This paragraph explains what actual transportation costs are
allowable under a non-arm's-length contract or no contract situation.
The transportation allowance for non-arm's-length or no-contract
situations is based upon your actual costs for transportation during the
reporting period. Allowable costs include operating and maintenance
expenses, overhead, and either depreciation and a return on
undepreciated capital investment (in accordance with paragraph
(b)(2)(iv)(A) of this section), or a cost equal to the initial
depreciable investment in the transportation system multiplied by a rate
of return in accordance with paragraph (b)(2)(iv)(B) of this section.
Allowable capital costs are generally those costs for depreciable fixed
assets (including costs of delivery and installation of capital
equipment) that are an integral part of the transportation system.
(i) Allowable operating expenses include operations supervision and
engineering, operations labor, fuel, utilities, materials, ad valorem
property taxes, rent, supplies, and any other directly allocable and
attributable operating expense that you can document.
(ii) Allowable maintenance expenses include maintenance of the
transportation system, maintenance of equipment, maintenance labor, and
other directly allocable and attributable maintenance expenses that you
can document.
(iii) Overhead directly attributable and allocable to the operation
and maintenance of the transportation system is an allowable expense.
State and Federal income taxes and severance taxes and other fees,
including royalties, are not allowable expenses.
(iv) You may use either depreciation with a return on undepreciated
capital investment or a return on depreciable capital investment. After
you have elected to use either method for a transportation system, you
may not later elect to change to the other alternative without MMS
approval.
(A) To compute depreciation, you may elect to use either a straight-
line depreciation method based on the life of equipment or on the life
of the reserves that the transportation system services, or a unit of
production method. Once you make an election, you may not change methods
without MMS approval. A change in ownership of a transportation system
will not alter the depreciation schedule that the original transporter/
lessee established for purposes of the allowance calculation. With or
without a change in ownership, a transportation system may be
depreciated only once. Equipment may not be depreciated below a
reasonable salvage value. To compute a return on undepreciated capital
investment, you will multiply the undepreciated capital investment in
the transportation system by the rate of return determined under
paragraph (b)(2)(v) of this section.
(B) To compute a return on depreciable capital investment, you will
multiply the initial capital investment in the transportation system by
the rate of return determined under paragraph (b)(2)(v) of this section.
No allowance will be provided for depreciation. This alternative will
apply only to transportation facilities first placed in service after
March 1, 1988.
(v) The rate of return is the industrial rate associated with
Standard and Poor's BBB rating. The rate of return
[[Page 117]]
is the monthly average rate as published in Standard and Poor's Bond
Guide for the first month of the reporting period for which the
allowance is applicable and is effective during the reporting period.
The rate must be redetermined at the beginning of each subsequent
transportation allowance reporting period that is determined under
paragraph (b)(4) of this section.
(3) This paragraph explains how to allocate transportation costs to
each product and transportation system.
(i) The deduction for transportation costs must be determined based
on your cost of transporting each product through each individual
transportation system. If you transport more than one product in a
gaseous phase, the allocation of costs to each of the products
transported must be made in a consistent and equitable manner. The
allocation should be in the same proportion that the volume of each
product (excluding waste products that have no value) bears to the
volume of all products in the gaseous phase (excluding waste products
that have no value). Except as provided in this paragraph, you may not
take an allowance for transporting a product that is not royalty bearing
without MMS approval.
(ii) As an alternative to the requirements of paragraph (b)(3)(i) of
this section, you may propose to MMS a cost allocation method based on
the values of the products transported. MMS will approve the method upon
determining that it meets one of the two following requirements:
(A) The methodology in paragraph (b)(3)(i) of this section cannot be
applied; and
(B) Your proposal is more reasonable than the method in paragraph
(b)(3)(i) of this section.
(4) Your transportation allowance under this paragraph (b) must be
determined based upon a calendar year or other period if you and MMS
agree to an alternative.
(5) If you transport both gaseous and liquid products through the
same transportation system, you must propose a cost allocation procedure
to MMS. You may use the transportation allowance determined in
accordance with your proposed allocation procedure until MMS issues its
determination on the acceptability of the cost allocation. You are
required to submit all relevant data to support your proposal. MMS will
then determine the transportation allowance based upon your proposal and
any additional information MMS deems necessary.
(c) Using the alternative transportation calculation when you have a
non-arm's-length or no contract. (1) As an alternative to computing your
transportation allowance under paragraph (b) of this section, you may
use as the transportation allowance 10 percent of your gross proceeds
but not to exceed 30 cents per MMBtu.
(2) Your election to use the alternative transportation allowance
calculation in paragraph (c)(1) of this section must be made at the
beginning of a month and must remain in effect for an entire calendar
year. Your first election will remain in effect until the end of the
succeeding calendar year, except for elections effective January 1 that
will be effective only for that calendar year.
(d) Reporting your transportation allowance. (1) If MMS requests,
you must submit all data used to determine your transportation
allowance. The data must be provided within a reasonable period of time
that MMS will determine.
(2) You must report transportation allowances as a separate line
item on Form MMS-2014. MMS may approve a different reporting procedure
on allottee leases, and with lessor approval on tribal leases.
(e) Adjusting incorrect allowances. If for any month the
transportation allowance you are entitled to is less than the amount you
took on Form MMS-2014, you are required to report and pay additional
royalties due, plus interest computed under 30 CFR 218.54 from the first
day of the first month you deducted the improper transportation
allowance until the date you pay the royalties due. If the
transportation allowance you are entitled to is greater than the amount
you took on Form MMS-2014 for any royalties during the reporting period,
you are entitled to a credit. No interest will be paid on the
overpayment.
(f) Determining allowable costs for transportation allowances.
Lessees may
[[Page 118]]
include, but are not limited to, the following costs in determining the
arm's-length transportation allowance under paragraph (a) of this
section or the non-arm's-length transportation allowance under paragraph
(b) of this section:
(1) Firm demand charges paid to pipelines. You must limit the
allowable costs for the firm demand charges to the applicable rate per
MMBtu multiplied by the actual volumes transported. You may not include
any losses incurred for previously purchased but unused firm capacity.
You also may not include any gains associated with releasing firm
capacity. If you receive a payment or credit from the pipeline for
penalty refunds, rate case refunds, or other reasons, you must reduce
the firm demand charge claimed on the Form MMS-2014. You must modify the
Form MMS-2014 by the amount received or credited for the affected
reporting period.
(2) Gas supply realignment (GSR) costs. The GSR costs result from a
pipeline reforming or terminating supply contracts with producers to
implement the restructuring requirements of FERC orders in 18 CFR part
284.
(3) Commodity charges. The commodity charge allows the pipeline to
recover the costs of providing service.
(4) Wheeling costs. Hub operators charge a wheeling cost for
transporting gas from one pipeline to either the same or another
pipeline through a market center or hub. A hub is a connected manifold
of pipelines through which a series of incoming pipelines are
interconnected to a series of outgoing pipelines.
(5) Gas Research Institute (GRI) fees. The GRI conducts research,
development, and commercialization programs on natural gas related
topics for the benefit of the U.S. gas industry and gas customers. GRI
fees are allowable provided such fees are mandatory in FERC-approved
tariffs.
(6) Annual Charge Adjustment (ACA) fees. FERC charges these fees to
pipelines to pay for its operating expenses.
(7) Payments (either volumetric or in value) for actual or
theoretical losses. This paragraph does not apply to non-arm's-length
transportation arrangements.
(8) Temporary storage services. This includes short duration storage
services offered by market centers or hubs (commonly referred to as
``parking'' or ``banking''), or other temporary storage services
provided by pipeline transporters, whether actual or provided as a
matter of accounting. Temporary storage is limited to 30 days or less.
(9) Supplemental costs for compression, dehydration, and treatment
of gas. MMS allows these costs only if such services are required for
transportation and exceed the services necessary to place production
into marketable condition required under Sec. 206.174(h).
(g) Determining nonallowable costs for transportation allowances.
Lessees may not include the following costs in determining the arm's-
length transportation allowance under paragraph (a) of this section or
the non-arm's-length transportation allowance under paragraph (b) of
this section:
(1) Fees or costs incurred for storage. This includes storing
production in a storage facility, whether on or off the lease, for more
than 30 days.
(2) Aggregater/marketer fees. This includes fees you pay to another
person (including your affiliates) to market your gas, including
purchasing and reselling the gas, or finding or maintaining a market for
the gas production.
(3) Penalties you incur as shipper. These penalties include, but are
not limited to the following:
(i) Over-delivery cash-out penalties. This includes the difference
between the price the pipeline pays you for over-delivered volumes
outside the tolerances and the price you receive for over-delivered
volumes within tolerances.
(ii) Scheduling penalties. This includes penalties you incur for
differences between daily volumes delivered into the pipeline and
volumes scheduled or nominated at a receipt or delivery point.
(iii) Imbalance penalties. This includes penalties you incur
(generally on a monthly basis) for differences between volumes delivered
into the pipeline and volumes scheduled or nominated at a receipt or
delivery point.
(iv) Operational penalties. This includes fees you incur for
violation of
[[Page 119]]
the pipeline's curtailment or operational orders issued to protect the
operational integrity of the pipeline.
(4) Intra-hub transfer fees. These are fees you pay to hub operators
for administrative services (e.g., title transfer tracking) necessary to
account for the sale of gas within a hub.
(5) Other nonallowable costs. Any cost you incur for services you
are required to provide at no cost to the lessor.
(h) Other transportation cost determinations. You must follow the
provisions of this section to determine transportation costs when
establishing value using either a net-back valuation procedure or any
other procedure that allows deduction of actual transportation costs.
Processing Allowances
Sec. 206.179 What general requirements regarding processing allowances apply
to me?
(a) When you value any gas plant product under Sec. 206.174, you
may deduct from value the reasonable actual costs of processing.
(b) You must allocate processing costs among the gas plant products.
You must determine a separate processing allowance for each gas plant
product and processing plant relationship. Natural gas liquids are
considered as one product.
(c) The processing allowance deduction based on an individual
product may not exceed 66 2/3 percent of the value of each gas plant
product determined under Sec. 206.174. Before you calculate the 66 2/3
percent limit, you must first reduce the value for any transportation
allowances related to post-processing transportation authorized under
Sec. 206.177.
(d) Processing cost deductions will not be allowed for placing lease
products in marketable condition. These costs include among others,
dehydration, separation, compression upstream of the facility
measurement point, or storage, even if those functions are performed off
the lease or at a processing plant. Costs for the removal of acid gases,
commonly referred to as sweetening, are not allowed unless the acid
gases removed are further processed into a gas plant product. In such
event, you will be eligible for a processing allowance determined under
this subpart. However, MMS will not grant any processing allowance for
processing lease production that is not royalty bearing.
(e) You will be allowed a reasonable amount of residue gas royalty
free for operation of the processing plant, but no allowance will be
made for expenses incidental to marketing, except as provided in 30 CFR
part 206. In those situations where a processing plant processes gas
from more than one lease, only that proportionate share of your residue
gas necessary for the operation of the processing plant will be allowed
royalty free.
(f) You do not owe royalty on residue gas, or any gas plant product
resulting from processing gas, that is reinjected into a reservoir
within the same lease, unit, or approved Federal agreement, until such
time as those products are finally produced from the reservoir for sale
or other disposition. This paragraph applies only when the reinjection
is included in a BLM-approved plan of development or operations.
(g) If MMS determines that you have determined an improper
processing allowance authorized by this subpart, then you will be
required to pay any additional royalties plus late payment interest
determined under 30 CFR 218.54. Alternatively, you may be entitled to a
credit, but you will not receive any interest on your overpayment.
Sec. 206.180 How do I determine an actual processing allowance?
(a) Determining a processing allowance if you have an arms's-length
processing contract. (1) This paragraph explains how you determine an
allowance under an arm's-length processing contract.
(i) The processing allowance is the reasonable actual costs you
incur to process the gas under that contract. Paragraphs (a)(1)(ii) and
(iii) of this section provide a limited exception. You have the burden
of demonstrating that your contract is arm's-length. You are required to
submit to MMS a copy of your arm's-length contract(s) and all subsequent
amendments to the contract(s) within 2 months of the date MMS receives
your first report that deducts the allowance on the Form MMS-2014.
[[Page 120]]
(ii) When MMS conducts reviews and audits, we will examine whether
the contract reflects more than the consideration actually transferred
either directly or indirectly from you to the processor for the
processing. If the contract reflects more than the total consideration,
then MMS may require that the processing allowance be determined under
paragraph (b) of this section.
(iii) If MMS determines that the consideration paid under an arm's-
length processing contract does not reflect the value of the processing
because of misconduct by or between the contracting parties, or because
you otherwise have breached your duty to the lessor to market the
production for the mutual benefit of you and the lessor, then MMS will
require that the processing allowance be determined under paragraph (b)
of this section. In these circumstances, MMS will notify you and give
you an opportunity to provide written information justifying your
processing costs.
(2) If your arm's-length processing contract includes more than one
gas plant product and the processing costs attributable to each product
can be determined from the contract, then the processing costs for each
gas plant product must be determined in accordance with the contract.
You may not take an allowance for the costs of processing lease
production that is not royalty-bearing.
(3) If your arm's-length processing contract includes more than one
gas plant product and the processing costs attributable to each product
cannot be determined from the contract, you must propose an allocation
procedure to MMS. You may use your proposed allocation procedure until
MMS issues its determination. You are required to submit all relevant
data to support your proposal. MMS will then determine the processing
allowance based upon your proposal and any additional information MMS
deems necessary. You may not take a processing allowance for the costs
of processing lease production that is not royalty-bearing.
(4) If your payments for processing under an arm's-length contract
are not based on a dollar per unit price, you must convert whatever
consideration is paid to a dollar value equivalent for the purposes of
this section.
(b) Determining a processing allowance if you have a non-arm's-
length contract or no contract. (1) This paragraph applies if you have a
non-arm's-length processing contract or no contract, including those
situations where you perform processing for yourself.
(i) If you have a non-arm's-length contract or no contract, the
processing allowance is based upon your reasonable actual costs of
processing as provided in paragraph (b)(2) of this section.
(ii) All processing allowances deducted under a non-arm's-length or
no-contract situation are subject to monitoring, review, audit, and
adjustment. You must submit the actual cost information to support the
allowance to MMS on Form MMS-4109, Gas Processing Allowance Summary
Report, within 3 months after the end of the 12-month period for which
the allowance applies. MMS may approve a longer time period. MMS will
monitor the allowance deduction to ensure that deductions are reasonable
and allowable. When necessary or appropriate, MMS may require you to
modify your processing allowance.
(2) The processing allowance for non-arm's-length or no-contract
situations is based upon your actual costs for processing during the
reporting period. Allowable costs include operating and maintenance
expenses, overhead, and either depreciation and a return on
undepreciated capital investment (in accordance with paragraph
(b)(2)(iv)(A) of this section), or a cost equal to the initial
depreciable investment in the processing plant multiplied by a rate of
return in accordance with paragraph (b)(2)(iv)(B) of this section.
Allowable capital costs are generally those costs for depreciable fixed
assets (including costs of delivery and installation of capital
equipment) that are an integral part of the processing plant.
(i) Allowable operating expenses include operations supervision and
engineering, operations labor, fuel, utilities, materials, ad valorem
property taxes, rent, supplies, and any other directly allocable and
attributable operating expense that the lessee can document.
[[Page 121]]
(ii) Allowable maintenance expenses include maintenance of the
processing plant, maintenance of equipment, maintenance labor, and other
directly allocable and attributable maintenance expenses that you can
document.
(iii) Overhead directly attributable and allocable to the operation
and maintenance of the processing plant is an allowable expense. State
and Federal income taxes and severance taxes, including royalties, are
not allowable expenses.
(iv) You may use either depreciation with a return on undepreciable
capital investment or a return on depreciable capital investment. After
you elect to use either method for a processing plant, you may not later
elect to change to the other alternative without MMS approval.
(A) To compute depreciation, you may elect to use either a straight-
line depreciation method based on the life of equipment or on the life
of the reserves that the processing plant services, or a unit-of-
production method. Once you make an election, you may not change methods
without MMS approval. A change in ownership of a processing plant will
not alter the depreciation schedule that the original processor/lessee
established for purposes of the allowance calculation. However, for
processing plants you or your affiliate purchase that do not have a
previously claimed MMS depreciation schedule, you may treat the
processing plant as a newly installed facility for depreciation
purposes. A processing plant may be depreciated only once, regardless of
whether there is a change in ownership. Equipment may not be depreciated
below a reasonable salvage value. To compute a return on undepreciated
capital investment, you must multiply the undepreciable capital
investment in the processing plant by the rate of return determined
under paragraph (b)(2)(v) of this section.
(B) To compute a return on depreciable capital investment, you must
multiply the initial capital investment in the processing plant by the
rate of return determined under paragraph (b)(2)(v) of this section. No
allowance will be provided for depreciation. This alternative will apply
only to plants first placed in service after March 1, 1988.
(v) The rate of return is the industrial rate associated with
Standard and Poor's BBB rating. The rate of return is the monthly
average rate as published in Standard and Poor's Bond Guide for the
first month for which the allowance is applicable. The rate must be
redetermined at the beginning of each subsequent calendar year.
(3) Your processing allowance under this paragraph (b) must be
determined based upon a calendar year or other period if you and MMS
agree to an alternative.
(4) The processing allowance for each gas plant product must be
determined based on your reasonable and actual cost of processing the
gas. You must base your allocation of costs to each gas plant product
upon generally accepted accounting principles. You may not take an
allowance for the costs of processing lease production that is not
royalty-bearing.
(c) Reporting your processing allowance. (1) If MMS requests, you
must submit all data used to determine your processing allowance. The
data must be provided within a reasonable period of time, as MMS
determines.
(2) You must report gas processing allowances as a separate line
item on the Form MMS-2014. MMS may approve a different reporting
procedure for allottee leases, and with lessor approval on tribal
leases.
(d) Adjusting incorrect processing allowances. If for any month the
gas processing allowance you are entitled to is less than the amount you
took on Form MMS-2014, you are required to pay additional royalties,
plus interest computed under 30 CFR 218.54 from the first day of the
first month you deducted a processing allowance until the date you pay
the royalties due. If the processing allowance you are entitled is
greater than the amount you took on Form MMS-2014, you are entitled to a
credit. However, no interest will be paid on the overpayment.
(e) Other processing cost determinations. You must follow the
provisions of this section to determine processing costs when
establishing value using either a net-back valuation procedure or
[[Page 122]]
any other procedure that requires deduction of actual processing costs.
Sec. 206.181 How do I establish processing costs for dual accounting
purposes when I do not process the gas?
Where accounting for comparison (dual accounting) is required for
gas production from a lease but neither you nor someone acting on your
behalf processes the gas, and you have elected to perform actual dual
accounting under Sec. 206.176, you must use the first applicable of the
following methods to establish processing costs for dual accounting
purposes:
(a) The average of the costs established in your current arm's-
length processing agreements for gas from the lease, provided that some
gas has previously been processed under these agreements.
(b) The average of the costs established in your current arm's-
length processing agreements for gas from the lease, provided that the
agreements are in effect for plants to which the lease is physically
connected and under which gas from other leases in the field or area is
being or has been processed.
(c) A proposed comparable processing fee submitted to either the
tribe and MMS (for tribal leases) or MMS (for allotted leases) with your
supporting documentation submitted to MMS. If MMS does not take action
on your proposal within 120 days, the proposal will be deemed to be
denied and subject to appeal to the MMS Director under 30 CFR part 290.
(d) Processing costs based on the regulations in Sec. Sec. 206.179
and 206.180.
Subpart F_Federal Coal
Source: 54 FR 1523, Jan. 13, 1989, unless otherwise noted.
Sec. 206.250 Purpose and scope.
(a) This subpart is applicable to all coal produced from Federal
coal leases. The purpose of this subpart is to establish the value of
coal produced for royalty purposes, of all coal from Federal leases
consistent with the mineral leasing laws, other applicable laws and
lease terms.
(b) If the specific provisions of any statute or settlement
agreement between the United States and a lessee resulting from
administrative or judicial litigation, or any coal lease subject to the
requirements of this subpart, are inconsistent with any regulation in
this subpart then the statute, lease provision, or settlement shall
govern to the extent of that inconsistency.
(c) All royalty payments made to the Minerals Management Service
(MMS) are subject to later audit and adjustment.
[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5479, Feb. 12, 1996; 67
FR 19111, Apr. 18, 2002]
Sec. 206.251 Definitions.
Ad valorem lease means a lease where the royalty due to the lessor
is based upon a percentage of the amount or value of the coal.
Allowance means a deduction used in determining value for royalty
purposes. Coal washing allowance means an allowance for the reasonable,
actual costs incurred by the lessee for coal washing. Transportation
allowance means an allowance for the reasonable, actual costs incurred
by the lessee for moving coal to a point of sale or point of delivery
remote from both the lease and mine or wash plant.
Area means a geographic region in which coal has similar quality and
economic characteristics. Area boundaries are not officially designated
and the areas are not necessarily named.
Arm's-length contract means a contract or agreement that has been
arrived at in the marketplace between independent, nonaffiliated persons
with opposing economic interests regarding that contract. For purposes
of this subpart, two persons are affiliated if one person controls, is
controlled by, or is under common control with another person. For
purposes of this subpart, based on the instruments of ownership of the
voting securities of an entity, or based on other forms of ownership:
(a) Ownership in excess of 50 percent constitutes control;
(b) Ownership of 10 through 50 percent creates a presumption of
control; and
[[Page 123]]
(c) Ownership of less than 10 percent creates a presumption of
noncontrol which MMS may rebut if it demonstrates actual or legal
control, including the existence of interlocking directorates.
Notwithstanding any other provisions of this subpart, contracts between
relatives, either by blood or by marriage, are not arm's-length
contracts. The MMS may require the lessee to certify ownership control.
To be considered arm's-length for any production month, a contract must
meet the requirements of this definition for that production month as
well as when the contract was executed.
Audit means a review, conducted in accordance with generally
accepted accounting and auditing standards, of royalty payment
compliance activities of lessees or other interest holders who pay
royalties, rents, or bonuses on Federal leases.
BLM means the Bureau of Land Management of the Department of the
Interior.
Coal means coal of all ranks from lignite through anthracite.
Coal washing means any treatment to remove impurities from coal.
Coal washing may include, but is not limited to, operations such as
flotation, air, water, or heavy media separation; drying; and related
handling (or combination thereof).
Contract means any oral or written agreement, including amendments
or revisions thereto, between two or more persons and enforceable by law
that with due consideration creates an obligation.
Gross proceeds (for royalty payment purposes) means the total monies
and other consideration accruing to a coal lessee for the production and
disposition of the coal produced. Gross proceeds includes, but is not
limited to, payments to the lessee for certain services such as
crushing, sizing, screening, storing, mixing, loading, treatment with
substances including chemicals or oils, and other preparation of the
coal to the extent that the lessee is obligated to perform them at no
cost to the Federal Government. Gross proceeds, as applied to coal, also
includes but is not limited to reimbursements for royalties, taxes or
fees, and other reimbursements. Tax reimbursements are part of the gross
proceeds accruing to a lessee even though the Federal royalty interest
may be exempt from taxation. Monies and other consideration, including
the forms of consideration identified in this paragraph, to which a
lessee is contractually or legally entitled but which it does not seek
to collect through reasonable efforts are also part of gross proceeds.
Lease means any contract, profit-share arrangement, joint venture,
or other agreement issued or approved by the United States for a Federal
coal resource under a mineral leasing law that authorizes exploration
for, development or extraction of, or removal of coal--or the land
covered by that authorization, whichever is required by the context.
Lessee means any person to whom the United States issues a lease,
and any person who has been assigned an obligation to make royalty or
other payments required by the lease. This includes any person who has
an interest in a lease as well as an operator or payor who has no
interest in the lease but who has assumed the royalty payment
responsibility.
Like-quality coal means coal that has similar chemical and physical
characteristics.
Marketable condition means coal that is sufficiently free from
impurities and otherwise in a condition that it will be accepted by a
purchaser under a sales contract typical for that area.
Mine means an underground or surface excavation or series of
excavations and the surface or underground support facilities that
contribute directly or indirectly to mining, production, preparation,
and handling of lease products.
Net-back method means a method for calculating market value of coal
at the lease or mine. Under this method, costs of transportation,
washing, handling, etc., are deducted from the ultimate proceeds
received for the coal at the first point at which reasonable values for
the coal may be determined by a sale pursuant to an arm's-length
contract or by comparison to other sales of coal, to ascertain value at
the mine.
Net output means the quantity of washed coal that a washing plant
produces.
[[Page 124]]
Netting is the deduction of an allowance from the sales value by
reporting a one line net sales value, instead of correctly reporting the
deduction as a separate line item on the Form MMS-4430.
Person means by individual, firm, corporation, association,
partnership, consortium, or joint venture.
Selling arrangement means the individual contractual arrangements
under which sales or dispositions of coal are made to a purchaser.
Spot market price means the price received under any sales
transaction when planned or actual deliveries span a short period of
time, usually not exceeding one year.
[54 FR 1523, Jan. 13, 1989, as amended at 55 FR 35433, Aug. 30, 1990; 61
FR 5479, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999; 66 FR 45769, Aug.
30, 2001]
Sec. 206.252 Information collection.
The information collection requirements contained in this subpart
have been approved by the Office of Management and Budget (OMB) under 44
U.S.C. 3501 et seq. The forms, filing date, and approved OMB clearance
numbers are identified in 30 CFR 210.10 and 30 CFR 216.10.
Sec. 206.253 Coal subject to royalties--general provisions.
(a) All coal (except coal unavoidably lost as determined by BLM
under 43 CFR part 3400) from a Federal lease subject to this part is
subject to royalty. This includes coal used, sold, or otherwise disposed
of by the lessee on or off the lease.
(b) If a lessee receives compensation for unavoidably lost coal
through insurance coverage or other arrangements, royalties at the rate
specified in the lease are to be paid on the amount of compensation
received for the coal. No royalty is due on insurance compensation
received by the lessee for other losses.
(c) If waste piles or slurry ponds are reworked to recover coal, the
lessee shall pay royalty at the rate specified in the lease at the time
the recovered coal is used, sold, or otherwise finally disposed of. The
royalty rate shall be that rate applicable to the production method used
to initially mine coal in the waste pile or slurry pond; i.e.,
underground mining method or surface mining method. Coal in waste pits
or slurry ponds initially mined from Federal leases shall be allocated
to such leases regardless of whether it is stored on Federal lands. The
lessee shall maintain accurate records to determine to which individual
Federal lease coal in the waste pit or slurry pond should be allocated.
However, nothing in this section requires payment of a royalty on coal
for which a royalty has already been paid.
[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5479, Feb. 12, 1996]
Sec. 206.254 Quality and quantity measurement standards for reporting and
paying royalties.
For all leases subject to this subpart, the quantity of coal on
which royalty is due shall be measured in short tons (of 2,000 pounds
each) by methods prescribed by the BLM. Coal quantity information shall
be reported on appropriate forms required under 30 CFR part 216 and on
the Solid Minerals Production and Royalty Report, Form MMS-4430, as
required under 30 CFR part 210.
[54 FR 1523, Jan. 13, 1989, as amended at 57 FR 52720, Nov. 5, 1992; 66
FR 45769, Aug. 30, 2001]
Sec. 206.255 Point of royalty determination.
(a) For all leases subject to this subpart, royalty shall be
computed on the basis of the quantity and quality of Federal coal in
marketable condition measured at the point of royalty measurement as
determined jointly by BLM and MMS.
(b) Coal produced and added to stockpiles or inventory does not
require payment of royalty until such coal is later used, sold, or
otherwise finally disposed of. MMS may ask BLM to increase the lease
bond to protect the lessor's interest when BLM determines that
stockpiles or inventory become excessive so as to increase the risk of
degradation of the resource.
(c) The lessee shall pay royalty at a rate specified in the lease at
the time
[[Page 125]]
the coal is used, sold, or otherwise finally disposed of, unless
otherwise provided for at Sec. 206.256(d) of this subpart.
[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5480, Feb. 12, 1996]
Sec. 206.256 Valuation standards for cents-per-ton leases.
(a) This section is applicable to coal leases on Federal lands which
provide for the determination of royalty on a cents-per-ton (or other
quantity) basis.
(b) The royalty for coal from leases subject to this section shall
be based on the dollar rate per ton prescribed in the lease. That dollar
rate shall be applicable to the actual quantity of coal used, sold, or
otherwise finally disposed of, including coal which is avoidably lost as
determine by BLM pursuant to 43 CFR part 3400.
(c) For leases subject to this section, there shall be no allowances
for transportation, removal of impurities, coal washing, or any other
processing or preparation of the coal.
(d) When a coal lease is readjusted pursuant to 43 CFR part 3400 and
the royalty valuation method changes from a cents-per-ton basis to an ad
valorem basis, coal which is produced prior to the effective date of
readjustment and sold or used within 30 days of the effective date of
readjustment shall be valued pursuant to this section. All coal that is
not used, sold, or otherwise finally disposed of within 30 days after
the effective date of readjustment shall be valued pursuant to the
provisions of Sec. 206.257 of this subpart, and royalties shall be paid
at the royalty rate specified in the readjusted lease.
[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5480, Feb. 12, 1996]
Sec. 206.257 Valuation standards for ad valorem leases.
(a) This section is applicable to coal leases on Federal lands which
provide for the determination of royalty as a percentage of the amount
of value of coal (ad valorem). The value for royalty purposes of coal
from such leases shall be the value of coal determined under this
section, less applicable coal washing allowances and transportation
allowances determined under Sec. Sec. 206.258 through 206.262 of this
subpart, or any allowance authorized by Sec. 206.265 of this subpart.
The royalty due shall be equal to the value for royalty purposes
multiplied by the royalty rate in the lease.
(b)(1) The value of coal that is sold pursuant to an arm's-length
contract shall be the gross proceeds accruing to the lessee, except as
provided in paragraphs (b)(2), (b)(3), and (b)(5) of this section. The
lessee shall have the burden of demonstrating that its contract is
arm's-length. The value which the lessee reports, for royalty purposes,
is subject to monitoring, review, and audit.
(2) In conducting reviews and audits, MMS will examine whether the
contract reflects the total consideration actually transferred either
directly or indirectly from the buyer to the seller for the coal
produced. If the contract does not reflect the total consideration, then
the MMS may require that the coal sold pursuant to that contract be
valued in accordance with paragraph (c) of this section. Value may not
be based on less than the gross proceeds accruing to the lessee for the
coal production, including the additional consideration.
(3) If the MMS determines that the gross proceeds accruing to the
lessee pursuant to an arm's-length contract do not reflect the
reasonable value of the production because of misconduct by or between
the contracting parties, or because the lessee otherwise has breached
its duty to the lessor to market the production for the mutual benefit
of the lessee and the lessor, then MMS shall require that the coal
production be valued pursuant to paragraph (c)(2) (ii), (iii), (iv), or
(v) of this section, and in accordance with the notification
requirements of paragraph (d)(3) of this section. When MMS determines
that the value may be unreasonable, MMS will notify the lessee and give
the lessee an opportunity to provide written information justifying the
lessee's reported coal value.
(4) The MMS may require a lessee to certify that its arm's-length
contract provisions include all of the consideration to be paid by the
buyer, either directly or indirectly, for the coal production.
(5) The value of production for royalty purposes shall not include
payments received by the lessee pursuant
[[Page 126]]
to a contract which the lessee demonstrates, to MMS's satisfaction, were
not part of the total consideration paid for the purchase of coal
production.
(c)(1) The value of coal from leases subject to this section and
which is not sold pursuant to an arm's-length contract shall be
determined in accordance with this section.
(2) If the value of the coal cannot be determined pursuant to
paragraph (b) of this section, then the value shall be determined
through application of other valuation criteria. The criteria shall be
considered in the following order, and the value shall be based upon the
first applicable criterion:
(i) The gross proceeds accruing to the lessee pursuant to a sale
under its non-arm's-length contract (or other disposition of produced
coal by other than an arm's-length contract), provided that those gross
proceeds are within the range of the gross proceeds derived from, or
paid under, comparable arm's-length contracts between buyers and sellers
neither of whom is affiliated with the lessee for sales, purchases, or
other dispositions of like-quality coal produced in the area. In
evaluating the comparability of arm's-length contracts for the purposes
of these regulations, the following factors shall be considered: Price,
time of execution, duration, market or markets served, terms, quality of
coal, quantity, and such other factors as may be appropriate to reflect
the value of the coal;
(ii) Prices reported for that coal to a public utility commission;
(iii) Prices reported for that coal to the Energy Information
Administration of the Department of Energy;
(iv) Other relevant matters including, but not limited to, published
or publicly available spot market prices, or information submitted by
the lessee concerning circumstances unique to a particular lease
operation or the saleability of certain types of coal;
(v) If a reasonable value cannot be determined using paragraphs
(c)(2) (i), (ii), (iii), or (iv) of this section, then a net-back method
or any other reasonable method shall be used to determine value.
(3) When the value of coal is determined pursuant to paragraph
(c)(2) of this section, that value determination shall be consistent
with the provisions contained in paragraph (b)(5) of this section.
(d)(1) Where the value is determined pursuant to paragraph (c) of
this section, that value does not require MMS's prior approval. However,
the lessee shall retain all data relevant to the determination of
royalty value. Such data shall be subject to review and audit, and MMS
will direct a lessee to use a different value if it determines that the
reported value is inconsistent with the requirements of these
regulations.
(2) Any Federal lessee will make available upon request to the
authorized MMS or State representatives, to the Inspector General of the
Department of the Interior or other persons authorized to receive such
information, arm's-length sales value and sales quantity data for like-
quality coal sold, purchased, or otherwise obtained by the lessee from
the area.
(3) A lessee shall notify MMS if it has determined value pursuant to
paragraphs (c)(2) (ii), (iii), (iv), or (v) of this section. The
notification shall be by letter to the Associate Director for Minerals
Revenue Management of his/her designee. The letter shall identify the
valuation method to be used and contain a brief description of the
procedure to be followed. The notification required by this section is a
one-time notification due no later than the month the lessee first
reports royalties on the Form MMS-4430 using a valuation method
authorized by paragraphs (c)(2) (ii), (iii), (iv), or (v) of this
section, and each time there is a change in a method under paragraphs
(c)(2) (iv) or (v) of this section.
(e) If MMS determines that a lessee has not properly determined
value, the lessee shall be liable for the difference, if any, between
royalty payments made based upon the value it has used and the royalty
payments that are due based upon the value established by MMS. The
lessee shall also be liable for interest computed pursuant to 30 CFR
218.202. If the lessee is entitled to a credit, MMS will provide
instructions for the taking of that credit.
(f) The lessee may request a value determination from MMS. In that
event, the lessee shall propose to MMS a
[[Page 127]]
value determination method, and may use that method in determining value
for royalty purposes until MMS issues its decision. The lessee shall
submit all available data relevant to its proposal. The MMS shall
expeditiously determine the value based upon the lessee's proposal and
any additional information MMS deems necessary. That determination shall
remain effective for the period stated therein. After MMS issues its
determination, the lessee shall make the adjustments in accordance with
paragraph (e) of this section.
(g) Notwithstanding any other provisions of this section, under no
circumstances shall the value for royalty purposes be less than the
gross proceeds accruing to the lessee for the disposition of produced
coal less applicable provisions of paragraph (b)(5) of this section and
less applicable allowances determined pursuant to Sec. Sec. 206.258
through 206.262 and Sec. 206.265 of this subpart.
(h) The lessee is required to place coal in marketable condition at
no cost to the Federal Government. Where the value established under
this section is determined by a lessee's gross proceeds, that value
shall be increased to the extent that the gross proceeds has been
reduced because the purchaser, or any other person, is providing certain
services, the cost of which ordinarily is the responsibility of the
lessee to place the coal in marketable condition.
(i) Value shall be based on the highest price a prudent lessee can
receive through legally enforceable claims under its contract. Absent
contract revision or amendment, if the lessee fails to take proper or
timely action to receive prices or benefits to which it is entitled, it
must pay royalty at a value based upon that obtainable price or benefit.
Contract revisions or amendments shall be in writing and signed by all
parties to an arm's-length contract, and may be retroactively applied to
value for royalty purposes for a period not to exceed two years, unless
MMS approves a longer period. If the lessee makes timely application for
a price increase allowed under its contract but the purchaser refuses,
and the lessee takes reasonable measures, which are documented, to force
purchaser compliance, the lessee will owe no additional royalties unless
or until monies or consideration resulting from the price increase are
received. This paragraph shall not be construed to permit a lessee to
avoid its royalty payment obligation in situations where a purchaser
fails to pay, in whole or in part or timely, for a quantity of coal.
(j) Notwithstanding any provision in these regulations to the
contrary, no review, reconciliation, monitoring, or other like process
that results in a redetermination by MMS of value under this section
shall be considered final or binding as against the Federal Government
or its beneficiaries until the audit period is formally closed.
(k) Certain information submitted to MMS to support valuation
proposals, including transportation, coal washing, or other allowances
under Sec. 206.265 of this subpart, is exempted from disclosure by the
Freedom of Information Act, 5 U.S.C. 522. Any data specified by the Act
to be privileged, confidential, or otherwise exempt shall be maintained
in a confidential manner in accordance with applicable law and
regulations. All requests for information about determinations made
under this part are to be submitted in accordance with the Freedom of
Information Act regulation of the Department of the Interior, 43 CFR
part 2.
[54 FR 1523, Jan. 13, 1989, as amended at 55 FR 35433, Aug. 30, 1990; 57
FR 52720, Nov. 5, 1992; 61 FR 5480, Feb. 12, 1996; 66 FR 45769, Aug. 30,
2001]
Sec. 206.258 Washing allowances--general.
(a) For ad valorem leases subject to Sec. 206.257 of this subpart,
MMS shall, as authorized by this section, allow a deduction in
determining value for royalty purposes for the reasonable, actual costs
incurred to wash coal, unless the value determined pursuant to Sec.
206.257 of this subpart was based upon like-quality unwashed coal. Under
no circumstances will the authorized washing allowance and the
transportation allowance reduce the value for royalty purposes to zero.
(b) If MMS determines that a lessee has improperly determined a
washing allowance authorized by this section, then the lessee shall be
liable for any
[[Page 128]]
additional royalties, plus interest determined in accordance with 30 CFR
218.202, or shall be entitled to a credit without interest.
(c) Lessees shall not disproportionately allocate washing costs to
Federal leases.
(d) No cost normally associated with mining operations and which are
necessary for placing coal in marketable condition shall be allowed as a
cost of washing.
(e) Coal washing costs shall only be recognized as allowances when
the washed coal is sold and royalties are reported and paid.
[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5480, Feb. 12, 1996; 64
FR 43288, Aug. 10, 1999]
Sec. 206.259 Determination of washing allowances.
(a) Arm's-length contracts. (1) For washing costs incurred by a
lessee under an arm's-length contract, the washing allowance shall be
the reasonable actual costs incurred by the lessee for washing the coal
under that contract, subject to monitoring, review, audit, and possible
future adjustment. The lessee shall have the burden of demonstrating
that its contract is arm's-length. MMS' prior approval is not required
before a lessee may deduct costs incurred under an arm's-length
contract. The lessee must claim a washing allowance by reporting it as a
separate line entry on the Form MMS-4430.
(2) In conducting reviews and audits, MMS will examine whether the
contract reflects more than the consideration actually transferred
either directly or indirectly from the lessee to the washer for the
washing. If the contract reflects more than the total consideration
paid, then the MMS may require that the washing allowance be determined
in accordance with paragraph (b) of this section.
(3) If the MMS determines that the consideration paid pursuant to an
arm's-length washing contract does not reflect the reasonable value of
the washing because of misconduct by or between the contracting parties,
or because the lessee otherwise has breached its duty to the lessor to
market the production for the mutual benefit of the lessee and the
lessor, then MMS shall require that the washing allowance be determined
in accordance with paragraph (b) of this section. When MMS determines
that the value of the washing may be unreasonable, MMS will notify the
lessee and give the lessee an opportunity to provide written information
justifying the lessee's washing costs.
(4) Where the lessee's payments for washing under an arm's-length
contract are not based on a dollar-per-unit basis, the lessee shall
convert whatever consideration is paid to a dollar value equivalent.
Washing allowances shall be expressed as a cost per ton of coal washed.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length contract or has no contract, including those situations
where the lessee performs washing for itself, the washing allowance will
be based upon the lessee's reasonable actual costs. All washing
allowances deducted under a non-arm's-length or no contract situation
are subject to monitoring, review, audit, and possible future
adjustment. The lessee must claim a washing allowance by reporting it as
a separate line entry on the Form MMS-4430. When necessary or
appropriate, MMS may direct a lessee to modify its estimated or actual
washing allowance.
(2) The washing allowance for non-arm's-length or no contract
situations shall be based upon the lessee's actual costs for washing
during the reported period, including operating and maintenance
expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph (b)(2)(iv)
(A) of this section, or a cost equal to the depreciable investment in
the wash plant multiplied by the rate of return in accordance with
paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are
generally those for depreciable fixed assets (including costs of
delivery and installation of capital equipment) which are an integral
part of the wash plant.
(i) Allowable operating expenses include: Operations supervision and
engineering; operations labor; fuel; utilities; materials; ad valorem
property
[[Page 129]]
taxes, rent; supplies; and any other directly allocable and attributable
operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the wash
plant; maintenance of equipment; maintenance labor; and other directly
allocable and attributable maintenance expenses which the lessee can
document.
(iii) Overhead attributable and allocable to the operation and
maintenance of the wash plant is an allowable expense. State and Federal
income taxes and severance taxes, including royalities, are not
allowable expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this
section. After a lessee has elected to use either method for a wash
plant, the lessee may not later elect to change to the other alternative
without approval of the MMS.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the wash plant services, whichever is
appropriate, or a unit of production method. After an election is made,
the lessee may not change methods without MMS approval. A change in
ownership of a wash plant shall not alter the depreciation schedule
established by the original operator/lessee for purposes of the
allowance calculation. With or without a change in ownership, a wash
plant shall be depreciated only once. Equipment shall not be depreciated
below a reasonable salvage value.
(B) The MMS shall allow as a cost an amount equal to the allowable
capital investment in the wash plant multiplied by the rate of return
determined pursuant to paragraph (b)(2)(v) of this section. No allowance
shall be provided for depreciation. This alternative shall apply only to
plants first placed in service or acquired after March 1, 1989.
(v) The rate of return must be the industrial rate associated with
Standard and Poor's BBB rating. The rate of return must be the monthly
average rate as published in Standard and Poor's Bond Guide for the
first month for which the allowance is applicable. The rate must be
redetermined at the beginning of each subsequent calendar year.
(3) The washing allowance for coal shall be determined based on the
lessee's reasonable and actual cost of washing the coal. The lessee may
not take an allowance for the costs of washing lease production that is
not royalty bearing.
(c) Reporting requirements--(1) Arm's-length contracts. (i) The
lessee must notify MMS of an allowance based on incurred costs by using
a separate line entry on the Form MMS-4430.
(ii) The MMS may require that a lessee submit arm's-length washing
contracts and related documents. Documents shall be submitted within a
reasonable time, as determined by MMS.
(2) Non-arm's-length or no contract. (i) The lessee must notify MMS
of an allowance based on the incurred costs by using a separate line
entry on the Form MMS-4430.
(ii) For new washing facilities or arrangements, the lessee's
initial washing deduction shall include estimates of the allowable coal
washing costs for the applicable period. Cost estimates shall be based
upon the most recently available operations data for the washing system
or, if such data are not available, the lessee shall use estimates based
upon industry data for similar washing systems.
(iii) Upon request by MMS, the lessee shall submit all data used to
prepare the allowance deduction. The data shall be provided within a
reasonable period of time, as determined by MMS.
(d) Interest and assessments. (1) If a lessee nets a washing
allowance on the Form MMS-4430, then the lessee shall be assessed an
amount up to 10 percent of the allowance netted not to exceed $250 per
lease selling arrangement per sales period.
(2) If a lessee erroneously reports a washing allowance which
results in an underpayment of royalties, interest shall be paid on the
amount of that underpayment.
(3) Interest required to be paid by this section shall be determined
in accordance with 30 CFR 218.202.
(e) Adjustments. (1) If the actual coal washing allowance is less
than the amount the lessee has taken on Form MMS-4430 for each month
during the
[[Page 130]]
allowance reporting period, the lessee shall pay additional royalties
due plus interest computed under 30 CFR 218.202 from the date when the
lessee took the deduction to the date the lessee repays the difference
to MMS. If the actual washing allowance is greater than the amount the
lessee has taken on Form MMS-4430 for each month during the allowance
reporting period, the lessee shall be entitled to a credit without
interest.
(2) The lessee must submit a corrected Form MMS-4430 to reflect
actual costs, together with any payment, in accordance with instructions
provided by MMS.
(f) Other washing cost determinations. The provisions of this
section shall apply to determine washing costs when establishing value
using a net-back valuation procedure or any other procedure that
requires deduction of washing costs.
[54 FR 1523, Jan. 13, 1989, as amended at 57 FR 52720, Nov. 5, 1992; 61
FR 5480, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999; 66 FR 45769, Aug.
30, 2001]
Sec. 206.260 Allocation of washed coal.
(a) When coal is subjected to washing, the washed coal must be
allocated to the leases from which it was extracted.
(b) When the net output of coal from a washing plant is derived from
coal obtained from only one lease, the quantity of washed coal allocable
to the lease will be based on the net output of the washing plant.
(c) When the net output of coal from a washing plant is derived from
coal obtained from more than one lease, unless determined otherwise by
BLM, the quantity of net output of washed coal allocable to each lease
will be based on the ratio of measured quantities of coal delivered to
the washing plant and washed from each lease compared to the total
measured quantities of coal delivered to the washing plant and washed.
Sec. 206.261 Transportation allowances--general.
(a) For ad valorem leases subject to Sec. 206.257 of this subpart,
where the value for royalty purposes has been determined at a point
remote from the lease or mine, MMS shall, as authorized by this section,
allow a deduction in determining value for royalty purposes for the
reasonable, actual costs incurred to:
(1) Transport the coal from a Federal lease to a sales point which
is remote from both the lease and mine; or
(2) Transport the coal from a Federal lease to a wash plant when
that plant is remote from both the lease and mine and, if applicable,
from the wash plant to a remote sales point. In-mine transportation
costs shall not be included in the transportation allowance.
(b) Under no circumstances will the authorized washing allowance and
the transportation allowance reduce the value for royalty purposes to
zero.
(c)(1) When coal transported from a mine to a wash plant is eligible
for a transportation allowance in accordance with this section, the
lessee is not required to allocate transportation costs between the
quantity of clean coal output and the rejected waste material. The
transportation allowance shall be authorized for the total production
which is transported. Transportation allowances shall be expressed as a
cost per ton of cleaned coal transported.
(2) For coal that is not washed at a wash plant, the transportation
allowance shall be authorized for the total production which is
transported. Transportation allowances shall be expressed as a cost per
ton of coal transported.
(3) Transportation costs shall only be recognized as allowances when
the transported coal is sold and royalties are reported and paid.
(d) If, after a review and/or audit, MMS determines that a lessee
has improperly determined a transportation allowance authorized by this
section, then the lessee shall pay any additional royalties, plus
interest, determined in accordance with 30 CFR 218.202, or shall be
entitled to a credit, without interest.
(e) Lessees shall not disproportionately allocate transportation
costs to Federal leases.
[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5481, Feb. 12, 1996; 64
FR 43288, Aug. 10, 1999]
[[Page 131]]
Sec. 206.262 Determination of transportation allowances.
(a) Arm's-length contracts. (1) For transportation costs incurred by
a lessee pursuant to an arm's-length contract, the transportation
allowance shall be the reasonable, actual costs incurred by the lessee
for transporting the coal under that contract, subject to monitoring,
review, audit, and possible future adjustment. The lessee shall have the
burden of demonstrating that its contract is arm's-length. The lessee
must claim a transportation allowance by reporting it as a separate line
entry on the Form MMS-4430.
(2) In conducting reviews and audits, MMS will examine whether the
contract reflects more than the consideration actually transferred
either directly or indirectly from the lessee to the transporter for the
transportation. If the contract reflects more than the total
consideration paid, then the MMS may require that the transportation
allowance be determined in accordance with paragraph (b) of this
section.
(3) If the MMS determines that the consideration paid pursuant to an
arm's-length transportation contract does not reflect the reasonable
value of the transportation because of misconduct by or between the
contracting parties, or because the lessee otherwise has breached its
duty to the lessor to market the production for the mutual benefit of
the lessee and the lessor, then MMS shall require that the
transportation allowance be determined in accordance with paragraph (b)
of this section. When MMS determines that the value of the
transportation may be unreasonable, MMS will notify the lessee and give
the lessee an opportunity to provide written information justifying the
lessee's transportation costs.
(4) Where the lessee's payments for transportation under an arm's-
length contract are not based on a dollar-per-unit basis, the lessee
shall convert whatever consideration is paid to a dollar value
equivalent for the purposes of this section.
(b) Non-arm's-length or no contract--(1) If a lessee has a non-
arm's-length contract or has no contract, including those situations
where the lessee performs transportation services for itself, the
transportation allowance will be based upon the lessee's reasonable
actual costs. All transportation allowances deducted under a non-arm's-
length or no contract situation are subject to monitoring, review,
audit, and possible future adjustment. The lessee must claim a
transportation allowance by reporting it as a separate line entry on the
Form MMS-4430. When necessary or appropriate, MMS may direct a lessee to
modify its estimated or actual transportation allowance deduction.
(2) The transportation allowance for non-arm's-length or no-contract
situations shall be based upon the lessee's actual costs for
transportation during the reporting period, including operating and
maintenance expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph
(b)(2)(iv)(A) of this section, or a cost equal to the depreciable
investment in the transportation system multiplied by the rate of return
in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable
capital costs are generally those for depreciable fixed assets
(including costs of delivery and installation of capital equipment)
which are an integral part of the transportation system.
(i) Allowable operating expenses include: Operations supervision and
engineering; operations labor; fuel; utilities; materials; ad valorem
property taxes; rent; supplies; and any other directly allocable and
attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the
transportation system; maintenance of equipment; maintenance labor; and
other directly allocable and attributable maintenance expenses which the
lessee can document.
(iii) Overhead attributable and allocable to the operation and
maintenance of the transportation system is an allowable expense. State
and Federal income taxes and severance taxes and other fees, including
royalties, are not allowable expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or paragraph
(b)(2)(iv)(B) of this section. After a lessee has elected to use either
method for
[[Page 132]]
a transportation system, the lessee may not later elect to change to the
other alternative without approval of the MMS.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the transportation system services,
whichever is appropriate, or a unit of production method. After an
election is made, the lessee may not change methods without MMS
approval. A change in ownership of a transportation system shall not
alter the depreciation schedule established by the original transporter/
lessee for purposes of the allowance calculation. With or without a
change in ownership, a transportation system shall be depreciated only
once. Equipment shall not be depreciated below a reasonable salvage
value.
(B) The MMS shall allow as a cost an amount equal to the allowable
capital investment in the transportation system multiplied by the rate
of return determined pursuant to paragraph (b)(2)(B)(v) of this section.
No allowance shall be provided for depreciation. This alternative shall
apply only to transportation facilities first placed in service or
acquired after March 1, 1989.
(v) The rate of return must be the industrial rate associated with
Standard and Poor's BBB rating. The rate of return must be the monthly
average rate as published in Standard and Poor's Bond Guide for the
first month for which the allowance is applicable. The rate must be
redetermined at the beginning of each subsequent calendar year.
(3) A lessee may apply to MMS for exception from the requirement
that it compute actual costs in accordance with paragraphs (b)(1) and
(b)(2) of this section. MMS will grant the exception only if the lessee
has a rate for the transportation approved by a Federal agency or by a
State regulatory agency (for Federal leases). MMS shall deny the
exception request if it determines that the rate is excessive as
compared to arm's-length transportation charges by systems, owned by the
lessee or others, providing similar transportation services in that
area. If there are no arm's-length transportation charges, MMS shall
deny the exception request if:
(i) No Federal or State regulatory agency costs analysis exists and
the Federal or State regulatory agency, as applicable, has declined to
investigate under MMS timely objections upon filing; and
(ii) The rate significantly exceeds the lessee's actual costs for
transportation as determined under this section.
(c) Reporting requirements--(1) Arm's-length contracts. (i) The
lessee must notify MMS of an allowance based on incurred costs by using
a separate line entry on the Form MMS-4430.
(ii) The MMS may require that a lessee submit arm's-length
transportation contracts, production agreements, operating agreements,
and related documents. Documents shall be submitted within a reasonable
time, as determined by MMS.
(2) Non-arm's-length or no contract--(i) The lessee must notify MMS
of an allowance based on the incurred costs by using a separate line
entry on Form MMS-4430.
(ii) For new transportation facilities or arrangements, the lessee's
initial deduction shall include estimates of the allowable coal
transportation costs for the applicable period. Cost estimates shall be
based upon the most recently available operations data for the
transportation system or, if such data are not available, the lessee
shall use estimates based upon industry data for similar transportation
systems.
(iii) Upon request by MMS, the lessee shall submit all data used to
prepare the allowance deduction. The data shall be provided within a
reasonable period of time, as determined by MMS.
(iv) If the lessee is authorized to use its Federal- or State-
agency-approved rate as its transportation cost in accordance with
paragraph (b)(3) of this section, it shall follow the reporting
requirements of paragraph (c)(1) of this section.
(d) Interest and assessments. (1) If a lessee nets a transportation
allowance on Form MMS-4430, the lessee shall be assessed an amount of up
to 10 percent of the allowance netted not to exceed $250 per lease
selling arrangement per sales period.
[[Page 133]]
(2) If a lessee erroneously reports a transportation allowance which
results in an underpayment of royalties, interest shall be paid on the
amount of that underpayment.
(3) Interest required to be paid by this section shall be determined
in accordance with 30 CFR 218.202.
(e) Adjustments. (1) If the actual coal transportation allowance is
less than the amount the lessee has taken on Form MMS-4430 for each
month during the allowance reporting period, the lessee shall pay
additional royalties due plus interest computed under 30 CFR 218.202
from the date when the lessee took the deduction to the date the lessee
repays the difference to MMS. If the actual transportation allowance is
greater than amount the lessee has taken on Form MMS-4430 for each month
during the allowance reporting period, the lessee shall be entitled to a
credit without interest.
(2) The lessee must submit a corrected Form MMS-4430 to reflect
actual costs, together with any payments, in accordance with
instructions provided by MMS.
(f) Other transportation cost determinations. The provisions of this
section shall apply to determine transportation costs when establishing
value using a net-back valuation procedure or any other procedure that
requires deduction of transportation costs.
[54 FR 1523, Jan. 13, 1989, as amended at 57 FR 41864, Sept. 14, 1992;
57 FR 52720, Nov. 5, 1992; 61 FR 5481, Feb. 12, 1996; 64 FR 43288, Aug.
10, 1999; 66 FR 45769, Aug. 30, 2001]
Sec. 206.263 [Reserved]
Sec. 206.264 In-situ and surface gasification and liquefaction operations.
If an ad valorem Federal coal lease is developed by in-situ or
surface gasification or liquefaction technology, the lessee shall
propose the value of coal for royalty purposes to MMS. The MMS will
review the lessee's proposal and issue a value determination. The lessee
may use its proposed value until MMS issues a value determination.
[54 FR 1523, Jan. 13, 1989, as amended at 65 FR 43289, Aug. 10, 1999]
Sec. 206.265 Value enhancement of marketable coal.
If, prior to use, sale, or other disposition, the lessee enhances
the value of coal after the coal has been placed in marketable condition
in accordance with Sec. 206.257(h) of this subpart, the lessee shall
notify MMS that such processing is occurring or will occur. The value of
that production shall be determined as follows:
(a) A value established for the feedstock coal in marketable
condition by application of the provisions of Sec. 206.257(c)(2)(i-iv)
of this subpart; or,
(b) In the event that a value cannot be established in accordance
with subsection (a), then the value of production will be determined in
accordance with Sec. 206.257(c)(2)(v) of this subpart and the value
shall be the lessee's gross proceeds accruing from the disposition of
the enhanced product, reduced by MMS-approved processing costs and
procedures including a rate of return on investment equal to two times
the Standard and Poor's BBB bond rate applicable under Sec.
206.259(b)(2)(v) of this subpart.
Subpart G_Other Solid Minerals
Sec. 206.301 Value basis for royalty computation.
(a) The gross value for royalty purposes shall be the sale or
contract unit price times the number of units sold, Provided, however,
That where the authorized officer determines:
(1) That a contract of sale or other business arrangement between
the lessee and a purchaser of some or all of the commodities produced
from the lease is not a bona fide transaction between independent
parties because it is based in whole or in part upon considerations
other than the value of the commodities, or
(2) That no bona fide sales price is received for some or all of
such commodities because the lessee is consuming them, the authorized
officer shall determine their gross value, taking into account: (i) All
prices received by the lessee in all bona fide transactions, (ii) Prices
paid for commodities of like quality produced from the same general
area, and (iii) Such other relevant factors as the authorized officer
may
[[Page 134]]
deem appropriate; and Provided further, That in a situation where an
estimated value is used, the authorized officer shall require the
payment of such additional royalties, or allow such credits or refunds
as may be necessary to adjust royalty payment to reflect the actual
gross value.
(b) The lessee is required to certify that the values reported for
royalty purposes are bona fide sales not involving considerations other
than the sale of the mineral, and he may be required by the authorized
officer to supply supporting information.
[43 FR 10341, Mar. 13, 1978. Redesignated at 48 FR 36588, Aug. 12, 1983,
and amended at 48 FR 44795, Sept. 30, 1983. Further redesignated at 51
FR 15212, Apr. 22, 1986. Redesignated at 53 FR 39461, Oct. 7, 1988]
Subpart H_Geothermal Resources
Source: 72 FR 24459, May 2, 2007, unless otherwise noted.
Sec. 206.350 What is the purpose of this subpart?
(a) This subpart applies to all geothermal resources produced from
Federal geothermal leases issued pursuant to the Geothermal Steam Act of
1970 (GSA), as amended by the Energy Policy Act of 2005 (EPAct) (30
U.S.C. 1001 et seq.). The purpose of this subpart is to prescribe how to
calculate royalties and direct use fees for geothermal production.
(b) The MMS may audit and adjust all royalty and fee payments.
(c) In some cases, the regulations in this subpart may be
inconsistent with a statute, settlement agreement, written agreement, or
lease provision. If this happens, the statute, settlement agreement,
written agreement, or lease provision will govern to the extent of the
inconsistency. For purposes of this paragraph, the following definitions
apply:
(1) ``Settlement agreement'' means a settlement agreement between
the United States and a lessee resulting from administrative or judicial
litigation.
(2) ``Written agreement'' means a written agreement between the
lessee and the MMS Director or Assistant Secretary, Land and Minerals
Management of the Department of the Interior that:
(i) Establishes a method to determine the royalty from any lease
that MMS expects at least would approximate the value or royalty
established under this subpart; and
(ii) Includes a value or gross proceeds determination under Sec.
206.364 of this subpart.
Sec. 206.351 What definitions apply to this subpart?
For purposes of this subpart, the following terms have the meanings
indicated.
Affiliate means a person who controls, is controlled by, or is under
common control with another person. For purposes of this subpart:
(1) Ownership or common ownership of more than 50 percent of the
voting securities, or instruments of ownership, or other forms of
ownership, of another person constitutes control. Ownership of less than
10 percent constitutes a presumption of noncontrol that MMS may rebut.
(2) If there is ownership or common ownership of 10 through 50
percent of the voting securities, or instruments of ownership, or other
forms of ownership of another person, MMS will consider the following
factors in determining whether there is control under the circumstances
of a particular case:
(i) The extent to which there are common officers or directors;
(ii) With respect to the voting securities, or instruments of
ownership, or other forms of ownership: the percentage of ownership or
common ownership, the relative percentage of ownership or common
ownership compared to the percentage(s) of ownership by other persons,
whether a person is the greatest single owner, or whether there is an
opposing voting bloc of greater ownership;
(iii) Operation of a lease, plant, pipeline, or other facility;
(iv) The extent of participation by other owners in operations and
day-to-day management of a lease, plant, pipeline, or other facility;
and
(v) Other evidence of power to exercise control over or common
control with another person.
[[Page 135]]
(3) Regardless of any percentage of ownership or common ownership,
relatives, either by blood or marriage, are affiliates.
Allowance means a deduction in determining value for royalty
purposes.
Arm's-length contract means a contract or agreement between
independent persons who are not affiliates and who have opposing
economic interests regarding that contract. To be considered arm's
length for any production month, a contract must satisfy this definition
for that month, as well as when the contract was executed.
Audit means a review, conducted in accordance with generally
accepted accounting and auditing standards, of royalty or fee payment
compliance activities of lessees or other interest holders who pay
royalties, fees, rents, or bonuses on Federal geothermal leases.
Byproducts means minerals (exclusive of oil, hydrocarbon gas, and
helium), found in solution or in association with geothermal steam, that
no person would extract and produce by themselves because they are worth
less than 75 percent of the value of the geothermal steam or because
extraction and production would be too difficult.
Byproduct recovery facility means a facility where byproducts are
placed in marketable condition.
Byproduct transportation allowance means an allowance for the
reasonable, actual costs of moving byproducts to a point of sale or
delivery off the lease, unit area, or communitized area, or away from a
byproduct recovery facility. The byproduct transportation allowance does
not include gathering costs. You must report a byproduct transportation
allowance as a separate discrete field on the Form MMS-2014.
Class I lease means:
(1) A lease that BLM issued before August 8, 2005, for which the
lessee has not converted the royalty rate terms under 43 CFR 3212.25; or
(2) A lease that BLM issued in response to an application that was
pending on August 8, 2005, for which the lessee has not made an election
under 43 CFR 3200.8(b).
Class II lease means:
A lease that BLM issued after August 8, 2005, except for a lease
issued in response to an application that was pending on August 8, 2005,
for which the lessee does not make an election under 43 CFR 3200.8(b).
Class III lease means:
A lease that BLM issued before August 8, 2005, for which the lessee
has converted to the royalty rate or direct use fee terms under 43 CFR
3212.25.
Commercial production or generation of electricity means generation
of electricity that is sold or is subject to sale, including the
electricity or energy that is reasonably required to produce the
resource used in production of electricity for sale or to convert
geothermal energy into electrical energy for sale.
Contract means any oral or written agreement, including amendments
or revisions thereto, between two or more persons and enforceable by law
that with due consideration creates an obligation.
Deduction means a subtraction the lessee uses to determine the value
of geothermal resources produced from a Class I lease that the lessee
uses to generate electricity.
Delivered electricity means the amount of electricity in kilowatt-
hours delivered to the purchaser.
Direct use means the utilization of geothermal resources for
commercial, residential, agricultural, public facilities, or other
energy needs, other than the commercial production or generation of
electricity.
Direct use facility means a facility that uses the heat or other
energy of the geothermal resource for direct use purposes.
Electrical facility means a power plant or other facility that uses
a geothermal resource to generate electricity.
Field means the land surface vertically projected over a subsurface
geothermal reservoir encompassing at least the outermost boundaries of
all geothermal accumulations known to be within that reservoir.
Geothermal fields are usually given names and their official boundaries
are often designated by regulatory agencies in the respective States in
which the fields are located.
[[Page 136]]
Gathering means the movement of lease production from the wellhead
to the point of utilization.
Generating deduction means a deduction for the lessee's reasonable,
actual costs of generating plant tailgate electricity.
Geothermal resources means:
(1) All products of geothermal processes, including indigenous
steam, hot water, and hot brines;
(2) Steam and other gases, hot water, and hot brines resulting from
water, gas, or other fluids artificially introduced into geothermal
formations;
(3) Heat or other associated energy found in geothermal formations;
and
(4) Any byproducts.
Gross proceeds (for royalty payment purposes) means the total monies
and other consideration accruing to a geothermal lessee for the sale of
electricity or geothermal resource. Gross proceeds includes, but is not
limited to:
(1) Payments to the lessee for certain services such as effluent
injection, field operation and maintenance, drilling or workover of
wells, or field gathering to the extent that the lessee is obligated to
perform such functions at no cost to the Federal Government;
(2) Reimbursements for production taxes and other taxes. Tax
reimbursements are part of gross proceeds accruing to a lessee even
though the Federal royalty interest may be exempt from taxation; and
(3) Any monies and other consideration, including the forms of
consideration identified in this paragraph, to which a lessee is
contractually or legally entitled but which it does not seek to collect
through reasonable efforts.
Lease means a geothermal lease issued under the authority of the
GSA, unless the context indicates otherwise.
Lessee (you) means any person to whom the United States issues a
geothermal lease, and any person who has been assigned an obligation to
make royalty, fee, or other payments required by the lease. This
includes any person who has an interest in a geothermal lease as well as
an operator or payor who has no interest in the lease but who has
assumed the royalty, fee, or other payment responsibility. This also
includes any affiliate of the lessee that uses the geothermal resource
to generate electricity, in a direct use process, or to recover
byproducts, or any affiliate that sells or transports lease production.
Marketable condition means lease products that are sufficiently free
from impurities and otherwise in a condition that they will be accepted
by a purchaser under a sales contract typical for the disposition from
the field or area of such lease products.
Person means any individual, firm, corporation, association,
partnership, consortium, or joint venture (when established as a
separate entity).
Plant parasitic electricity means electricity used to operate a
power plant that is used for commercial production or generation of
electricity.
Plant tailgate electricity means the amount of electricity in
kilowatt-hours generated by a power plant exclusive of plant parasitic
electricity, but inclusive of any electricity generated by the power
plant and returned to the lease for lease operations. Plant tailgate
electricity should be measured at, or calculated for, the high voltage
side of the transformer in the plant switchyard.
Point of utilization means the power plant or direct use facility in
which the geothermal resource is utilized.
Public purpose means a program carried out by a State, tribal, or
local government for the purpose of providing facilities or services for
the benefit of the public in connection with, but not limited to, public
health, safety or welfare, other than the commercial generation of
electricity. Use of lands or facilities for habitation, cultivation,
trade or manufacturing is permissible only when necessary for and
integral to (i.e., an essential part of) the public purpose.
Public safety or welfare means a program carried out or promoted by
a public agency for public purposes involving, directly or indirectly,
protection, safety, and law enforcement activities, and the criminal
justice system of a given political area. Public safety or welfare may
include, but is not limited to, programs carried out by:
(1) Public police departments;
(2) Sheriffs' offices;
(3) The courts;
[[Page 137]]
(4) Penal and correctional institutions (including juvenile
facilities);
(5) State and local civil defense organizations; and
(6) Fire departments and rescue squads (including volunteer fire
departments and rescue squads supported in whole or in part with public
funds).
Reasonable alternative fuel means a conventional fuel (such as coal,
oil, gas, or wood) that would normally be used as a source of heat in
direct use operations.
Secretary means the Secretary of the Interior or any person duly
authorized to exercise the powers vested in that office.
Transmission deduction means a deduction for the lessee's reasonable
actual costs incurred to wheel or transmit the electricity from the
lessee's power plant to the purchaser's delivery point.
Wheeling means the transmission of electricity from a power plant to
the point of delivery.
Sec. 206.352 How do I calculate the royalty due on geothermal resources used
for commercial production or generation of electricity?
(a) If you sold geothermal resources produced from a Class I, II, or
III lease at arm's length that the purchaser uses to generate
electricity, then the royalty on the geothermal resources is the gross
proceeds accruing to you from the sale of the geothermal resource to the
arm's-length purchaser multiplied by either:
(1) The royalty rate in your lease; or
(2) The royalty rate that BLM prescribes or calculates under 43 CFR
3211.17. See Sec. 206.361 for additional provisions applicable to
determining gross proceeds under arm's-length sales.
(b) If you use the geothermal resource in your own power plant for
the generation and sale of electricity, the following provisions apply
(1) For Class I leases, you must determine the royalty on produced
geothermal resources in accordance with the first applicable of the
following paragraphs:
(i) The gross proceeds accruing to you from the arm's-length sale of
the electricity less applicable deductions determined under Sec.
206.353 and Sec. 206.354 of this part, multiplied by the royalty rate
in your lease. See Sec. 206.361 for additional provisions applicable to
determining gross proceeds under arm's-length sales. Under no
circumstances may the deductions reduce the royalty value of the
geothermal resource to zero; or
(ii) A royalty determined by any other reasonable method approved by
MMS under Sec. 206.364 of this subpart.
(2) For Class II and Class III leases, the royalty on geothermal
resources produced is your gross proceeds from the sale of electricity
multiplied by the royalty rate BLM prescribed for your lease under 43
CFR 3211.17. See Sec. 206.361 for additional provisions applicable to
determining gross proceeds under arm's-length sales. You may not reduce
gross proceeds by any deductions.
Sec. 206.353 How do I determine transmission deductions?
(a) If you determine the value of your geothermal resources under
Sec. 206.352(b)(1)(i) of this subpart, you may subtract a transmission
deduction from the gross proceeds you received for the sale of
electricity to determine the plant tailgate value of the electricity.
(1) The transmission deduction consists of either or both of two
components:
(i) Transmission line costs as determined under paragraph (b) of
this section; and
(ii) Wheeling costs if the electricity is transmitted across a third
party's transmission line under an arm's-length wheeling agreement.
(2) You may deduct the actual costs you (including your
affiliate(s)) incur for transmitting electricity under your arm's-length
wheeling contract.
(b) To determine your transmission line cost, you must follow the
requirements of paragraphs (b)(1) and (b)(2) of this section.
(1) Your transmission line costs are your actual costs associated
with the construction and operation of a transmission line for the
purpose of transmitting electricity attributable and allocable to your
power plant utilizing Federal geothermal resources.
(i) You must determine the monthly transmission line cost component
of
[[Page 138]]
the transmission deduction by multiplying the annual transmission line
cost rate (in dollars per kilowatt-hour) by the amount of electricity
delivered for the reporting month.
(ii) You must redetermine the transmission line cost rate annually
either at the beginning of the same month of the year in which the power
plant was placed into service or at a time concurrent with the beginning
of your annual corporate accounting period. The period you select must
coincide with the same period you chose for the generating deduction
under Sec. 206.354(b)(1). After you choose a deduction period, you may
not later elect to use a different deduction period without MMS
approval.
(2) Your actual transmission line costs during the reporting period
include:
(i) Operating and maintenance expenses under paragraphs (d) and (e)
of this section;
(ii) Overhead under paragraph (f) of this section; and either
(iii) Depreciation under paragraphs (g) and (h) of this section and
a return on undepreciated capital investment under paragraphs (g) and
(i) of this section or
(iv) A return on the capital investment in the transmission line
under paragraphs (g) and (j) of this section.
(c)(1) Allowable capital costs under paragraph (b) of this section
are generally those for depreciable fixed assets (including costs of
delivery and installation of capital equipment) that are an integral
part of the transmission line.
(2)(i) You may include a return on capital you invested in the
purchase of real estate for transmission facilities if:
(A) Such purchase is necessary; and
(B) The surface is not part of the Federal lease.
(ii) The rate of return will be the same rate determined under
paragraph (k) of this section.
(d) Allowable operating expenses include:
(1) Operations supervision and engineering;
(2) Operations labor;
(3) Fuel;
(4) Utilities;
(5) Materials;
(6) Ad valorem property taxes;
(7) Rent;
(8) Supplies; and
(9) Any other directly allocable and attributable operating or
maintenance expense that you can document.
(e) Allowable maintenance expenses include:
(1) Maintenance of the transmission line;
(2) Maintenance of equipment;
(3) Maintenance labor; and
(4) Other directly allocable and attributable maintenance expenses
that you can document.
(f) Overhead directly attributable and allocable to the operation
and maintenance of the transmission line is an allowable expense. State
and Federal income taxes and severance taxes and other fees, including
royalties, are not allowable expenses.
(g) To compute costs associated with capital investment, a lessee
may use either depreciation with a return on undepreciated capital
investment, or a return on capital investment in the transmission line.
After a lessee has elected to use either method, the lessee may not
later elect to change to the other alternative without MMS approval.
(h)(1) To compute depreciation, you must use a straight-line
depreciation method based on the life of the geothermal project, usually
the term of the electricity sales contract, or other depreciation period
acceptable to MMS. You may not depreciate equipment below a reasonable
salvage value.
(2) A change in ownership of a transmission line does not alter the
depreciation schedule established by the original lessee-owner for
purposes of computing transmission line costs.
(3) With or without a change in ownership, you may depreciate a
transmission line only once.
(i) To calculate a return on undepreciated capital investment,
multiply the remaining undepreciated capital balance as of the beginning
of the period for which you are calculating the transmission deduction
by the rate of return provided in paragraph (k) of this section.
(j) To compute a return on capital investment in the transmission
line,
[[Page 139]]
multiply the allowable capital investment in the transmission line by
the rate of return determined pursuant to paragraph (k) of this section.
There is no allowance for depreciation.
(k) The rate of return must be 2.0 multiplied by the industrial rate
associated with Standard & Poor's BBB rating. The BBB rate must be the
monthly average rate as published in Standard & Poor's Bond Guide for
the first month for which the allowance is applicable. Redetermine the
rate at the beginning of each subsequent calendar year.
(l) Calculate the deduction for transmission costs based on your
cost of transmitting electricity through each individual transmission
line.
(m)(1) For new transmission facilities or arrangements, base your
initial deduction on estimates of allowable electricity transmission
costs for the applicable period. Use the most recently available
operations data for the transmission line or, if such data are not
available, use estimates based on data for similar transmission lines.
(2) When actual cost information is available, you must amend your
prior Form MMS-2014 reports to reflect actual transmission costs
deductions for each month for which you reported and paid based on
estimated transmission costs. You must pay any additional royalties due
(together with interest computed under Sec. 218.302). You are entitled
to a credit for or refund of any overpaid royalties.
(n) In conducting reviews and audits, MMS may require you to submit
arm's-length transmission contracts, production agreements, operating
agreements, and related documents and all other data used to calculate
the deduction. You must comply with any such requirements within the
time MMS specifies. Recordkeeping requirements are found at part 212 of
this chapter.
(o) At the completion of transmission line dismantlement and salvage
operations, you may report a credit for or request a refund of royalties
in an amount equal to the royalty rate times the amount by which actual
transmission line dismantlement costs exceed actual income attributable
to salvage of the transmission line.
Sec. 206.354 How do I determine generating deductions?
(a) If you determine the value of your geothermal resources under
Sec. 206.352(b)(1)(i) of this subpart, you may deduct your reasonable
actual costs incurred to generate electricity from the plant tailgate
value of the electricity (usually the transmission-reduced value of the
delivered electricity). You may deduct the actual costs you incur for
generating electricity under your arm's-length power plant contract.
(b)(1) You must base your generating costs deduction on your actual
annual costs associated with the construction and operation of a
geothermal power plant.
(i) You must determine your monthly generating deduction by
multiplying the annual generating cost rate (in dollars per kilowatt-
hour) by the amount of plant tailgate electricity measured (or computed)
for the reporting month. The generating cost rate is determined from the
annual amount of your plant tailgate electricity.
(ii) You must redetermine your generating cost rate annually either
at the beginning of the same month of the year in which the power plant
was placed into service or at a time concurrent with the beginning of
your annual corporate accounting period. The period you select must
coincide with the same period chosen for the transmission deduction
under Sec. 206.353(b)(1). After you choose a deduction period, you may
not later elect to use a different deduction period without MMS
approval.
(2) Your generating costs are your actual power plant costs during
the reporting period, including:
(i) Operating and maintenance expenses under paragraphs (d) and (e)
of this section;
(ii) Overhead under paragraph (f) of this section; and either
(iii) Depreciation under paragraphs (g) and (h) of this section and
a return on undepreciated capital investment under paragraphs (g) and
(i) of this section; or
(iv) A return on capital investment in the power plant under
paragraphs (g) and (j) of this section.
[[Page 140]]
(c)(1) Allowable capital costs under paragraph (b) of this section
are generally those for depreciable fixed assets (including costs of
delivery and installation of capital equipment) that are an integral
part of the power plant or are required by the design specifications of
the power conversion cycle.
(2)(i) You may include a return on capital you invested in the
purchase of real estate for a power plant site if:
(A) The purchase is necessary; and,
(B) The surface is not part of the Federal lease.
(ii) The rate of return will be the same rate determined under
paragraph (k) of this section.
(3) You may not deduct the costs of gathering systems and other
production-related facilities.
(d) Allowable operating expenses include:
(1) Operations supervision and engineering;
(2) Operations labor;
(3) Auxiliary fuel and/or utilities used to operate the power plant
during down time;
(4) Utilities;
(5) Materials;
(6) Ad valorem property taxes;
(7) Rent;
(8) Supplies; and
(9) Any other directly allocable and attributable operating expense.
(e) Allowable maintenance expenses include:
(1) Maintenance of the power plant;
(2) Maintenance of equipment;
(3) Maintenance labor; and
(4) Other directly allocable and attributable maintenance expenses
that you can document.
(f) Overhead directly attributable and allocable to the operation
and maintenance of the power plant is an allowable expense. State and
Federal income taxes and severance taxes and other fees, including
royalties, are not allowable expenses.
(g) To compute costs associated with capital investment, a lessee
may use either depreciation with a return on undepreciated capital
investment, or a return on capital investment in the power plant. After
a lessee has elected to use either method, the lessee may not later
elect to change to the other alternative without MMS approval.
(h)(1) To compute depreciation, you must use a straight-line
depreciation method based on the life of the geothermal project, usually
the term of the electricity sales contract, or other depreciation period
acceptable to MMS. You may not depreciate equipment below a reasonable
salvage value.
(2) A change in ownership of the power plant does not alter the
depreciation schedule established by the original lessee-owner for
purposes of computing generating costs.
(3) With or without a change in ownership, you may depreciate a
power plant only once.
(i) To calculate a return on undepreciated capital investment,
multiply the remaining undepreciated capital balance as of the beginning
of the period for which you are calculating the generating deduction
allowance by the rate of return provided in paragraph (k) of this
section.
(j) To compute a return on capital investment in the power plant,
multiply the allowable capital investment in the power plant by the rate
of return determined pursuant to paragraph (k) of this section. There is
no allowance for depreciation.
(k) The rate of return must be 2.0 multiplied by the industrial rate
associated with Standard & Poor's BBB rating. The BBB rate must be the
monthly average rate as published in Standard & Poor's Bond Guide for
the first month for which the allowance is applicable. You must
redetermine the rate at the beginning of each subsequent calendar year.
(l) Calculate the deduction for generating costs based on your cost
of generating electricity through each individual power plant.
(m)(1) For new power plants or arrangements, base your initial
deduction on estimates of allowable electricity generation costs for the
applicable period. Use the most recently available operations data for
the power plant or, if such data are not available, use estimates based
on data for similar power plants.
(2) When actual cost information is available, you must amend your
prior Form MMS-2014 reports to reflect actual generating cost deductions
for each month for which you reported and
[[Page 141]]
paid based on estimated generating costs. You must pay any additional
royalties due (together with interest computed under Sec. 218.302). You
are entitled to a credit for or refund of any overpaid royalties.
(n) In conducting reviews and audits, MMS may require you to submit
arm's-length power plant contracts, production agreements, operating
agreements, related documents and all other data used to calculate the
deduction. You must comply with any such requirements within the time
MMS specifies. Recordkeeping requirements are found at part 212 of this
chapter.
(o) At the completion of power plant dismantlement and salvage
operations, you may report a credit for or request a refund of royalty
in an amount equal to the royalty rate times the amount by which actual
power plant dismantlement costs exceed actual income attributable to
salvage of the power plant.
Sec. 206.355 How do I calculate royalty due on geothermal resources I sell
at arm's length to a purchaser for direct use?
If you sell geothermal resources produced from Class I, II, or III
leases at arm's length to a purchaser for direct use, then the royalty
on the geothermal resource is the gross proceeds accruing to you from
the sale of the geothermal resource to the arm's-length purchaser
multiplied by the royalty rate in your lease or that BLM prescribes
under 43 CFR 3211.18. See Sec. 206.361 for additional provisions
applicable to determining gross proceeds under arm's-length sales.
Sec. 206.356 How do I calculate royalty or fees due on geothermal resources
I use for direct use purposes?
If you use the geothermal resource for direct use:
(a) For Class I leases, you must determine the royalty due on
geothermal resources in accordance with the first applicable of the
following three paragraphs.
(1) The weighted average of the gross proceeds established in arm's-
length contracts for the purchase of significant quantities of
geothermal resources to operate the lessee's same direct-use facility
multiplied by the royalty rate in your lease. In evaluating the
acceptability of arm's-length contracts, the following factors will be
considered: time of execution, duration, terms, volume, quality of
resource, and such other factors as may be appropriate to reflect the
value of the resource.
(2) The equivalent value of the least expensive, reasonable
alternative energy source (fuel) multiplied by the royalty rate in your
lease. The equivalent value of the least expensive, reasonable
alternative energy source will be based on the amount of thermal energy
that would otherwise be used by the direct use facility in place of the
geothermal resource. That amount of thermal energy (in Btu) displaced by
the geothermal resource will be determined by the equation:
[GRAPHIC] [TIFF OMITTED] TR02MY07.003
Where hin is the enthalpy in Btu/lb at the direct use
facility inlet (based on measured inlet temperature), hout is
the enthalpy in Btu/lb at the facility outlet (based on measured outlet
temperature), density is in lbs/cu ft based on inlet temperature, the
factor 0.113681 (cu ft/gal) converts gallons to cubic feet, and volume
is the quantity of geothermal fluid in gallons produced at the wellhead
or measured at an approved point. The efficiency factor of the
alternative energy source will be 0.7 for coal and 0.8 for oil, natural
gas, and other fuels derived from oil and natural gas, or an efficiency
factor proposed by the lessee and approved by
[[Page 142]]
MMS. The methods of measuring resource parameters (temperature, volume,
etc.) and the frequency of computing and accumulating the amount of
thermal energy displaced will be determined and approved by BLM under 43
CFR 3275.13-3275.17.
(3) A royalty determined by any other reasonable method approved by
MMS or the Assistant Secretary, Land and Minerals Management of the
Department of the Interior, under Sec. 206.364 of this part.
(b) For geothermal resources produced from Class II and Class III
leases, you must multiply the appropriate fee from the schedule in
subparagraph (b)(1) of this section by the number of gallons or pounds
you produce from the direct use lease each month.
(1) You must use the following fee schedule to calculate fees due
under this section:
Direct Use Fee Schedule
[Hot water]
----------------------------------------------------------------------------------------------------------------
If your average monthly inlet temperature ( [deg]F) is Your fees are . . .
----------------------------------------------------------------------------------------------------------------
But less than ($/million ($/million
At least . . . . . . gallons) pounds)
----------------------------------------------------------------------------------------------------------------
130............................................................. 140 2.524 0.307
140............................................................. 150 7.549 0.921
150............................................................. 160 12.543 1.536
160............................................................. 170 17.503 2.150
170............................................................. 180 22.426 2.764
180............................................................. 190 27.310 3.379
190............................................................. 200 32.153 3.993
200............................................................. 210 36.955 4.607
210............................................................. 220 41.710 5.221
220............................................................. 230 46.417 5.836
230............................................................. 240 51.075 6.450
240............................................................. 250 55.682 7.064
250............................................................. 260 60.236 7.679
260............................................................. 270 64.736 8.293
270............................................................. 280 69.176 8.907
280............................................................. 290 73.558 9.521
290............................................................. 300 77.876 10.136
300............................................................. 310 82.133 10.750
310............................................................. 320 86.328 11.364
320............................................................. 330 90.445 11.979
330............................................................. 340 94.501 12.593
340............................................................. 350 98.481 13.207
350............................................................. 360 102.387 13.821
----------------------------------------------------------------------------------------------------------------
(i) For direct use geothermal resources with an average monthly
inlet temperature of 130 [deg]F or less, you must pay only the lease
rental.
(ii) The MMS, in consultation with BLM, will develop and publish a
revised fee schedule in the Federal Register, as needed.
(iii) The MMS, in consultation with BLM, will calculate revised fees
schedules using the following formulas:
[GRAPHIC] [TIFF OMITTED] TR02MY07.004
Where:
RV = Royalty due as a function of produced volume in the fee
schedule, expressed as dollars per million (10\6\) gallons;
[[Page 143]]
Rm = Royalty due as a function of produced mass in the fee
schedule, expressed as dollars per million (10\6\) pounds;
[rho][rho] = Water density at inlet temperature expressed as lbs per
gallon;
Tin = Measured inlet temperature in [deg]F (as required by
BLM under 43 CFR part 3275);
Tout = Established assumed outlet temperature of 130[deg] F;
e = Boiler Efficiency Factor for coal of 70 percent;
Pprbc = The 3-year historical average of Powder River Basin
spot coal prices, as published by the Energy Information Administration,
or other recognized authoritative reference source of coal prices, in
dollars (per MMBtu);
Frr = The assumed Lease Royalty Rate of 10 percent.
(2) The fee that you report is subject to monitoring, review, and
audit.
(3) The schedule of fees established under this paragraph will apply
to any Class III lease with respect to any royalty payments previously
made when the lease was a Class I lease that were due and owing, and
were paid, on or after July 16, 2003. To use this provision, you must
provide MMS data showing the amount of geothermal production in pounds
or gallons of geothermal fluid to input into the fee schedule (see 43
CFR part 3276).
(i) If the royalties you previously paid are less than the fees due
under this section, you must pay the difference plus interest on that
difference computed under Sec. 218.302.
(ii) If the royalties you previously paid are more than the fees due
under this section, then you are entitled to a refund or credit from MMS
of 50 percent of the overpaid royalties. You are also entitled to a
refund or credit of any interest that you paid on the overpaid
royalties.
(c) For geothermal resources other than hot water, MMS will
determine fees on a case-by-case basis.
Sec. 206.357 How do I calculate royalty due on byproducts?
(a) If you sell byproducts, you must determine the royalty due on
the byproducts that are royalty-bearing under:
(1) Applicable lease terms of Class I leases and of Class III leases
that do not elect to be subject to all of the BLM regulations
promulgated for leases issued after August 8, 2005, under 43 CFR
3200.7(a)(2), or
(2) Applicable statutory provisions at 30 U.S.C. 1004(a)(2) for
Class II leases and for Class III leases that do elect to be subject to
all of the BLM regulations promulgated for leases issued after August 8,
2005, under 43 CFR 3200.7(a)(2).
(b) You must determine the royalty due on the byproducts by
multiplying the royalty rate in your lease or that BLM prescribes under
43 CFR 3211.19 by a value of the byproducts determined in accordance
with the first applicable of the following subparagraphs:
(1) The gross proceeds accruing to you from the arm's-length sale of
the byproducts, less any applicable byproduct transportation allowances
determined under Sec. Sec. 206.358 and 206.359. See Sec. 206.361 for
additional provisions applicable to determining gross proceeds;
(2) Other relevant matters including, but not limited to, published
or publicly available spot-market prices, or information submitted by
the lessee concerning circumstances unique to a particular lease
operation or the saleability of certain byproducts; or
(3) Any other reasonable valuation method approved by MMS.
Sec. 206.358 What are byproduct transportation allowances?
(a) When you determine the value of byproducts at a point off the
geothermal lease, unit, or participating area, you are allowed a
deduction in determining value, for royalty purposes, for your
reasonable, actual costs incurred to:
(1) Transport the byproducts from a Federal lease, unit, or
participating area to a sales point or point of delivery that is off the
lease, unit, or participating area; or
(2) Transport the byproducts from a Federal lease, unit, or
participating area, or from a geothermal use facility to a byproduct
recovery facility when that byproduct recovery facility is off the
lease, unit, or participating area and, if applicable, from the recovery
facility to a sales point or point of delivery off the lease, unit, or
participating area.
(b) Costs for transporting geothermal fluids from the lease to the
geothermal
[[Page 144]]
use facility, whether on or off the lease, are not includible in the
byproduct transportation allowance.
(c)(1) When you transport byproducts from a lease, unit,
participating area, or geothermal use facility to a byproduct recovery
facility, you are not required to allocate transportation costs between
the quantity of marketable byproducts and the rejected waste material.
The byproduct transportation allowance is authorized for the total
production that is transported. You must express byproduct
transportation allowances as a cost per unit of marketable byproducts
transported.
(2) For byproducts that are extracted on the lease, unit,
participating area, or at the geothermal use facility, the byproduct
transportation allowance is authorized for the total byproduct that is
transported to a point of sale off the lease, unit, or participating
area. You must express byproduct transportation allowances as a cost per
unit of byproduct transported.
(3) You may deduct transportation costs only when you sell, deliver,
or otherwise utilize the transported byproduct and report and pay
royalties on the byproduct.
(d) Reporting requirements. (1) You must use a discrete field on
Form MMS-2014 to notify MMS of a transportation allowance.
(2) In conducting reviews and audits, MMS may require you to submit
arm's-length transportation contracts, production agreements, operating
agreements, and related documents. You must comply with any such
requirements within the time MMS specifies. Recordkeeping requirements
are found at part 212 of this chapter.
(e) Byproduct transportation allowances are subject to monitoring,
review, and audit. If, after a review or audit, MMS determines that you
have improperly determined a byproduct transportation allowance, you
must pay any additional royalties due (plus interest computed under
Sec. 218.302). You are entitled to a credit for or refund of any
overpaid royalties.
(f) If you commingled byproducts produced from Federal and non-
Federal leases for transportation, you may not disproportionately
allocate transportation costs to Federal lease production.
Sec. 206.359 How do I determine byproduct transportation allowances?
(a) For transportation costs you incur under an arm's-length
contract, the transportation allowance will be the reasonable, actual
costs you incurred for transporting the byproducts under that contract.
(1) In conducting reviews and audits, MMS will examine whether the
contract reflects more than the consideration actually transferred
either directly or indirectly from you to the transporter for the
transportation. If the contract reflects more than the total
consideration you paid, MMS may require you to determine the byproduct
transportation allowance under paragraph (b) of this section.
(2) If MMS determines that the consideration you paid under an
arm's-length byproduct transportation contract does not reflect the
reasonable value of the transportation because of misconduct by or
between the contracting parties, or because you otherwise have breached
your duty to the lessor to market the production for the mutual benefit
of the lessee and the lessor, MMS will require you to determine the
byproduct transportation allowance under paragraph (b) of this section.
When MMS determines that the value of the transportation may be
unreasonable, MMS will notify you and give you an opportunity to provide
written information justifying your transportation costs.
(3) Where your payments for transportation under an arm's-length
contract are not established on a dollars-per-unit basis, you must
convert whatever consideration you paid to a dollar value equivalent for
the purposes of this section.
(b) If you transport the byproduct yourself or under a non-arm's-
length transportation arrangement, the byproduct transportation
allowance is your reasonable actual costs for transportation during the
reporting period, including:
(1) Operating and maintenance expenses under paragraphs (d) and (e)
of this section;
[[Page 145]]
(2) Overhead under paragraph (f) of this section; and either
(3) Depreciation under paragraphs (g) and (h) of this section and a
return on undepreciated capital investment under paragraphs (g) and (i)
of this section; or
(4) A return on capital investment in the transportation system
under paragraphs (g) and (j) of this section.
(c)(1) Allowable capital costs under paragraph (b) of this section
are generally those for depreciable fixed assets (including costs of
delivery and installation of capital equipment) that are an integral
part of the transportation system.
(2)(i) You may include a return on capital you invested in the
purchase of real estate to locate the byproduct transportation
facilities if:
(A) The purchase is necessary; and
(B) The surface is not part of a Federal lease.
(ii) The rate of return will be the same rate determined in
paragraph (k) of this section.
(3) You may not deduct the costs of gathering systems and other
production-related facilities.
(d) Allowable operating expenses include:
(1) Operations supervision and engineering;
(2) Operations labor;
(3) Fuel;
(4) Utilities;
(5) Materials;
(6) Ad valorem property taxes;
(7) Rent;
(8) Supplies; and
(9) Any other directly allocable and attributable operating expense
that you can document.
(e) Allowable maintenance expenses include:
(1) Maintenance of the transportation system;
(2) Maintenance of equipment;
(3) Maintenance labor; and
(4) Other directly allocable and attributable maintenance expenses
that you can document.
(f) Overhead directly attributable and allocable to the operation
and maintenance of the transportation system is an allowable expense.
State and Federal income taxes and severance taxes and other fees,
including royalties, are not allowable expenses.
(g) To compute costs associated with capital investment, a lessee
may use either paragraphs (h) and (i) or paragraph (j) of this section.
After a lessee has elected to use either method for a transportation
system, the lessee may not later elect to change to the other
alternative without MMS approval.
(h)(1) To compute depreciation, you must use a straight-line
depreciation method based on either the life of the equipment or the
life of the geothermal project which the transportation system services.
After you choose the basis for depreciation, you may not change that
basis without MMS approval. You may not depreciate equipment below a
reasonable salvage value.
(2) A change in ownership of a transportation system does not alter
the depreciation schedule established by the original lessee-owner for
purposes of computing transportation costs.
(3) With or without a change in ownership, you may depreciate a
transportation system only once.
(i) To calculate a return on undepreciated capital investment,
multiply the remaining undepreciated capital balance as of the beginning
of the period for which you are calculating the transportation allowance
by the rate of return provided in paragraph (k) of this section.
(j) To compute a return on capital investment in the transportation
system, the allowed cost will be the amount equal to the allowable
capital investment in the transportation system multiplied by the rate
of return determined pursuant to paragraph (k) of this section. There is
no allowance for depreciation.
(k) The rate of return must be the industrial rate associated with
Standard & Poor's BBB rating. The BBB rate must be the monthly average
rate as published in Standard & Poor's Bond Guide for the first month
for which the allowance is applicable. You must redetermine the rate at
the beginning of each subsequent calendar year.
(l)(1) For new transportation facilities or arrangements, base your
initial deduction on estimates of allowable byproduct transportation
costs for the
[[Page 146]]
applicable period. Use the most recently available operations data for
the transportation system or, if such data are not available, use
estimates based on data for similar transportation systems.
(2) When actual cost information is available, you must amend your
prior Form MMS-2014 reports to reflect actual byproduct transportation
cost deductions for each month for which you reported and paid based on
estimated byproduct transportation costs. You must pay any additional
royalties due (together with interest computed under Sec. 218.302). You
are entitled to a credit for or a refund of any overpaid royalties.
Sec. 206.360 What records must I keep to support my calculations of royalty
or fees under this subpart?
If you determine royalties or direct use fees for your geothermal
resource under this subpart, you must retain all data relevant to the
determination of the royalty value or the fee you paid. Recordkeeping
requirements are found at part 212 of this chapter.
(a) You must be able to show:
(1) How you calculated the royalty value or fee you reported,
including all allowable deductions; and
(2) How you complied with this subpart.
(b) Upon request, you must submit all data to MMS. You must comply
with any such requirement within the time MMS specifies.
Sec. 206.361 How will MMS determine whether my royalty or direct use fee
payments are correct?
(a)(1) The royalties or direct use fees that you report are subject
to monitoring, review, and audit. The MMS may review and audit your
data, and MMS will direct you to use a different measure of royalty
value, gross proceeds, or fee, whichever is applicable, if it determines
that the reported value, gross proceeds, or fee is inconsistent with the
requirements of this subpart.
(2) If MMS directs you to use a different royalty value, measure of
gross proceeds, or fee, you must either pay any royalties or fees due
(together with interest computed under Sec. 218.302) or report a credit
for or request a refund of any overpaid royalties or fees.
(b) When the provisions in this subpart refer to gross proceeds
either for the sale of electricity or the sale of a geothermal resource,
in conducting reviews and audits MMS will examine whether your sales
contract reflects the total consideration actually transferred, either
directly or indirectly, from the buyer to you for the geothermal
resource or electricity. If MMS determines that a contract does not
reflect the total consideration, or the gross proceeds accruing to you
under a contract do not reflect reasonable consideration because of
misconduct by or between the contracting parties, or because you
otherwise have breached your duty to the lessor to market the production
for the mutual benefit of the lessee and the lessor, MMS may require you
to increase the gross proceeds to reflect any additional consideration.
Alternatively, for Class I leases, MMS may require you to use another
valuation method in the regulations applicable to dispositions other
than under an arm's-length contract. The MMS will notify you to give you
an opportunity to provide written information justifying your gross
proceeds.
(c) For arm's-length sales, you have the burden of demonstrating
that your contract is arm's length.
(d) The MMS may require you to certify that the provisions in your
sales contract include all of the consideration the buyer paid you,
either directly or indirectly, for the electricity or geothermal
resource.
(e) Notwithstanding any other provision of this subpart, under no
circumstances will the value of production for royalty purposes under a
Class I lease where the geothermal resources are sold before use be less
than the gross proceeds accruing to you.
(f) Gross proceeds for the sale of electricity or for the sale of
the geothermal resource will be based on the highest price a prudent
lessee can receive through legally enforceable claims under its
contract.
(1) Absent contract revision or amendment, if you fail to take
proper or timely action to receive prices or benefits to which you are
entitled, you
[[Page 147]]
must pay royalty based upon that obtainable price or benefit.
(2) Contract revisions or amendments you make must be in writing and
signed by all parties to the contract.
(3) If you make timely application for a price increase or benefit
allowed under your contract, but the purchaser refuses and you take
reasonable measures, which are documented, to force purchaser
compliance, you will owe no additional royalties unless or until you
receive additional monies or consideration resulting from the price
increase. This paragraph (f)(3) will not be construed to permit you to
avoid your royalty payment obligation in situations where a purchaser
fails to pay, in whole or in part or timely, for a quantity of
geothermal resources or electricity.
Sec. 206.362 What are my responsibilities to place production into
marketable condition and to market production?
You must place geothermal resources and byproducts in marketable
condition and market the geothermal resources or byproducts for the
mutual benefit of the lessee and the lessor at no cost to the Federal
Government. If you use gross proceeds under an arm's-length contract in
determining royalty, you must increase those gross proceeds to the
extent that the purchaser, or any other person, provides certain
services that the seller normally would be responsible to perform to
place the geothermal resources or byproducts in marketable condition or
to market the geothermal resources or byproducts.
Sec. 206.363 When is an MMS audit, review, reconciliation, monitoring, or
other like process considered final?
Notwithstanding any provision in these regulations to the contrary,
no audit, review, reconciliation, monitoring, or other like process that
results in a redetermination by MMS of royalty or fees due under this
subpart is considered final or binding as against the Federal Government
or its beneficiaries until MMS formally closes the audit period in
writing.
Sec. 206.364 How do I request a value or gross proceeds determination?
(a) You may request a value determination from MMS regarding any
geothermal resources produced from a Class I lease or for byproducts
produced from a Class I, Class II, or Class III lease. You may also
request a gross proceeds determination for a Class II or Class III
lease. Your request must:
(1) Be in writing;
(2) Identify specifically all leases involved, all owners of
interests in those leases, and the operator(s) for those leases;
(3) Completely explain all relevant facts. You must inform MMS of
any changes to relevant facts that occur before we respond to your
request;
(4) Include copies of all relevant documents;
(5) Provide your analysis of the issue(s), including citations to
all relevant precedents (including adverse precedents); and
(6) Suggest your proposed gross proceeds calculation or valuation
method.
(b) In response to your request:
(1) The Assistant Secretary, Land and Minerals Management, may issue
a determination; or
(2) The MMS may issue a determination; or
(3) The MMS may inform you in writing that MMS will not provide a
determination. Situations in which MMS typically will not provide any
determination include, but are not limited to:
(i) Requests for guidance on hypothetical situations; and
(ii) Matters that are the subject of pending litigation or
administrative appeals.
(c)(1) A determination signed by the Assistant Secretary, Land and
Minerals Management, is binding on both you and MMS until the Assistant
Secretary modifies or rescinds it.
(2) After the Assistant Secretary issues a determination, you must
make any adjustments in royalty payments that follow from the
determination and, if you owe additional royalties, pay the royalties
owed together with late payment interest computed under Sec. 218.302.
(3) A determination signed by the Assistant Secretary is the final
action of
[[Page 148]]
the Department and is subject to judicial review under 5 U.S.C. 701-706.
(d) A determination issued by MMS is binding on MMS and delegated
States, but not on you, with respect to the specific situation addressed
in the determination unless the MMS (for MMS-issued determinations) or
the Assistant Secretary modifies or rescinds it.
(1) A determination by MMS is not an appealable decision or order
under 30 CFR part 290 subpart B.
(2) If you receive an order requiring you to pay royalty on the same
basis as the determination, you may appeal that order under 30 CFR part
290 subpart B.
(e) In making a determination, MMS or the Assistant Secretary may
use any of the applicable criteria in this subpart.
(f) A change in an applicable statute or regulation on which any
determination is based takes precedence over the determination after the
effective date of the statute or regulation, regardless of whether the
MMS or the Assistant Secretary modifies or rescinds the determination.
(g) The MMS or the Assistant Secretary generally will not
retroactively modify or rescind a determination issued under paragraph
(d) of this section, unless:
(1) There was a misstatement or omission of material facts; or
(2) The facts subsequently developed are materially different from
the facts on which the guidance was based.
(h) The MMS may make requests and replies under this section
available to the public, subject to the confidentiality requirements
under Sec. 206.365.
Sec. 206.365 Does MMS protect information I provide?
Certain information you submit to MMS regarding royalties or fees on
geothermal resources or byproducts, including deductions and allowances,
may be exempt from disclosure. To the extent applicable laws and
regulations permit, MMS will keep confidential any data you submit that
is privileged, confidential, or otherwise exempt from disclosure. All
requests for information must be submitted under the Freedom of
Information Act regulations of the Department of the Interior at 43 CFR
part 2.
Sec. 206.366 What is the nominal fee that a State, tribal, or local
government lessee must pay for the use of geothermal resources?
If a State, tribal, or local government lessee uses a geothermal
resource without sale and for public purposes--other than commercial
production or generation of electricity--the State, tribal, or local
government lessee must pay a nominal fee. A nominal fee means a slight
or de minimis fee. The MMS will determine the fee on a case-by-case
basis.
Subpart I--OCS Sulfur [Reserved]
Subpart J_Indian Coal
Source: 61 FR 5481, Feb. 12, 1996, unless otherwise noted.
Sec. 206.450 Purpose and scope.
(a) This subpart prescribes the procedures to establish the value,
for royalty purposes, of all coal from Indian Tribal and allotted leases
(except leases on the Osage Indian Reservation, Osage County, Oklahoma).
(b) If the specific provisions of any statute, treaty, or settlement
agreement between the Indian lessor and a lessee resulting from
administrative or judicial litigation, or any coal lease subject to the
requirements of this subpart, are inconsistent with any regulation in
this subpart, then the statute, treaty, lease provision, or settlement
shall govern to the extent of that inconsistency.
(c) All royalty payments are subject to later audit and adjustment.
(d) The regulations in this subpart are intended to ensure that the
trust responsibilities of the United States with respect to the
administration of Indian coal leases are discharged in accordance with
the requirements of the governing mineral leasing laws, treaties, and
lease terms.
Sec. 206.451 Definitions.
Ad valorem lease means a lease where the royalty due to the lessor
is based upon a percentage of the amount or value of the coal.
[[Page 149]]
Allowance means an approved, or an MMS-initially accepted deduction
in determining value for royalty purposes. Coal washing allowance means
an allowance for the reasonable, actual costs incurred by the lessee for
coal washing, or an approved or MMS-initially accepted deduction for the
costs of washing coal, determined pursuant to this subpart.
Transportation allowance means an allowance for the reasonable, actual
costs incurred by the lessee for moving coal to a point of sale or point
of delivery remote from both the lease and mine or wash plant, or an
approved MMS-initially accepted deduction for costs of such
transportation, determined pursuant to this subpart.
Area means a geographic region in which coal has similar quality and
economic characteristics. Area boundaries are not officially designated
and the areas are not necessarily named.
Arm's-length contract means a contract or agreement that has been
arrived at in the marketplace between independent, nonaffiliated persons
with opposing economic interests regarding that contract. For purposes
of this subpart, two persons are affiliated if one person controls, is
controlled by, or is under common control with another person. For
purposes of this subpart, based on the instruments of ownership of the
voting securities of an entity, or based on other forms of ownership:
ownership in excess of 50 percent constitutes control; ownership of 10
through 50 percent creates a presumption of control; and ownership of
less than 10 percent creates a presumption of noncontrol which MMS may
rebut if it demonstrates actual or legal control, including the
existence of interlocking directorates. Notwithstanding any other
provisions of this subpart, contracts between relatives, either by blood
or by marriage, are not arm's-length contracts. MMS may require the
lessee to certify ownership control. To be considered arm's-length for
any production month, a contract must meet the requirements of this
definition for that production month, as well as when the contract was
executed.
Audit means a review, conducted in accordance with generally
accepted accounting and auditing standards, of royalty payment
compliance activities of lessees or other interest holders who pay
royalties, rents, or bonuses on Indian leases.
BIA means the Bureau of Indian Affairs of the Department of the
Interior.
BLM means the Bureau of Land Management of the Department of the
Interior.
Coal means coal of all ranks from lignite through anthracite.
Coal washing means any treatment to remove impurities from coal.
Coal washing may include, but is not limited to, operations such as
flotation, air, water, or heavy media separation; drying; and related
handling (or combination thereof).
Contract means any oral or written agreement, including amendments
or revisions thereto, between two or more persons and enforceable by law
that with due consideration creates an obligation.
Gross proceeds (for royalty payment purposes) means the total monies
and other consideration accruing to a coal lessee for the production and
disposition of the coal produced. Gross proceeds includes, but is not
limited to, payments to the lessee for certain services such as
crushing, sizing, screening, storing, mixing, loading, treatment with
substances including chemicals or oils, and other preparation of the
coal to the extent that the lessee is obligated to perform them at no
cost to the Indian lessor. Gross proceeds, as applied to coal, also
includes but is not limited to reimbursements for royalties, taxes or
fees, and other reimbursements. Tax reimbursements are part of the gross
proceeds accruing to a lessee even though the Indian royalty interest
may be exempt from taxation. Monies and other consideration, including
the forms of consideration identified in this paragraph, to which a
lessee is contractually or legally entitled but which it does not seek
to collect through reasonable efforts are also part of gross proceeds.
Indian allottee means any Indian for whom land or an interest in
land is held in trust by the United States or who holds title subject to
Federal restriction against alienation.
Indian Tribe means any Indian Tribe, band, nation, pueblo,
community,
[[Page 150]]
rancheria, colony, or other group of Indians for which any land or
interest in land is held in trust by the United States or which is
subject to Federal restriction against alienation.
Lease means any contract, profit-share arrangement, joint venture,
or other agreement issued or approved by the United States for an Indian
coal resource under a mineral leasing law that authorizes exploration
for, development or extraction of, or removal of coal--or the land
covered by that authorization, whichever is required by the context.
Lessee means any person to whom the Indian Tribe or an Indian
allottee issues a lease, and any person who has been assigned an
obligation to make royalty or other payments required by the lease. This
includes any person who has an interest in a lease as well as an
operator or payor who has no interest in the lease but who has assumed
the royalty payment responsibility.
Like-quality coal means coal that has similar chemical and physical
characteristics.
Marketable condition means coal that is sufficiently free from
impurities and otherwise in a condition that it will be accepted by a
purchaser under a sales contract typical for that area.
Mine means an underground or surface excavation or series of
excavations and the surface or underground support facilities that
contribute directly or indirectly to mining, production, preparation,
and handling of lease products.
MMS means the Minerals Management Service of the Department of the
Interior.
Net-back method means a method for calculating market value of coal
at the lease or mine. Under this method, costs of transportation,
washing, handling, etc., are deducted from the ultimate proceeds
received for the coal at the first point at which reasonable values for
the coal may be determined by a sale pursuant to an arm's-length
contract or by comparison to other sales of coal, to ascertain value at
the mine.
Net output means the quantity of washed coal that a washing plant
produces.
Person means by individual, firm, corporation, association,
partnership, consortium, or joint venture.
Selling arrangement means the individual contractual arrangements
under which sales or dispositions of coal are made to a purchaser.
Spot market price means the price received under any sales
transaction when planned or actual deliveries span a short period of
time, usually not exceeding one year.
[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999]
Sec. 206.452 Coal subject to royalties--general provisions.
(a) All coal (except coal unavoidably lost as determined by BLM
pursuant to 43 CFR group 3400) from an Indian lease subject to this part
is subject to royalty. This includes coal used, sold, or otherwise
disposed of by the lessee on or off the lease.
(b) If a lessee receives compensation for unavoidably lost coal
through insurance coverage or other arrangements, royalties at the rate
specified in the lease are to be paid on the amount of compensation
received for the coal. No royalty is due on insurance compensation
received by the lessee for other losses.
(c) If waste piles or slurry ponds are reworked to recover coal, the
lessee shall pay royalty at the rate specified in the lease at the time
the recovered coal is used, sold, or otherwise finally disposed of. The
royalty rate shall be that rate applicable to the production method used
to initially mine coal in the waste pile or slurry pond; i.e.,
underground mining method or surface mining method. Coal in waste pits
or slurry ponds initially mined from Indian leases shall be allocated to
such leases regardless of whether it is stored on Indian lands. The
lessee shall maintain accurate records to determine to which individual
Indian lease coal in the waste pit or slurry pond should be allocated.
However, nothing in this section requires payment of a royalty on coal
for which a royalty has already been paid.
Sec. 206.453 Quality and quantity measurement standards for reporting and
paying royalties.
For all leases subject to this subpart, the quantity of coal on
which royalty is due shall be measured in short tons
[[Page 151]]
(of 2,000 pounds each) by methods prescribed by the BLM. Coal quantity
information shall be reported on appropriate forms required under 30 CFR
part 216 and on the Solid Minerals Production and Royalty Report, Form
MMS-4430, as required under 30 CFR part 210.
[61 FR 5481, Feb. 12, 1996, as amended at 66 FR 45769, Aug. 30, 2001]
Sec. 206.454 Point of royalty determination.
(a) For all leases subject to this subpart, royalty shall be
computed on the basis of the quantity and quality of Indian coal in
marketable condition measured at the point of royalty measurement as
determined jointly by BLM and MMS.
(b) Coal produced and added to stockpiles or inventory does not
require payment of royalty until such coal is later used, sold, or
otherwise finally disposed of. MMS may ask BLM or BIA to increase the
lease bond to protect the lessor's interest when BLM determines that
stockpiles or inventory become excessive so as to increase the risk of
degradation of the resource.
(c) The lessee shall pay royalty at a rate specified in the lease at
the time the coal is used, sold, or otherwise finally disposed of,
unless otherwise provided for at Sec. 206.455(d) of this subpart.
Sec. 206.455 Valuation standards for cents-per-ton leases.
(a) This section is applicable to coal leases on Indian Tribal and
allotted Indian lands (except leases on the Osage Indian Reservation,
Osage County, Oklahoma) which provide for the determination of royalty
on a cents-per-ton (or other quantity) basis.
(b) The royalty for coal from leases subject to this section shall
be based on the dollar rate per ton prescribed in the lease. That dollar
rate shall be applicable to the actual quantity of coal used, sold, or
otherwise finally disposed of, including coal which is avoidably lost as
determined by BLM pursuant to 43 CFR part 3400.
(c) For leases subject to this section, there shall be no allowances
for transportation, removal of impurities, coal washing, or any other
processing or preparation of the coal.
(d) When a coal lease is readjusted pursuant to 43 CFR part 3400 and
the royalty valuation method changes from a cents-per-ton basis to an ad
valorem basis, coal which is produced prior to the effective date of
readjustment and sold or used within 30 days of the effective date of
readjustment shall be valued pursuant to this section. All coal that is
not used, sold, or otherwise finally disposed of within 30 days after
the effective date of readjustment shall be valued pursuant to the
provisions of Sec. 206.456 of this subpart, and royalties shall be paid
at the royalty rate specified in the readjusted lease.
Sec. 206.456 Valuation standards for ad valorem leases.
(a) This section is applicable to coal leases on Indian Tribal and
allotted Indian lands (except leases on the Osage Indian Reservation,
Osage County, Oklahoma) which provide for the determination of royalty
as a percentage of the amount of value of coal (ad valorem). The value
for royalty purposes of coal from such leases shall be the value of coal
determined pursuant to this section, less applicable coal washing
allowances and transportation allowances determined pursuant to
Sec. Sec. 206.457 through 206.461 of this subpart, or any allowance
authorized by Sec. 206.464 of this subpart. The royalty due shall be
equal to the value for royalty purposes multiplied by the royalty rate
in the lease.
(b)(1) The value of coal that is sold pursuant to an arm's-length
contract shall be the gross proceeds accruing to the lessee, except as
provided in paragraphs (b)(2), (b)(3), and (b)(5) of this section. The
lessee shall have the burden of demonstrating that its contract is
arm's-length. The value which the lessee reports, for royalty purposes,
is subject to monitoring, review, and audit.
(2) In conducting reviews and audits, MMS will examine whether the
contract reflects the total consideration actually transferred either
directly or indirectly from the buyer to the seller for the coal
produced. If the contract does not reflect the total consideration, then
MMS may require that the coal sold pursuant to that contract be valued
in accordance with paragraph (c) of this section. Value may not be
[[Page 152]]
based on less than the gross proceeds accruing to the lessee for the
coal production, including the additional consideration.
(3) If MMS determines that the gross proceeds accruing to the lessee
pursuant to an arm's-length contract do not reflect the reasonable value
of the production because of misconduct by or between the contracting
parties, or because the lessee otherwise has breached its duty to the
lessor to market the production for the mutual benefit of the lessee and
the lessor, then MMS shall require that the coal production be valued
pursuant to paragraphs (c)(2)(ii), (c)(2)(iii), (c)(2)(iv), or (c)(2)(v)
of this section, and in accordance with the notification requirements of
paragraph (d)(3) of this section. When MMS determines that the value may
be unreasonable, MMS will notify the lessee and give the lessee an
opportunity to provide written information justifying the lessee's
reported coal value.
(4) MMS may require a lessee to certify that its arm's-length
contract provisions include all of the consideration to be paid by the
buyer, either directly or indirectly, for the coal production.
(5) The value of production for royalty purposes shall not include
payments received by the lessee pursuant to a contract which the lessee
demonstrates, to MMS' satisfaction, were not part of the total
consideration paid for the purchase of coal production.
(c)(1) The value of coal from leases subject to this section and
which is not sold pursuant to an arm's-length contract shall be
determined in accordance with this section.
(2) If the value of the coal cannot be determined pursuant to
paragraph (b) of this section, then the value shall be determined
through application of other valuation criteria. The criteria shall be
considered in the following order, and the value shall be based upon the
first applicable criterion:
(i) The gross proceeds accruing to the lessee pursuant to a sale
under its non-arm's-length contract (or other disposition of produced
coal by other than an arm's-length contract), provided that those gross
proceeds are within the range of the gross proceeds derived from, or
paid under, comparable arm's-length contracts between buyers and sellers
neither of whom is affiliated with the lessee for sales, purchases, or
other dispositions of like-quality coal produced in the area. In
evaluating the comparability of arm's-length contracts for the purposes
of these regulations, the following factors shall be considered: price,
time of execution, duration, market or markets served, terms, quality of
coal, quantity, and such other factors as may be appropriate to reflect
the value of the coal;
(ii) Prices reported for that coal to a public utility commission;
(iii) Prices reported for that coal to the Energy Information
Administration of the Department of Energy;
(iv) Other relevant matters including, but not limited to, published
or publicly available spot market prices, or information submitted by
the lessee concerning circumstances unique to a particular lease
operation or the salability of certain types of coal;
(v) If a reasonable value cannot be determined using paragraphs
(c)(2)(i), (c)(2)(ii), (c)(2)(iii), or (c)(2)(iv) of this section, then
a net-back method or any other reasonable method shall be used to
determine value.
(3) When the value of coal is determined pursuant to paragraph
(c)(2) of this section, that value determination shall be consistent
with the provisions contained in paragraph (b)(5) of this section.
(d)(1) Where the value is determined pursuant to paragraph (c) of
this section, that value does not require MMS' prior approval. However,
the lessee shall retain all data relevant to the determination of
royalty value. Such data shall be subject to review and audit, and MMS
will direct a lessee to use a different value if it determines that the
reported value is inconsistent with the requirements of these
regulations.
(2) An Indian lessee will make available upon request to the
authorized MMS or Indian representatives, or to the Inspector General of
the Department of the Interior or other persons authorized to receive
such information, arm's-length sales and sales quantity data for like-
quality coal sold, purchased, or otherwise obtained by the lessee from
the area.
[[Page 153]]
(3) A lessee shall notify MMS if it has determined value pursuant to
paragraphs (c)(2)(ii), (c)(2)(iii), (c)(2)(iv), or (c)(2)(v) of this
section. The notification shall be by letter to the Associate Director
for Minerals Revenue Management or his/her designee. The letter shall
identify the valuation method to be used and contain a brief description
of the procedure to be followed. The notification required by this
section is a one-time notification due no later than the month the
lessee first reports royalties on the Form MMS-4430 using a valuation
method authorized by paragraphs (c)(2)(ii), (c)(2)(iii), (c)(2)(iv), or
(c)(2)(v) of this section, and each time there is a change in a method
under paragraphs (c)(2)(iv) or (c)(2)(v) of this section.
(e) If MMS determines that a lessee has not properly determined
value, the lessee shall be liable for the difference, if any, between
royalty payments made based upon the value it has used and the royalty
payments that are due based upon the value established by MMS. The
lessee shall also be liable for interest computed pursuant to 30 CFR
218.202. If the lessee is entitled to a credit, MMS will provide
instructions for the taking of that credit.
(f) The lessee may request a value determination from MMS. In that
event, the lessee shall propose to MMS a value determination method, and
may use that method in determining value for royalty purposes until MMS
issues its decision. The lessee shall submit all available data relevant
to its proposal. MMS shall expeditiously determine the value based upon
the lessee's proposal and any additional information MMS deems
necessary. That determination shall remain effective for the period
stated therein. After MMS issues its determination, the lessee shall
make the adjustments in accordance with paragraph (e) of this section.
(g) Notwithstanding any other provisions of this section, under no
circumstances shall the value for royalty purposes be less than the
gross proceeds accruing to the lessee for the disposition of produced
coal less applicable provisions of paragraph (b)(5) of this section and
less applicable allowances determined pursuant to Sec. Sec. 206.457
through 206.461 and Sec. 206.464 of this subpart.
(h) The lessee is required to place coal in marketable condition at
no cost to the Indian lessor. Where the value established pursuant to
this section is determined by a lessee's gross proceeds, that value
shall be increased to the extent that the gross proceeds has been
reduced because the purchaser, or any other person, is providing certain
services, the cost of which ordinarily is the responsibility of the
lessee to place the coal in marketable condition.
(i) Value shall be based on the highest price a prudent lessee can
receive through legally enforceable claims under its contract. Absent
contract revision or amendment, if the lessee fails to take proper or
timely action to receive prices or benefits to which it is entitled, it
must pay royalty at a value based upon that obtainable price or benefit.
Contract revisions or amendments shall be in writing and signed by all
parties to an arm's-length contract, and may be retroactively applied to
value for royalty purposes for a period not to exceed two years, unless
MMS approves a longer period. If the lessee makes timely application for
a price increase allowed under its contract but the purchaser refuses,
and the lessee takes reasonable measures, which are documented, to force
purchaser compliance, the lessee will owe no additional royalties unless
or until monies or consideration resulting from the price increase are
received. This paragraph shall not be construed to permit a lessee to
avoid its royalty payment obligation in situations where a purchaser
fails to pay, in whole or in part or timely, for a quantity of coal.
(j) Notwithstanding any provision in these regulations to the
contrary, no review, reconciliation, monitoring, or other like process
that results in a redetermination by MMS of value under this section
shall be considered final or binding as against the Indian Tribes or
allottees until the audit period is formally closed.
(k) Certain information submitted to MMS to support valuation
proposals, including transportation, coal washing, or other allowances
pursuant to Sec. Sec. 206.457 through 206.461 and Sec. 206.464 of
[[Page 154]]
this subpart, is exempted from disclosure by the Freedom of Information
Act, 5 U.S.C. 522. Any data specified by the Act to be privileged,
confidential, or otherwise exempt shall be maintained in a confidential
manner in accordance with applicable law and regulations. All requests
for information about determinations made under this part are to be
submitted in accordance with the Freedom of Information Act regulation
of the Department of the Interior, 43 CFR part 2. Nothing in this
section is intended to limit or diminish in any manner whatsoever the
right of an Indian lessor to obtain any and all information as such
lessor may be lawfully entitled from MMS or such lessor's lessee
directly under the terms of the lease or applicable law.
[61 FR 5481, Feb. 12, 1996, as amended at 66 FR 45769, Aug. 30, 2001]
Sec. 206.457 Washing allowances--general.
(a) For ad valorem leases subject to Sec. 206.456 of this subpart,
MMS shall, as authorized by this section, allow a deduction in
determining value for royalty purposes for the reasonable, actual costs
incurred to wash coal, unless the value determined pursuant to Sec.
206.456 of this subpart was based upon like-quality unwashed coal. Under
no circumstances will the authorized washing allowance and the
transportation allowance reduce the value for royalty purposes to zero.
(b) If MMS determines that a lessee has improperly determined a
washing allowance authorized by this section, then the lessee shall be
liable for any additional royalties, plus interest determined in
accordance with 30 CFR 218.202, or shall be entitled to a credit,
without interest.
(c) Lessees shall not disproportionately allocate washing costs to
Indian leases.
(d) No cost normally associated with mining operations and which are
necessary for placing coal in marketable condition shall be allowed as a
cost of washing.
(e) Coal washing costs shall only be recognized as allowances when
the washed coal is sold and royalties are reported and paid.
[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999]
Sec. 206.458 Determination of washing allowances.
(a) Arm's-length contracts. (1) For washing costs incurred by a
lessee pursuant to an arm's-length contract, the washing allowance shall
be the reasonable actual costs incurred by the lessee for washing the
coal under that contract, subject to monitoring, review, audit, and
possible future adjustment. MMS' prior approval is not required before a
lessee may deduct costs incurred under an arm's-length contract.
However, before any deduction may be taken, the lessee must submit a
completed page one of Form MMS-4292, Coal Washing Allowance Report, in
accordance with paragraph (c)(1) of this section. A washing allowance
may be claimed retroactively for a period of not more than 3 months
prior to the first day of the month that Form MMS-4292 is filed with
MMS, unless MMS approves a longer period upon a showing of good cause by
the lessee.
(2) In conducting reviews and audits, MMS will examine whether the
contract reflects more than the consideration actually transferred
either directly or indirectly from the lessee to the washer for the
washing. If the contract reflects more than the total consideration
paid, then MMS may require that the washing allowance be determined in
accordance with paragraph (b) of this section.
(3) If MMS determines that the consideration paid pursuant to an
arm's-length washing contract does not reflect the reasonable value of
the washing because of misconduct by or between the contracting parties,
or because the lessee otherwise has breached its duty to the lessor to
market the production for the mutual benefit of the lessee and the
lessor, then MMS shall require that the washing allowance be determined
in accordance with paragraph (b) of this section. When MMS determines
that the value of the washing may be unreasonable, MMS will notify the
lessee and give the lessee an opportunity to provide written
[[Page 155]]
information justifying the lessee's washing costs.
(4) Where the lessee's payments for washing under an arm's-length
contract are not based on a dollar-per-unit basis, the lessee shall
convert whatever consideration is paid to a dollar value equivalent.
Washing allowances shall be expressed as a cost per ton of coal washed.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length contract or has no contract, including those situations
where the lessee performs washing for itself, the washing allowance will
be based upon the lessee's reasonable actual costs. All washing
allowances deducted under a non-arm's-length or no contract situation
are subject to monitoring, review, audit, and possible future
adjustment. Prior MMS approval of washing allowances is not required for
non-arm's-length or no contract situations. However, before any
estimated or actual deduction may be taken, the lessee must submit a
completed Form MMS-4292 in accordance with paragraph (c)(2) of this
section. A washing allowance may be claimed retroactively for a period
of not more than 3 months prior to the first day of the month that Form
MMS-4292 is filed with MMS, unless MMS approves a longer period upon a
showing of good cause by the lessee. MMS will monitor the allowance
deduction to ensure that deductions are reasonable and allowable. When
necessary or appropriate, MMS may direct a lessee to modify its actual
washing allowance.
(2) The washing allowance for non-arm's-length or no contract
situations shall be based upon the lessee's actual costs for washing
during the reported period, including operating and maintenance
expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph
(b)(2)(iv)(A) of this section, or a cost equal to the depreciable
investment in the wash plant multiplied by the rate of return in
accordance with paragraph (b)(2)(iv)(B) of this section. Allowable
capital costs are generally those for depreciable fixed assets
(including costs of delivery and installation of capital equipment)
which are an integral part of the wash plant.
(i) Allowable operating expenses include: Operations supervision and
engineering; operations labor; fuel; utilities; materials; ad valorem
property taxes; rent; supplies; and any other directly allocable and
attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the wash
plant; maintenance of equipment; maintenance labor; and other directly
allocable and attributable maintenance expenses which the lessee can
document.
(iii) Overhead attributable and allocable to the operation and
maintenance of the wash plant is an allowable expense. State and Federal
income taxes and severance taxes, including royalties, are not allowable
expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or
(b)(2)(iv)(B) of this section. After a lessee has elected to use either
method for a wash plant, the lessee may not later elect to change to the
other alternative without approval of MMS.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the wash plant services, whichever is
appropriate, or a unit of production method. After an election is made,
the lessee may not change methods without MMS approval. A change in
ownership of a wash plant shall not alter the depreciation schedule
established by the original operator/lessee for purposes of the
allowance calculation. With or without a change in ownership, a wash
plant shall be depreciated only once. Equipment shall not be depreciated
below a reasonable salvage value.
(B) MMS shall allow as a cost an amount equal to the allowable
capital investment in the wash plant multiplied by the rate of return
determined pursuant to paragraph (b)(2)(v) of this section. No allowance
shall be provided for depreciation. This alternative shall apply only to
plants first placed in service or acquired after March 1, 1989.
(v) The rate of return shall be the industrial rate associated with
Standard
[[Page 156]]
and Poor's BBB rating. The rate of return shall be the monthly average
rate as published in Standard and Poor's Bond Guide for the first month
of the reporting period for which the allowance is applicable and shall
be effective during the reporting period. The rate shall be redetermined
at the beginning of each subsequent washing allowance reporting period
(which is determined pursuant to paragraph (c)(2) of this section).
(3) The washing allowance for coal shall be determined based on the
lessee's reasonable and actual cost of washing the coal. The lessee may
not take an allowance for the costs of washing lease production that is
not royalty bearing.
(c) Reporting requirements--(1) Arm's-length contracts. (i) With the
exception of those washing allowances specified in paragraphs (c)(1)(v)
and (c)(1)(vi) of this section, the lessee shall submit page one of the
initial Form MMS-4292 prior to, or at the same time, as the washing
allowance determined pursuant to an arm's-length contract is reported on
Form MMS-4430, Solid Minerals Production and Royalty Report. A Form MMS-
4292 received by the end of the month that the Form MMS-4430 is due
shall be considered to be received timely.
(ii) The initial Form MMS-4292 shall be effective for a reporting
period beginning the month that the lessee is first authorized to deduct
a washing allowance and shall continue until the end of the calendar
year, or until the applicable contract or rate terminates or is modified
or amended, whichever is earlier.
(iii) After the initial reporting period and for succeeding
reporting periods, lessees must submit page one of Form MMS-4292 within
3 months after the end of the calendar year, or after the applicable
contract or rate terminates or is modified or amended, whichever is
earlier, unless MMS approves a longer period (during which period the
lessee shall continue to use the allowance from the previous reporting
period).
(iv) MMS may require that a lessee submit arm's-length washing
contracts and related documents. Documents shall be submitted within a
reasonable time, as determined by MMS.
(v) Washing allowances which are based on arm's-length contracts and
which are in effect at the time these regulations become effective will
be allowed to continue until such allowances terminate. For the purposes
of this section, only those allowances that have been approved by MMS in
writing shall qualify as being in effect at the time these regulations
become effective.
(vi) MMS may establish, in appropriate circumstances, reporting
requirements that are different from the requirements of this section.
(2) Non-arm's-length or no contract. (i) With the exception of those
washing allowances specified in paragraphs (c)(2)(v) and (c)(2)(vii) of
this section, the lessee shall submit an initial Form MMS-4292 prior to,
or at the same time as, the washing allowance determined pursuant to a
non-arm's-length contract or no contract situation is reported on Form
MMS-4430, Solid Minerals Production and Royalty Report. A Form MMS-4292
received by the end of the month that the Form MMS-4430 is due shall be
considered to be timely received. The initial reporting may be based on
estimated costs.
(ii) The initial Form MMS-4292 shall be effective for a reporting
period beginning the month that the lessee first is authorized to deduct
a washing allowance and shall continue until the end of the calendar
year, or until the washing under the non-arm's-length contract or the no
contract situation terminates, whichever is earlier.
(iii) For calendar-year reporting periods succeeding the initial
reporting period, the lessee shall submit a completed Form MMS-4292
containing the actual costs for the previous reporting period. If coal
washing is continuing, the lessee shall include on Form MMS-4292 its
estimated costs for the next calendar year. The estimated coal washing
allowance shall be based on the actual costs for the previous period
plus or minus any adjustments which are based on the lessee's knowledge
of decreases or increases which will affect the allowance. Form MMS-4292
must be received by MMS within 3 months after the end of the previous
reporting period, unless MMS approves a longer period (during which
period the lessee
[[Page 157]]
shall continue to use the allowance from the previous reporting period).
(iv) For new wash plants, the lessee's initial Form MMS-4292 shall
include estimates of the allowable coal washing costs for the applicable
period. Cost estimates shall be based upon the most recently available
operations data for the plant, or if such data are not available, the
lessee shall use estimates based upon industry data for similar coal
wash plants.
(v) Washing allowances based on non-arm's-length or no contract
situations which are in effect at the time these regulations become
effective will be allowed to continue until such allowances terminate.
For the purposes of this section, only those allowances that have been
approved by MMS in writing shall qualify as being in effect at the time
these regulations become effective.
(vi) Upon request by MMS, the lessee shall submit all data used by
the lessee to prepare its Forms MMS-4292. The data shall be provided
within a reasonable period of time, as determined by MMS.
(vii) MMS may establish, in appropriate circumstances, reporting
requirements which are different from the requirements of this section.
(3) MMS may establish coal washing allowance reporting dates for
individual leases different from those specified in this subpart in
order to provide more effective administration. Lessees will be notified
of any change in their reporting period.
(4) Washing allowances must be reported as a separate line on the
Form MMS-4430, unless MMS approves a different reporting procedure.
(d) Interest assessments for incorrect or late reports and failure
to report. (1) If a lessee deducts a washing allowance on its Form MMS-
4430 without complying with the requirements of this section, the lessee
shall be liable for interest on the amount of such deduction until the
requirements of this section are complied with. The lessee also shall
repay the amount of any allowance which is disallowed by this section.
(2) If a lessee erroneously reports a washing allowance which
results in an underpayment of royalties, interest shall be paid on the
amount of that underpayment.
(3) Interest required to be paid by this section shall be determined
in accordance with 30 CFR 218.202.
(e) Adjustments. (1) If the actual coal washing allowance is less
than the amount the lessee has taken on Form MMS-4430 for each month
during the allowance form reporting period, the lessee shall be required
to pay additional royalties due plus interest computed pursuant to 30
CFR 218.202, retroactive to the first month the lessee is authorized to
deduct a washing allowance. If the actual washing allowance is greater
than the amount the lessee has estimated and taken during the reporting
period, the lessee shall be entitled to a credit, without interest.
(2) The lessee must submit a corrected Form MMS-4430 to reflect
actual costs, together with any payment, in accordance with instructions
provided by MMS.
(f) Other washing cost determinations. The provisions of this
section shall apply to determine washing costs when establishing value
using a net-back valuation procedure or any other procedure that
requires deduction of washing costs.
[61 FR 5481, Feb. 12, 1996, as amended at 66 FR 45769, Aug. 30, 2001]
Sec. 206.459 Allocation of washed coal.
(a) When coal is subjected to washing, the washed coal must be
allocated to the leases from which it was extracted.
(b) When the net output of coal from a washing plant is derived from
coal obtained from only one lease, the quantity of washed coal allocable
to the lease will be based on the net output of the washing plant.
(c) When the net output of coal from a washing plant is derived from
coal obtained from more than one lease, unless determined otherwise by
BLM, the quantity of net output of washed coal allocable to each lease
will be based on the ratio of measured quantities of coal delivered to
the washing plant and washed from each lease compared to the total
measured quantities of coal delivered to the washing plant and washed.
[[Page 158]]
Sec. 206.460 Transportation allowances--general.
(a) For ad valorem leases subject to Sec. 206.456 of this subpart,
where the value for royalty purposes has been determined at a point
remote from the lease or mine, MMS shall, as authorized by this section,
allow a deduction in determining value for royalty purposes for the
reasonable, actual costs incurred to:
(1) Transport the coal from an Indian lease to a sales point which
is remote from both the lease and mine; or
(2) Transport the coal from an Indian lease to a wash plant when
that plant is remote from both the lease and mine and, if applicable,
from the wash plant to a remote sales point. In-mine transportation
costs shall not be included in the transportation allowance.
(b) Under no circumstances will the authorized washing allowance and
the transportation allowance reduce the value for royalty purposes to
zero.
(c)(1) When coal transported from a mine to a wash plant is eligible
for a transportation allowance in accordance with this section, the
lessee is not required to allocate transportation costs between the
quantity of clean coal output and the rejected waste material. The
transportation allowance shall be authorized for the total production
which is transported. Transportation allowances shall be expressed as a
cost per ton of cleaned coal transported.
(2) For coal that is not washed at a wash plant, the transportation
allowance shall be authorized for the total production which is
transported. Transportation allowances shall be expressed as a cost per
ton of coal transported.
(3) Transportation costs shall only be recognized as allowances when
the transported coal is sold and royalties are reported and paid.
(d) If, after a review and/or audit, MMS determines that a lessee
has improperly determined a transportation allowance authorized by this
section, then the lessee shall pay any additional royalties, plus
interest, determined in accordance with 30 CFR 218.202, or shall be
entitled to a credit, without interest.
(e) Lessees shall not disproportionately allocate transportation
costs to Indian leases.
[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999]
Sec. 206.461 Determination of transportation allowances.
(a) Arm's-length contracts. (1) For transportation costs incurred by
a lessee pursuant to an arm's-length contract, the transportation
allowance shall be the reasonable, actual costs incurred by the lessee
for transporting the coal under that contract, subject to monitoring,
review, audit, and possible future adjustment. MMS' prior approval is
not required before a lessee may deduct costs incurred under an arm's-
length contract. However, before any deduction may be taken, the lessee
must submit a completed page one of Form MMS-4293, Coal Transportation
Allowance Report, in accordance with paragraph (c)(1) of this section. A
transportation allowance may be claimed retroactively for a period of
not more than 3 months prior to the first day of the month that Form
MMS-4293 is filed with MMS, unless MMS approves a longer period upon a
showing of good cause by the lessee.
(2) In conducting reviews and audits, MMS will examine whether the
contract reflects more than the consideration actually transferred
either directly or indirectly from the lessee to the transporter for the
transportation. If the contract reflects more than the total
consideration paid, then MMS may require that the transportation
allowance be determined in accordance with paragraph (b) of this
section.
(3) If MMS determines that the consideration paid pursuant to an
arm's-length transportation contract does not reflect the reasonable
value of the transportation because of misconduct by or between the
contracting parties, or because the lessee otherwise has breached its
duty to the lessor to market the production for the mutual benefit of
the lessee and the lessor, then MMS shall require that the
transportation allowance be determined in accordance with paragraph (b)
of this section. When MMS determines that the value of the
transportation may be unreasonable, MMS will notify the lessee
[[Page 159]]
and give the lessee an opportunity to provide written information
justifying the lessee's transportation costs.
(4) Where the lessee's payments for transportation under an arm's-
length contract are not based on a dollar-per-unit basis, the lessee
shall convert whatever consideration is paid to a dollar value
equivalent for the purposes of this section.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length contract or has no contract, including those situations
where the lessee performs transportation services for itself, the
transportation allowance will be based upon the lessee's reasonable
actual costs. All transportation allowances deducted under a non-arm's-
length or no contract situation are subject to monitoring, review,
audit, and possible future adjustment. Prior MMS approval of
transportation allowances is not required for non-arm's-length or no
contract situations. However, before any estimated or actual deduction
may be taken, the lessee must submit a completed Form MMS-4293 in
accordance with paragraph (c)(2) of this section. A transportation
allowance may be claimed retroactively for a period of not more than 3
months prior to the first day of the month that Form MMS-4293 is filed
with MMS, unless MMS approves a longer period upon a showing of good
cause by the lessee. MMS will monitor the allowance deductions to ensure
that deductions are reasonable and allowable. When necessary or
appropriate, MMS may direct a lessee to modify its estimated or actual
transportation allowance deduction.
(2) The transportation allowance for non-arm's-length or no contract
situations shall be based upon the lessee's actual costs for
transportation during the reporting period, including operating and
maintenance expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph
(b)(2)(iv)(A) of this section, or a cost equal to the depreciable
investment in the transportation system multiplied by the rate of return
in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable
capital costs are generally those for depreciable fixed assets
(including costs of delivery and installation of capital equipment)
which are an integral part of the transportation system.
(i) Allowable operating expenses include: Operations supervision and
engineering; operations labor; fuel; utilities; materials; ad valorem
property taxes; rent; supplies; and any other directly allocable and
attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the
transportation system; maintenance of equipment; maintenance labor; and
other directly allocable and attributable maintenance expenses which the
lessee can document.
(iii) Overhead attributable and allocable to the operation and
maintenance of the transportation system is an allowable expense. State
and Federal income taxes and severance taxes and other fees, including
royalties, are not allowable expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or paragraph
(b)(2)(iv)(B) of this section. After a lessee has elected to use either
method for a transportation system, the lessee may not later elect to
change to the other alternative without approval of MMS.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the transportation system services,
whichever is appropriate, or a unit of production method. After an
election is made, the lessee may not change methods without MMS
approval. A change in ownership of a transportation system shall not
alter the depreciation schedule established by the original transporter/
lessee for purposes of the allowance calculation. With or without a
change in ownership, a transportation system shall be depreciated only
once. Equipment shall not be depreciated below a reasonable salvage
value.
(B) MMS shall allow as a cost an amount equal to the allowable
capital investment in the transportation system multiplied by the rate
of return determined pursuant to paragraph
[[Page 160]]
(b)(2)(B)(v) of this section. No allowance shall be provided for
depreciation. This alternative shall apply only to transportation
facilities first placed in service or acquired after March 1, 1989.
(v) The rate of return shall be the industrial rate associated with
Standard and Poor's BBB rating. The rate of return shall be the monthly
average as published in Standard and Poor's Bond Guide for the first
month of the reporting period of which the allowance is applicable and
shall be effective during the reporting period. The rate shall be
redetermined at the beginning of each subsequent transportation
allowance reporting period (which is determined pursuant to paragraph
(c)(2) of this section).
(3) A lessee may apply to MMS for exception from the requirement
that it compute actual costs in accordance with paragraphs (b)(1) and
(b)(2) of this section. MMS will grant the exception only if the lessee
has a rate for the transportation approved by a Federal agency for
Indian leases. MMS shall deny the exception request if it determines
that the rate is excessive as compared to arm's-length transportation
charges by systems, owned by the lessee or others, providing similar
transportation services in that area. If there are no arm's-length
transportation charges, MMS shall deny the exception request if:
(i) No Federal regulatory agency cost analysis exists and the
Federal regulatory agency has declined to investigate pursuant to MMS
timely objections upon filing; and
(ii) The rate significantly exceeds the lessee's actual costs for
transportation as determined under this section.
(c) Reporting requirements--(1) Arm's-length contracts. (i) With the
exception of those transportation allowances specified in paragraphs
(c)(1)(v) and (c)(1)(vi) of this section, the lessee shall submit page
one of the initial Form MMS-4293 prior to, or at the same time as, the
transportation allowance determined pursuant to an arm's-length contract
is reported on Form MMS-4430, Solid Minerals Production and Royalty
Report.
(ii) The initial Form MMS-4293 shall be effective for a reporting
period beginning the month that the lessee is first authorized to deduct
a transportation allowance and shall continue until the end of the
calendar year, or until the applicable contract or rate terminates or is
modified or amended, whichever is earlier.
(iii) After the initial reporting period and for succeeding
reporting periods, lessees must submit page one of Form MMS-4293 within
3 months after the end of the calendar year, or after the applicable
contract or rate terminates or is modified or amended, whichever is
earlier, unless MMS approves a longer period (during which period the
lessee shall continue to use the allowance from the previous reporting
period). Lessees may request special reporting procedures in unique
allowance reporting situations, such as those related to spot sales.
(iv) MMS may require that a lessee submit arm's-length
transportation contracts, production agreements, operating agreements,
and related documents. Documents shall be submitted within a reasonable
time, as determined by MMS.
(v) Transportation allowances that are based on arm's-length
contracts and which are in effect at the time these regulations become
effective will be allowed to continue until such allowances terminate.
For the purposes of this section, only those allowances that have been
approved by MMS in writing shall qualify as being in effect at the time
these regulations become effective.
(vi) MMS may establish, in appropriate circumstances, reporting
requirements that are different from the requirements of this section.
(2) Non-arm's-length or no contract. (i) With the exception of those
transportation allowances specified in paragraphs (c)(2)(v) and
(c)(2)(vii) of this section, the lessee shall submit an initial Form
MMS-4293 prior to, or at the same time as, the transportation allowance
determined pursuant to a non-arm's-length contract or no contract
situation is reported on Form MMS-4430, Solid Minerals Production and
Royalty Report. The initial report may be based on estimated costs.
(ii) The initial Form MMS-4293 shall be effective for a reporting
period beginning the month that the lessee first
[[Page 161]]
is authorized to deduct a transportation allowance and shall continue
until the end of the calendar year, or until the transportation under
the non-arm's-length contract or the no contract situation terminates,
whichever is earlier.
(iii) For calendar-year reporting periods succeeding the initial
reporting period, the lessee shall submit a completed Form MMS-4293
containing the actual costs for the previous reporting period. If the
transportation is continuing, the lessee shall include on Form MMS-4293
its estimated costs for the next calendar year. The estimated
transportation allowance shall be based on the actual costs for the
previous reporting period plus or minus any adjustments that are based
on the lessee's knowledge of decreases or increases that will affect the
allowance. Form MMS-4293 must be received by MMS within 3 months after
the end of the previous reporting period, unless MMS approves a longer
period (during which period the lessee shall continue to use the
allowance from the previous reporting period).
(iv) For new transportation facilities or arrangements, the lessee's
initial Form MMS-4293 shall include estimates of the allowable
transportation costs for the applicable period. Cost estimates shall be
based upon the most recently available operations data for the
transportation system, or, if such data are not available, the lessee
shall use estimates based upon industry data for similar transportation
systems.
(v) Non-arm's-length contract or no contract-based transportation
allowances that are in effect at the time these regulations become
effective will be allowed to continue until such allowances terminate.
For purposes of this section, only those allowances that have been
approved by MMS in writing shall qualify as being in effect at the time
these regulations become effective.
(vi) Upon request by MMS, the lessee shall submit all data used to
prepare its Form MMS-4293. The data shall be provided within a
reasonable period of time, as determined by MMS.
(vii) MMS may establish, in appropriate circumstances, reporting
requirements that are different from the requirements of this section.
(viii) If the lessee is authorized to use its Federal-agency-
approved rate as its transportation cost in accordance with paragraph
(b)(3) of this section, it shall follow the reporting requirements of
paragraph (c)(1) of this section.
(3) MMS may establish reporting dates for individual lessees
different than those specified in this paragraph in order to provide
more effective administration. Lessees will be notified as to any change
in their reporting period.
(4) Transportation allowances must be reported as a separate line
item on Form MMS-4430, unless MMS approves a different reporting
procedure.
(d) Interest assessments for incorrect or late reports and failure
to report. (1) If a lessee deducts a transportation allowance on its
Form MMS-4430 without complying with the requirements of this section,
the lessee shall be liable for interest on the amount of such deduction
until the requirements of this section are complied with. The lessee
also shall repay the amount of any allowance which is disallowed by this
section.
(2) If a lessee erroneously reports a transportation allowance which
results in an underpayment of royalties, interest shall be paid on the
amount of that underpayment.
(3) Interest required to be paid by this section shall be determined
in accordance with 30 CFR 218.202.
(e) Adjustments. (1) If the actual transportation allowance is less
than the amount the lessee has taken on Form MMS-4430 for each month
during the allowance form reporting period, the lessee shall be required
to pay additional royalties due plus interest, computed pursuant to 30
CFR 218.202, retroactive to the first month the lessee is authorized to
deduct a transportation allowance. If the actual transportation
allowance is greater than the amount the lessee has estimated and taken
during the reporting period, the lessee shall be entitled to a credit,
without interest.
(2) The lessee must submit a corrected Form MMS-4430 to reflect
actual costs, together with any payment,
[[Page 162]]
in accordance with instructions provided by MMS.
(f) Other transportation cost determinations. The provisions of this
section shall apply to determine transportation costs when establishing
value using a net-back valuation procedure or any other procedure that
requires deduction of transportation costs.
[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999; 66
FR 45769, Aug. 30, 2001]
Sec. 206.462 [Reserved]
Sec. 206.463 In-situ and surface gasification and liquefaction operations.
If an ad valorem Federal coal lease is developed by in-situ or
surface gasification or liquefaction technology, the lessee shall
propose the value of coal for royalty purposes to MMS. MMS will review
the lessee's proposal and issue a value determination. The lessee may
use its proposed value until MMS issues a value determination.
[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999]
Sec. 206.464 Value enhancement of marketable coal.
If, prior to use, sale, or other disposition, the lessee enhances
the value of coal after the coal has been placed in marketable condition
in accordance with Sec. 206.456(h) of this subpart, the lessee shall
notify MMS that such processing is occurring or will occur. The value of
that production shall be determined as follows:
(a) A value established for the feedstock coal in marketable
condition by application of the provisions of Sec. 206.456(c)(2) (i)
through (iv) of this subpart; or,
(b) In the event that a value cannot be established in accordance
with paragraph (a) of this section, then the value of production will be
determined in accordance with Sec. 206.456(c)(2)(v) of this subpart and
the value shall be the lessee's gross proceeds accruing from the
disposition of the enhanced product, reduced by MMS-approved processing
costs and procedures including a rate of return on investment equal to
two times the Standard and Poor's BBB bond rate applicable under Sec.
206.458(b)(2)(v) of this subpart.
[61 FR 5481, Feb. 12, 1996, as amended 64 FR 43289, Aug. 10, 1999]
PART 207_SALES AGREEMENTS OR CONTRACTS GOVERNING THE DISPOSAL OF LEASE
PRODUCTS--Table of Contents
Subpart A_General Provisions
Sec.
207.1 Required recordkeeping.
207.2 Definitions.
207.3 Contracts made pursuant to new form leases.
207.4 Contracts made pursuant to old form leases.
207.5 Contract and sales agreement retention.
Subpart B--Oil, Gas and OCS Sulfur, General [Reserved]
Subpart C--Federal and Indian Oil [Reserved]
Subpart D--Federal and Indian Gas [Reserved]
Subpart E--Solid Minerals, General [Reserved]
Subpart F--Coal [Reserved]
Subpart G--Other Solid Minerals [Reserved]
Subpart H--Geothermal Resources [Reserved]
Subpart I--OCS Sulfur [Reserved]
Authority: 5 U.S.C. 301 et seq.; 25 U.S.C. 396 et seq.; 25 U.S.C.
396a et seq.; 25 U.S.C. 2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C.
351 et seq.; 30 U.S.C. 1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C.
3716 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et
seq.; and 43 U.S.C. 1801 et seq.
Source: 53 FR 1225, Jan. 15, 1988, unless otherwise noted.
Subpart A_General Provisions
Sec. 207.1 Required recordkeeping.
(a) The information collection and recordkeeping requirements
contained in this part have been approved by OMB under 44 U.S.C. 3501 et
seq. and assigned OMB Clearance Number 1010-0061. The information
collected will be
[[Page 163]]
used to determine a proper transportation allowance for the cost of
transporting royalty oil from the lease to a delivery point remote from
the lease. The information is required in order to obtain a benefit and
is collected in accordance with the Federal Oil and Gas Royalty
Management Act of 1982, 30 U.S.C. 1701 et seq.
(b) Public reporting burden is estimated to average 30 minutes per
year for each record keeper to maintain copies of sales contracts,
agreements, or other documents relevant to the valuation of production.
Send any comments regarding this burden estimate or any other aspect of
this requirement to the Information Collection Clearance Officer,
Minerals Management Service, 381 Elden Street, Herndon, VA 22070, and to
the Office of Information and Regulatory Affairs, Office of Management
and Budget, Paperwork Reduction Project 1010-0061, Washington, DC 20503.
[57 FR 41864, Sept. 14, 1992, as amended at 58 FR 64901, Dec. 10, 1994]
Sec. 207.2 Definitions.
The definitions in part 206 of this title are applicable to this
part.
Sec. 207.3 Contracts made pursuant to new form leases.
On November 29, 1950 (15 FR 8585), a new lease form was adopted
(Form 4-1158, 15 FR 8585) containing provisions whereby the lessee
agrees that nothing in any contract or other arrangement made for the
sale or disposal of oil, gas, natural gasoline, and other products of
the leased land, shall be construed as modifying any of the provisions
of the lease, including, but not limited to, provisions relating to gas
waste, taking royalty-in-kind, and the method of computing royalties due
as based on a minimum valuation and in accordance with the oil and gas
valuation regulations. A contract or agreement pursuant to a lease
containing such provisions may be made without obtaining prior approval
of the United States as lessor, but must be retained as provided in
Sec. 207.5 of this subpart.
Sec. 207.4 Contracts made pursuant to old form leases.
(a) Old form leases are those containing provisions prohibiting
sales or disposal of oil, gas, natural gasoline, and other products of
the lease except in accordance with a contract or other arrangement
approved by the Secretary of the Interior, or by the Director of the
Minerals Management Service or his/her representative. A contract or
agreement made pursuant to an old form lease may be made without
obtaining approval if the contract or agreement contains either the
substance of or is accompanied by the stipulation set forth in paragraph
(b) of this section, signed by the seller (lessee or operator).
(b) The stipulation, the substance of which must be included in the
contract, or be made the subject matter of a separate instrument
properly identifying the leases affected thereby, is as follows:
It is hereby understood and agreed that nothing in the written
contract or in any approval thereof shall be construed as affecting any
of the relations between the United States and its lessee, particularly
in matters of gas waste, taking royalty in kind, and the method of
computing royalties due as based on a minimum valuation and in
accordance with the terms and provisions of the oil and gas valuation
regulations applicable to the lands covered by said contract.
Sec. 207.5 Contract and sales agreement retention.
Copies of all sales contracts, posted price bulletins, etc., and
copies of all agreements, other contracts, or other documents which are
relevant to the valuation of production are to be maintained by the
lessee and made available upon request during normal working hours to
authorized MMS, State or Indian representatives, other MMS or BLM
officials, auditors of the General Accounting Office, or other persons
authorized to receive such documents, or shall be submitted to MMS
within a reasonable period of time, as determined by MMS. Any oral sales
arrangement negotiated by the lessee must be placed in written form and
retained by the lessee. Records shall be retained in accordance with 30
CFR part 212.
[[Page 164]]
Subpart B--Oil, Gas, and OCS Sulfur, General [Reserved]
Subpart C--Federal and Indian Oil [Reserved]
Subpart D--Federal and Indian Gas [Reserved]
Subpart E--Solid Minerals, General [Reserved]
Subpart F--Coal [Reserved]
Subpart G--Other Solid Minerals [Reserved]
Subpart H--Geothermal Resources [Reserved]
Subpart I--OCS Sulfur [Reserved]
PART 208_SALE OF FEDERAL ROYALTY OIL--Table of Contents
Subpart A_General Provisons
Sec.
208.1 General.
208.2 Definitions.
208.3 Information collection.
208.4 Royalty oil sales to eligible refiners.
208.5 Notice of royalty oil sale.
208.6 General application procedures.
208.7 Determination of eligibility.
208.8 Transportation and delivery.
208.9 Agreements.
208.10 Notices.
208.11 Surety requirements.
208.12 Payment requirements.
208.13 Reporting requirements.
208.14 Civil and criminal penalties.
208.15 Audits.
208.16 How to appeal a contracting officer's decision that you receive.
208.17 Suspensions for national emergencies.
Authority: 5 U.S.C. 301 et seq.; 30 U.S.C. 181 et seq., 351 et seq.,
1701 et seq.; 31 U.S.C. 9701; 41 U.S.C. 601 et seq.; 43 U.S.C. 1301 et
seq., 1331 et seq., and 1801 et seq.
Source: 52 FR 41913, Oct. 30, 1987, unless otherwise noted.
Subpart A_General Provisions