[Title 30 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2003 Edition]
[From the U.S. Government Printing Office]
[[Page i]]
30
Parts 200 to 699
Revised as of July 1, 2003
Mineral Resources
Containing a codification of documents of general
applicability and future effect
As of July 1, 2003
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 563
Chapter IV--Geological Survey, Department of the
Interior 567
Finding Aids:
Material Approved for Incorporation by Reference........ 581
Table of CFR Titles and Chapters........................ 589
Alphabetical List of Agencies Appearing in the CFR...... 607
List of CFR Sections Affected........................... 617
----------------------------
Cite this Code: CFR
To cite the regulations in
this volume use title,
part and section number.
Thus, 30 CFR 201.100
refers to title 30, part
201, section 100.
----------------------------
EXPLANATION
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July 1, 2003.
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, 2003.
[[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
Cross References: Bureau of Land Management, Department of the Interior,
regulations with respect to mineral lands: 43 CFR, chapter II,
subchapter C.
Foreign Trade Statistics, Bureau of the Census, Department of
Commerce: 15 CFR part 30.
Forest Service regulations relating to mineral developments and mining
in national forests: 36 CFR part 228.
General Services Administration regulations for stockpiling of
strategic and critical materials: 41 CFR chapter 101, subchapter C.
Interstate Commerce Commission: 49 CFR chapter X.
Bureau of Indian Affairs, Department of the Interior, energy and
minerals regulations: 25 CFR chapter I, subchapter I.
Other regulations issued by the Department of the Interior appear in
title 25, chapters I and II; title 36, chapter I; title 41, chapter 114;
title 43; and title 50, chapters I and IV.
[[Page 3]]
CHAPTER II--MINERALS MANAGEMENT SERVICE,
DEPARTMENT OF THE INTERIOR
(Parts 200 to 699)
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SUBCHAPTER A--ROYALTY MANAGEMENT
Part Page
201 General..................................... 5
202 Royalties................................... 5
203 Relief or reduction in royalty rates........ 13
206 Product valuation........................... 35
207 Sales agreements or contracts governing the
disposal of lease products.............. 144
208 Sale of Federal royalty oil................. 146
210 Forms and reports........................... 154
212 Records and files maintenance............... 166
215
Accounting and auditing standards [Reserved]
216 Production accounting....................... 168
217 Audits and inspections...................... 174
218 Collection of royalties, rentals, bonuses
and other monies due the Federal
Government.............................. 175
219 Distribution and disbursement of royalties,
rentals, and bonuses.................... 190
220 Accounting procedures for determining net
profit share payment for Outer
Continental Shelf oil and gas leases.... 191
227 Delegation to States........................ 205
228 Cooperative activities with States and
Indian tribes........................... 216
229 Delegation to States........................ 220
230
Recoupments and refunds [Reserved]
232
Interest payments [Reserved]
233
Escrow and investments [Reserved]
234
Bonding--payment liability [Reserved]
241 Penalties................................... 227
242
Orders [Reserved]
[[Page 4]]
243 Suspensions pending appeal and bonding--
Minerals revenue management............. 233
SUBCHAPTER B--OFFSHORE
250 Oil and gas and sulphur operations in the
Outer Continental Shelf................. 239
251 Geological and geophysical (G & G)
explorations of the Outer Continental
Shelf................................... 427
252 Outer Continental Shelf (OCS) oil and gas
information program..................... 440
253 Oil spill financial responsibility for
offshore facilities..................... 445
254 Oil-spill response requirements for
facilities located seaward of the coast
line.................................... 459
256 Leasing of sulphur or oil and gas in the
Outer Continental Shelf................. 471
259 Mineral leasing: Definitions................ 499
260 Outer Continental Shelf oil and gas leasing. 500
270 Nondiscrimination in the Outer Continental
Shelf................................... 508
280 Prospecting for minerals other than oil,
gas, and sulfur on the Outer Continental
Shelf................................... 509
281 Leasing of minerals other than oil, gas, and
sulphur in the Outer Continental Shelf.. 521
282 Operations in the Outer Continental Shelf
for minerals other than oil, gas, and
sulphur................................. 534
SUBCHAPTER C--APPEALS
290 Appeals procedures.......................... 557
[[Page 5]]
SUBCHAPTER A--ROYALTY MANAGEMENT
PART 201--GENERAL--Table of Contents
Subpart A--General Provisions [Reserved]
Subpart B--Oil and Gas, General [Reserved]
Subpart C--Oil and Gas, Onshore
Sec.
201.100 Responsibilities of the Associate Director for 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.
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) Royalties on geothermal resources, including byproduct minerals
and commercially demineralized water, shall be at the royalty rate(s)
specified in the lease, unless the Secretary of the Interior temporarily
waives, suspends, or reduces that rate(s). Royalties shall be paid in
value. The royalty due shall be the value determined pursuant to subpart
H of 30 CFR part 206 multiplied by the royalty rate in the lease.
(b)(1) Royalties are due on all geothermal resources, except those
specified in paragraph (b)(2) of this section, that are produced from a
lease and are sold or utilized by the lessee or are reasonably
susceptible to sale or utilization by the lessee.
(2) Geothermal resources that are unavoidably lost, as determined by
the Bureau of Land Management (BLM), and geothermal resources that are
reinjected prior to use on or off the lease, as approved by BLM, are not
subject to royalty. The Minerals Management Service (MMS) will allow
free of royalty a reasonable amount of geothermal energy necessary to
generate electricity for internal powerplant operations or to generate
electricity returned to the lease for lease operations. If a powerplant
uses geothermal production from more than one lease, or uses unitized or
communitized production, only that proportionate share of each lease's
production (actual or allocated) necessary to operate the powerplant may
be used royalty free. The MMS will also allow free of royalty a
reasonable amount of commercially demineralized water necessary for
powerplant operations or otherwise used on or for the benefit of the
lease.
(3) Royalties on byproducts are due at the time the recovered
byproduct is used, sold, or otherwise finally disposed of. Byproducts
produced and added to stockpiles or inventory do not require payment of
royalty until the byproducts are sold, utilized, or otherwise finally
disposed of. The MMS may ask BLM to increase the lease bond to protect
the lessor's interest when BLM determines that stockpiles or inventories
become excessive.
(c) If BLM determines that geothermal resources (including
byproducts) were avoidably lost or wasted from the lease, or that
geothermal resources (including byproducts) were drained from the lease
for which compensatory royalty is due, the value of those geothermal
resources shall be determined in accordance with subpart H of 30 CFR
part 206.
[[Page 11]]
(d) If a lessee receives insurance or other compensation for
unavoidably lost geothermal resources (including byproducts), royalties
at the rates specified in the lease are due on the amount of that
compensation. This paragraph shall not apply to compensation through
self-insurance.
Sec. 202.352 Minimum royalty.
In no event shall the lessee's annual royalty payments for any
producing lease be less than the minimum royalty established by the
lease.
Sec. 202.353 Measurement standards for reporting and paying royalties.
(a) For geothermal resources used to generate electricity, the
quantity on which royalty is due shall be reported on Form MMS-2014
(Report of Sales and Royalty Remittance) as follows:
(1) For geothermal resources valued under arm's-length or non-arm's-
length contracts, quantities shall be reported in:
(i) Kilowatthours to the nearest whole kilowatthour if the contract
specifies payment in terms of generated electricity,
(ii) Thousands of pounds to the nearest whole thousand pounds if the
contract specifies payment in terms of weight, or
(iii) Millions of Btu's to the nearest whole million Btu if the
contract specifies payment in terms of heat or thermal energy.
(2) For geothermal resources valued by the netback procedure
pursuant to 30 CFR 206.352(c)(1)(ii) or (d)(1)(ii), the quantities shall
be reported in kilowatthours to the nearest whole kilowatthour.
(b) For geothermal resources used in direct utilization processes,
the quantity on which royalty is due shall be reported on Form MMS-2014
in:
(1) Millions of Btu's to the nearest whole million Btu if valuation
is in terms of thermal energy used or displaced,
(2) Hundreds of gallons to the nearest hundred gallons of geothermal
fluid produced if valuation is in terms of volume, or
(3) Other measurement unit approved by MMS for valuation and
reporting purposes.
(c) For byproduct minerals, the quantity on which royalty is due
shall be reported on Form MMS-2014 consistent with MMS-established
reporting standards.
(d) For commercially demineralized water, the quantity on which
royalty is due shall be reported on Form MMS-2014 in hundreds of gallons
to the nearest hundred gallons.
(e) Lessees are not required to report the quality of geothermal
resources, including byproducts, to MMS. The lessee must maintain
quality measurements for audit and valuation purposes. Quality
measurements include, but are not limited to, temperatures and chemical
analyses for fluid geothermal resources and chemical analyses, weight
percent, or other purity measurements for byproducts.
Subpart I--OCS Sulfur [Reserved]
Subpart J-- Gas Production From Indian Leases
Source: 64 FR 43514, Aug. 10, 1999, unless otherwise noted.
Sec. 202.550 How do I determine the royalty due on gas production?
If you produce gas from an Indian lease subject to this subpart, you
must determine and pay royalties on gas production as specified in this
section.
(a) Royalty rate. You must calculate your royalty using the royalty
rate in the lease.
(b) Payment in value or in kind. You must pay royalty in value
unless:
(1) The Tribal lessor requires payment in kind; or
(2) You have a lease on allotted lands and MMS requires payment in
kind.
(c) Royalty calculation. You must use the following calculations to
determine royalty due on the production from or attributable to your
lease.
(1) When paid in value, the royalty due is the unit value of
production for royalty purposes, determined under 30 CFR part 206,
multiplied by the volume of production multiplied by the royalty rate in
the lease.
(2) When paid in kind, the royalty due is the volume of production
multiplied by the royalty rate.
[[Page 12]]
(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 Secs. 202.555,
202.556, and 202.557.
(b) You and all other persons paying royalties on the lease must
report and pay royalties based on your takes. If another person takes
some of your entitled share but does not pay the royalties owed, you are
liable for those royalties.
(c) You and all other persons paying royalties on the lease may ask
MMS for permission to report and pay royalties based on your
entitlements. In that event, MMS will provide valuation instructions
consistent with this part and part 206 of this title.
Sec. 202.552 How do I determine how much royalty I must pay if my lease
is in an approved Federal unit or communitization agreement (AFA)?
You must pay royalties each month on production allocated to your
lease under the terms of an AFA. To determine the volume and the value
of your production, you must follow these three steps:
(a) You must determine the volume of your entitled share of
production allocated to your lease under the terms of an AFA. This may
include production from more than one AFA.
(b) You must value the production you take using 30 CFR part 206. If
you take more than your entitled share of production, see Sec. 202.553
for information on how to value this production. If you take less than
your entitled share of production, see Sec. 202.554 for information on
how to value production you are entitled to but do not take.
Sec. 202.553 How do I value my production if I take more than my
entitled share?
If you take more than your entitled share of production from a lease
in an AFA for any month, you must determine the weighted-average value
of all of the production that you take using the procedures in 30 CFR
part 206, and use that value for your entitled share of production.
Sec. 202.554 How do I value my production that I do not take if I take
less than my entitled share?
If you take none or only part of your entitled production from a
lease in an AFA for any month, use this section to value the production
that you are entitled to but do not take.
(a) If you take a significant volume of production from your lease
during the month, you must determine the weighted average value of the
production that you take using 30 CFR part 206, and use that value for
the production that you do not take.
(b) If you do not take a significant volume of production from your
lease during the month, you must use paragraph (c) or (d) of this
section, whichever applies.
(c) In a month where you do not take production or take an
insignificant volume, and if you would have used Sec. 206.172(b) to
value the production if you had taken it, you must determine the value
of production not taken for that month under Sec. 206.172(b) as if you
had taken it.
(d) If you take none of your entitled share of production from a
lease in an AFA, and if that production cannot be valued under
Sec. 206.172(b), then you must determine the value of the production
that you do not take using the first of the following methods that
applies:
(1) The weighted average of the value of your production (under 30
CFR part 206) in that month from other leases in the same AFA.
(2) The weighted average of the value of your production (under 30
CFR part 206) in that month from other leases in the same field or area.
(3) The weighted average of the value of your production (under 30
CFR part 206) during the previous month for production from leases in
the same AFA.
[[Page 13]]
(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 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?
[[Page 14]]
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?
Subpart B--OCS Oil, Gas, and Sulfur General
Royalty Relief for end-of-life Leases
203.50 Who may apply for end-of-life royalty relief?
203.51 How do I apply for end-of-life royalty relief?
203.52 What criteria must I meet to get relief?
203.53 What relief will MMS grant?
203.54 How does my relief arrangement for an oil and gas lease operate
if prices rise sharply?
203.55 Under what conditions can my end-of-life royalty relief
arrangement for an oil and gas lease be ended?
203.56 Does relief transfer when a lease is assigned?
Royalty Relief For Deep Water Expansion Projects And Pre-Act Deep Water
Leases
203.60 Who may apply for deep water royalty relief?
203.61 How do I assess my chances for getting relief?
203.62 How do I apply for relief?
203.63 Does my application have to include all leases in the field?
203.64 How many applications may I file on a field or a development
project?
203.65 How long will MMS take to evaluate my application?
203.66 What happens if MMS does not act in the time allowed?
203.67 What economic criteria must I meet to get royalty relief on an
authorized field or project?
203.68 What pre-application costs will MMS consider in determining
economic viability?
203.69 If my application is approved, what royalty relief will I
receive?
203.70 What information must I provide after MMS approves relief?
203.71 How does MMS allocate a field's suspension volume between my
lease and other leases on my field?
203.72 Can my lease receive more than one suspension volume?
203.73 How do suspension volumes apply to natural gas?
203.74 When will MMS reconsider its determination?
203.75 What risk do I run if I request a redetermination?
203.76 When might MMS withdraw or reduce the approved size of my
relief?
203.77 May I voluntarily give up relief if conditions change?
203.78 Do I keep relief if prices rise significantly?
203.79 How do I appeal MMS's decisions related to Deep Water Royalty
Relief?
203.80 When can I get royalty relief if I am not eligible for end-of-
life or deep water royalty relief?
Required Reports
203.81 What supplemental reports do royalty-relief applications
require?
203.82 What is MMS's authority to collect this information?
203.83 What is in an administrative information report?
203.84 What is in a net revenue and relief justification report?
203.85 What is in an economic viability and relief justification
report?
203.86 What is in a G&G report?
203.87 What is in an engineering report?
203.88 What is in a production report?
203.89 What is in a deep water cost report?
203.90 What is in a fabricator's confirmation report?
203.91 What is in a post-production development report?
Subpart C--Federal and Indian Oil [Reserved]
Subpart D--Federal and Indian Gas [Reserved]
Subpart E--Solid Minerals, General [Reserved]
Subpart F--Coal
203.250 Advance royalty.
203.251 Reduction in royalty rate or rental.
Subpart G--Other Solid Minerals [Reserved]
Subpart H--Geothermal Resources [Reserved]
Subpart I--OCS Sulfur [Reserved]
Authority: 25 U.S.C. 396 et seq.; 25 U.S.C. 396a et seq.; 25 U.S.C.
2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.; 30 U.S.C.
1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et
seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C. 1801 et seq.
Subpart A--General Provisions
Source: 63 FR 2616, Jan. 16, 1998, unless otherwise noted.
[[Page 15]]
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.
Complete application means an original and two copies of the six
reports consisting of the data specified in 30 CFR 203.81, 203.83 and
203.85 through 203.89, along with one set of digital information, which
MMS has reviewed and found complete.
Determination means the binding decision by MMS on whether your
field qualifies for relief or how large a royalty-suspension volume must
be to make the field economically viable.
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.
Performance conditions means minimum conditions you must meet, after
[[Page 16]]
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.
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.
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.
Sunk costs for an authorized field means the after-tax eligible
costs that you (not third parties) incur for exploration, development,
and production from the spud date of the first discovery on the field to
the date we receive your complete application for royalty relief. The
discovery well must be qualified as producible under part 250, subpart A
of this title. Sunk costs include the rig mobilization and material
costs for the discovery well that you incurred before its spud date.
Sunk costs for an expansion or development project means the after-
tax eligible costs that you (not third parties) incur for only the first
well that encounters hydrocarbons in the reservoir(s) included in the
application and that meets the producibility requirements under part
250, subpart A of this chapter on each lease participating in the
application. Sunk costs include rig mobilization and material costs for
the discovery wells that you incurred before their spud dates.
Withdraw means action we take on a field that has qualified for
relief if you have not met one or more of the performance conditions.
[63 FR 2616, Jan. 16, 1998, as amended at 67 FR 1872, Jan. 15, 2002]
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
[[Page 17]]
(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 Secs. 203.50
is economic under through 203.56.)
the existing
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 Secs. 203.60
producing on the through 203.79.)
field or lease,
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). Secs. 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 Secs. 203.60
project). 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.
------------------------------------------------------------------------
[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 how similar provisions of this
part apply in different situations.
(a) We require the information elements indicated by an X in the
following table and described in Secs. 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)......................................
[[Page 18]]
(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 Secs. 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 Secs. 203.50, 203.52,
203.60 and 203.67 describe, the prerequisites for our approval of your
royalty relief application.
----------------------------------------------------------------------------------------------------------------
Deep water
End-of- ------------------------------------------
Approval conditions life Pre-act Development
lease Expansion lease project
----------------------------------------------------------------------------------------------------------------
(1) At least 12 of the last 15 months have the required X
level of production......................................
(2) Already producing..................................... X
(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., X
platform, subsea template)...............................
(6) Determined to be economic only with relief............ X X X
----------------------------------------------------------------------------------------------------------------
(d) The following table indicates by an X, and Secs. 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 Secs. 203.53 and
203.69 describe, the characteristics of approved royalty relief.
[[Page 19]]
----------------------------------------------------------------------------------------------------------------
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 Secs. 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 Secs. 203.55 and
203.76 through 203.77 describe, circumstances under which we end or
reduce royalty relief.
----------------------------------------------------------------------------------------------------------------
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]
Subpart B--OCS Oil, Gas, and Sulfur General
Source: 63 FR 2618, Jan. 16, 1998, unless otherwise noted.
Royalty Relief for End-of-life Leases
Sec. 203.50 Who may apply for end-of-life royalty relief?
You may apply for royalty relief in two situations.
(a) Your end-of-life lease (as defined in Sec. 203.2) is an oil and
gas lease and has average daily production of at least 100 barrels of
oil equivalent (BOE) per
[[Page 20]]
month (as calculated in Sec. 203.73) in at least 12 of the past 15
months. The most recent of these 12 months are considered the qualifying
months. These 12 months should reflect the basic operation you intend to
use until your resources are depleted. If you changed your operation
significantly (e.g., begin re-injecting rather than recovering gas)
during the qualifying months, or if you do so while we are processing
your application, we may defer action on your application until you
revise it to show the new circumstances.
(b) Your end-of-life lease is other than an oil and gas lease (e.g.,
sulphur) and has production in at least 12 of the past 15 months. The
most recent of these 12 months are considered the qualifying months.
[63 FR 2618, Jan. 16, 1998, as amended at 63 FR 57249, Oct. 27, 1998]
Sec. 203.51 How do I apply for end-of-life royalty relief?
You must submit a complete application and the required fee to the
appropriate MMS Regional Director. Your MMS regional office will provide
specific guidance on the report formats. A complete application for
relief includes:
(a) An administrative information report (specified in Sec. 203.83)
and
(b) A net revenue and relief justification report (specified in
Sec. 203.84).
Sec. 203.52 What criteria must I meet to get relief?
(a) To qualify for relief, you must demonstrate that the sum of
royalty payments over the 12 qualifying months exceeds 75 percent of the
sum of net revenues (before-royalty revenues minus allowable costs, as
defined in Sec. 203.84).
(b) To re-qualify for relief, e.g., either applying for additional
relief on top of relief already granted, or applying for relief sometime
after your earlier agreement terminated, you must demonstrate that:
(1) You have met the criterion listed in paragraph (a) of this
section, and
(2) The 12 required qualifying months of operation have occurred
under the current royalty arrangement.
Sec. 203.53 What relief will MMS grant?
(a) If we approve your application and you meet certain conditions,
we will reduce the pre-application effective royalty rate by one-half on
production up to the relief volume amount. If you produce more than the
relief volume amount:
(1) We will impose a royalty rate equal to 1.5 times the effective
royalty rate on your additional production up to twice the relief volume
amount; and
(2) We will impose a royalty rate equal to the effective rate on all
production greater than twice the relief volume amount.
(b) Regardless of the level of production or prices (see
Sec. 203.54), royalty payments due under end-of-life relief will not
exceed the royalty obligations that would have been due at the effective
royalty rate.
(1) The effective royalty rate is the average lease rate paid on
production during the 12 qualifying months.
(2) The relief volume amount is the average monthly BOE production
for the 12 qualifying months.
Sec. 203.54 How does my relief arrangement for an oil and gas lease
operate if prices rise sharply?
In those months when your current reference price rises by at least
25 percent above your base reference price, you must pay the effective
royalty rate on all monthly production.
(a) Your current reference price is a weighted average of daily
closing prices on the NYMEX for light sweet crude oil and natural gas
over the most recent full 12 calendar months;
(b) Your base reference price is a weighted average of daily closing
prices on the NYMEX for light sweet crude oil and natural gas during the
qualifying months; and
(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
[[Page 21]]
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 Secs. 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
(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]
[[Page 22]]
Sec. 203.63 Does my application have to include all leases in the field?
(a) For authorized fields, we will accept only one joint application
for all leases that are part of the designated field on the date of
application, except as provided in paragraph (a)(3) of this section and
Sec. 203.64. However, we will evaluate all acreage that may eventually
become part of the authorized field. Therefore, if you have any other
leases that you believe may eventually be part of the authorized field,
you must submit data for these leases according to Sec. 203.81.
(1) The Regional Director maintains a Field Names Master List with
updates of all leases in each designated field.
(2) To avoid sharing proprietary data with other lessees on the
field, you may submit your proprietary G&G report separately from the
rest of your application. Your application is not complete until we
receive all the required information for each lease on the field. We
will not disclose proprietary data when explaining our assumptions and
reasons for our determinations under Sec. 203.67.
(3) We will not require a joint application if you show good cause
and honest effort to get all lessees in the field to participate. If you
must exclude a lease from your application because its lessee will not
participate, that lease is ineligible for the royalty relief for the
designated field.
(b) If your application seeks only relief for a development project
or an expansion project, your application does not have to include all
leases in the field.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]
Sec. 203.64 How many applications may I file on a field or a development
project?
You may file one complete application for royalty relief during the
life of the field or for a development project or an expansion project
designed to produce a reservoir or set of reservoirs. However, you may
send another application if:
(a) You are eligible to apply for a redetermination under
Sec. 203.74;
(b) You apply for royalty relief for an expansion project;
(c) You withdraw the application before we make a determination; or
(d) You apply for end-of-life royalty relief.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]
Sec. 203.65 How long will MMS take to evaluate my application?
(a) We will determine within 20 working days if your application for
royalty relief is complete. If your application is incomplete, we will
explain in writing what it needs. If you withdraw a complete
application, you may reapply.
(b) We will evaluate your first application on a field within 180
days, evaluate your first application on a development project or an
expansion project within 150 days and evaluate a redetermination under
Sec. 203.75 within 120 days after we determine that it is complete.
(c) We may ask to extend the review period for your application
under the conditions in the following table.
------------------------------------------------------------------------
If-- Then we may--
------------------------------------------------------------------------
We need more records to audit sunk Ask to extend the 120-day or 180-
costs. day evaluation period. The
extension we request will equal
the number of days between when
you receive our request for
records and the day we receive the
records.
We cannot evaluate your application Add another 30 days. We may add
for a valid reason, such as more than 30 days, but only if you
missing vital information or agree.
inconsistent or inconclusive
supporting data.
We need more data, explanations, or Ask to extend the 120-day or 180-
revision. day evaluation period. The
extension we request will equal
the number of days between when
you receive our request and the
day we receive the information.
------------------------------------------------------------------------
[[Page 23]]
(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 Secs.
minimum 203.70 and
suspension 203.76.
volumes specified
in Sec. 203.69.
(b) An expansion project........ You get a royalty Abide by Secs.
suspension for 203.70 and
the first year of 203.76.
production.
(c) A development project....... You get a royalty Abide by Secs.
suspension for 203.70 and
initial 203.76.
production for
the number of
months that a
decision is
delayed beyond
the stipulated
timeframes set by
Sec. 203.65,
plus all the
royalty
suspension volume
for which you
qualify.
------------------------------------------------------------------------
[67 FR 1875, Jan. 15, 2002]
Sec. 203.67 What economic criteria must I meet to get royalty relief on
an authorized field or project?
We will not approve applications if we determine that royalty relief
cannot make the field, development project, or expansion project
economically viable. Your field or project must be uneconomic while you
are paying royalties and must become economic with royalty relief.
[67 FR 1876, Jan. 15, 2002]
Sec. 203.68 What pre-application costs will MMS consider in determining
economic viability?
(a) We will not consider ineligible costs as set forth in
Sec. 203.89(h) in determining economic viability for purposes of royalty
relief.
(b) We will consider sunk costs according to the following table.
------------------------------------------------------------------------
We will When determining
------------------------------------------------------------------------
(1) Include sunk costs................. Whether a field that includes a
pre-Act lease which has not
produced, other than test
production, before the
application or redetermination
submission date needs relief
to become economic.
(2) Not include sunk costs............. Whether an authorized field, a
development project, or an
expansion project can become
economic with full relief (see
Sec. 203.67).
(3) Not include sunk costs............. How much suspension volume is
necessary to make the field, a
development project, or an
expansion project economic
(see Sec. 203.69(c)).
(4) Include sunk costs for the project Whether a development project
discovery well on each lease. or an expansion project needs
relief to become economic.
------------------------------------------------------------------------
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1876, Jan. 15, 2002]
Sec. 203.69 If my application is approved, what royalty relief will
I receive?
If we approve your application, subject to certain conditions, we
will not collect royalties on a specified suspension volume for your
field, development project, or expansion project. Suspension volumes
include volumes allocated to a lease under an approved unit agreement,
but exclude any volumes of production that are not normally royalty-
bearing under the lease or the regulations of this chapter (e.g., fuel
gas).
(a) For authorized fields, the minimum royalty-suspension volumes
are:
[[Page 24]]
(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 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.
------------------------------------------------------------------------
[[Page 25]]
[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 Secs. 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.
(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.
[[Page 26]]
(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 Secs. 203.67 and diminish. (ii) The eligible
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 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
[[Page 27]]
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 Secs. 203.85 and 203.88) from your most
recently approved application for this royalty relief.
(d) Before starting to build your development and production system,
you have revised your estimated development costs, and they are more
than 120 percent of the eligible development costs associated with the
most likely scenario from your most recently approved application for
this royalty relief.
[63 FR 2618, Jan. 16, 1998; 63 FR 24747, May 5, 1998, as amended at 67
FR 1878, Jan. 15, 2002]
Sec. 203.75 What risk do I run if I request a redetermination?
If you request a redetermination after we have granted you a
suspension volume, you could lose some or all of the previously granted
relief. This can happen because you must file a new complete application
and pay the required fee, as discussed in Sec. 203.62. We will evaluate
your application under Sec. 203.67 using the conditions prevailing at
the time of your redetermination request. In our evaluation, we may find
that you should receive a larger, equivalent, smaller, or no suspension
volume. This means we could find that you do not qualify for the amount
of relief previously granted or for any relief at all.
Sec. 203.76 When might MMS withdraw or reduce the approved size of
my relief?
We will withdraw approval of relief for any of the following
reasons.
(a) You change the type of development system proposed in your
application (e.g., change from a fixed platform to floating production
system, or from an independent development and production system to one
with subsea wells tied back to a host production facility, etc.).
(b) You do not start building the proposed development and
production system within18 months of the date we approved your
application, unless the MMS Director grants you an extension under
Sec. 203.79(c). If you start building the proposed system and then
suspend its construction before completion, and you do not restart
continuous building of the proposed system within 18 months of our
approval, we will withdraw the relief we granted.
(c) Your actual development costs are less than 80 percent of the
eligible development costs estimated in your application's most likely
scenario, and you do not report that fact in your post-production
development report (Sec. 203.70). Development costs are those
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.
[[Page 28]]
(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:
(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.
[[Page 29]]
(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 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
[[Page 30]]
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 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
[[Page 31]]
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;
(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
(Secs. 203.86 through 203.89) and
[[Page 32]]
(2) The development and production scenarios provided in the various
reports are consistent with each other and with the proposed development
system. You can use up to three scenarios (conservative, most likely,
and optimistic), but you must link each to a specific range on the
distribution of resources from the RSVP Resource Module.
Sec. 203.86 What is in a G&G report?
This report supports the reserve and resource estimates used in the
economic evaluation and must contain each of the following elements.
(a) Seismic data which includes:
(1) Non-interpreted 2D/3D survey lines reflecting any available
state-of-the-art processing technique in a format readable by MMS and
specified by the deep water royalty relief guidelines;
(2) Interpreted 2D/3D seismic survey lines reflecting any available
state-of-the-art processing technique identifying all known and
prospective pay horizons, wells, and fault cuts;
(3) Digital velocity surveys in the format of the GOM region's
letter to lessees of 10/1/90;
(4) Plat map of ``shot points;'' and
(5) ``Time slices'' of potential horizons.
(b) Well data which includes:
(1) Hard copies of all well logs in which--
(i) The 1-inch electric log shows pay zones and pay counts and
lithologic and paleo correlation markers at least every 500-feet,
(ii) The 1-inch type log shows missing sections from other logs
where faulting occurs,
(iii) The 5-inch electric log shows pay zones and pay counts and
labeled points used in establishing resistivity of the formation, 100
percent water 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
[[Page 33]]
(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.
(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
[[Page 34]]
spending, current authorization for expenditure, engineering estimates,
or analogous projects. These costs cover:
(1) Platform well drilling and average depth;
(2) Platform well completion;
(3) Subsea well drilling and average depth;
(4) Subsea well completion;
(5) Production system (platform); and
(6) Flowline fabrication and installation.
(c) Production costs based on historical costs, engineering
estimates, or analogous projects. These costs cover:
(1) Operation;
(2) Equipment; and
(3) Existing royalty overrides (we will not use the royalty
overrides in evaluations).
(d) Transportation costs, based on historical costs, engineering
estimates, or analogous projects. These costs cover:
(1) Oil or gas tariffs from pipeline or tankerage;
(2) Trunkline and tieback lines; and
(3) Gas plant processing for natural gas liquids.
(e) Abandonment costs, based on historical costs, engineering
estimates, or analogous projects. You should provide the costs to plug
and abandon only wells and to remove only production systems for which
you have not incurred costs as of the time of application submission.
You should also include a point estimate or distribution of prospective
salvage value for all potentially reusable facilities and materials,
along with the source and an explanation of the figures provided.
(f) A set of cost estimates consistent with each one of up to three
field-development scenarios and production profiles (conservative, most
likely, optimistic). You should express costs in constant real dollar
terms for the base year. You may also express the uncertainty of each
cost estimate with a minimum and maximum percentage of the base value.
(g) A spending schedule. You should provide costs for each year (in
real dollars) for each category in paragraphs (a) through (f) of this
section.
(h) A summary of other costs which are ineligible for evaluating
your need for relief. These costs cover:
(1) Expenses before first discovery on the field;
(2) Cash bonuses;
(3) Fees for royalty relief applications;
(4) Lease rentals, royalties, and payments of net profit share and
net revenue share;
(5) Legal expenses;
(6) Damages and losses;
(7) Taxes;
(8) Interest or finance charges, including those embedded in
equipment leases;
(9) Fines or penalties; and
(10) Money spent on previously existing obligations (e.g., royalty
overrides or other forms of payment for acquiring a financial position
in a lease, expenditures for plugging wells and removing and abandoning
facilities that existed on the application submission date).
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]
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
[[Page 35]]
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]
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 index price publications are acceptable to MMS?
206.105 What records must I keep to support my calculations of value
under this subpart?
206.106 What are my responsibilities to place production into
marketable condition and to market production?
206.107 How do I request a value determination?
206.108 Does MMS protect information I provide?
206.109 When may I take a transportation allowance in determining
value?
206.110 How do I determine a transportation allowance under an arm's-
length transportation contract?
206.111 How do I determine a transportation allowance under a non-
arm's-length transportation arrangement?
206.112 What adjustments and transportation allowances apply when I
value oil using index pricing?
206.113 How will MMS identify market centers?
206.114 What are my reporting requirements under an arm's-length
transportation contract?
206.115 What are my reporting requirements under a non-arm's-length
transportation arrangement?
206.116 What interest and assessments apply if I improperly report a
transportation allowance?
206.117 What reporting adjustments must I make for transportation
allowances?
206.118 Are actual or theoretical losses permitted as part of a
transportation allowance?
206.119 How are the royalty quantity and quality determined?
206.120 How are operating allowances determined?
206.121 Is there any grace period for reporting and paying royalties
after this subpart becomes effective?
Subpart D--Federal Gas
206.150 Purpose and scope.
206.151 Definitions.
206.152 Valuation standards--unprocessed gas.
206.153 Valuation standards--processed gas.
206.154 Determination of quantities and qualities for computing
royalties.
206.155 Accounting for comparison.
206.156 Transportation allowances--general.
206.157 Determination of transportation allowances.
[[Page 36]]
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 Purpose and scope.
206.351 Definitions.
206.352 Valuation standards for electrical generation.
206.353 Determination of transmission deductions.
206.354 Determination of generating deductions.
206.355 Valuation standards for direct utilization.
206.356 Valuation standards for byproducts.
206.357 Byproduct transportation allowances--general.
206.358 Determination of byproduct transportation allowances.
Subpart I--OCS Sulfur [Reserved]
Subpart J--Indian Coal
206.450 Purpose and scope.
206.451 Definitions.
206.452 Coal subject to royalties--general provisions.
206.453 Quality and quantity measurement standards for reporting and
paying royalties.
206.454 Point of royalty determination.
206.455 Valuation standards for cents-per-ton leases.
206.456 Valuation standards for ad valorem leases.
206.457 Washing allowances--general.
206.458 Determination of washing allowances.
206.459 Allocation of washed coal.
206.460 Transportation allowances--general.
206.461 Determination of transportation allowances.
206.462 [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
[[Page 37]]
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 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.
[[Page 38]]
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 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.
[[Page 39]]
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.
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-
[[Page 40]]
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
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;
[[Page 41]]
(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 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
[[Page 42]]
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 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
[[Page 43]]
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 (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
[[Page 44]]
products which have no value). Except as provided in this paragraph, no
allowance may be taken for the costs of transporting lease production
which is not royalty-bearing without MMS approval.
(ii) Notwithstanding the requirements of paragraph (i), the lessee
may propose to MMS a cost allocation method on the basis of the values
of the products transported. MMS shall approve the method unless it
determines that it is not consistent with the purposes of the
regulations in this part.
(3) If an arm's-length transportation contract includes both gaseous
and liquid products, and the transportation costs attributable to each
product cannot be determined from the contract, the lessee shall propose
an allocation procedure to MMS. The lessee may use the oil
transportation allowance determined in accordance with its proposed
allocation procedure until MMS issues its determination on the
acceptability of the cost allocation. The lessee shall submit all
available data to support its proposal. The initial proposal must be
submitted by June 30, 1988 or within 3 months after the last day of the
month for which the lessee requests a transportation allowance,
whichever is later (unless MMS approves a longer period). MMS shall then
determine the oil transportation allowance based upon the lessee's
proposal and any additional information MMS deems necessary.
(4) Where the lessee's payments for transportation under an arm's-
length contract are not on a dollar-per-unit basis, the lessee shall
convert whatever consideration is paid to a dollar value equivalent for
the purposes of this section.
(5) Where an arm's-length sales contract price, or a posted price,
includes a provision whereby the listed price is reduced by a
transportation factor, MMS will not consider the transportation factor
to be a transportation allowance. The transportation factor may be used
in determining the lessee's gross proceeds for the sale of the product.
The transportation factor may not exceed 50 percent of the base price of
the product without MMS approval.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length transportation contract or has no contract, including those
situations where the lessee performs transportation services for itself,
the transportation allowance will be based upon the lessee's reasonable,
actual costs as provided in this paragraph. All transportation
allowances deducted under a non-arms-length or no-contract situation are
subject to monitoring, review, audit, and adjustment. Before any
estimated or actual deduction may be taken, the lessee must submit a
completed Form MMS-4110 in its entirety in accordance with paragraph
(c)(2) of this section. A transportation allowance may be claimed
retroactively for a period of not more than 3 months prior to the first
day of the month that Form MMS-4110 is filed with MMS, unless MMS
approves a longer period upon a showing of good cause by the lessee. MMS
will monitor the allowance deductions to determine whether lessees are
taking deductions that are reasonable and allowable. When necessary or
appropriate, MMS may direct a lessee to modify its actual transportation
allowance deduction.
(2) The transportation allowance for non-arms-length or no-contract
situations shall be based upon the lessee's actual costs for
transportation during the reporting period, including operating and
maintenance expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph
(b)(2)(iv)(A) of this section, or a cost equal to the initial capital
investment in the transportation system multiplied by a rate of return
in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable
capital costs are generally those for depreciable fixed assets
(including costs of delivery and installation of capital equipment)
which are an integral part of the transportation system.
(i) Allowable operating expenses include: Operations supervision and
engineering; operations labor; fuel; utilities; materials; ad valorem
property taxes; rent; supplies; and any other directly allocable and
attributable operating expense which the lessee can document.
[[Page 45]]
(ii) Allowable maintenance expenses include: Maintenance of the
transportation system; maintenance of equipment; maintenance labor; and
other directly allocable and attributable maintenance expenses which the
lessee can document.
(iii) Overhead directly attributable and allocable to the operation
and maintenance of the transportation system is an allowable expense.
State and Federal income taxes and severance taxes and other fees,
including royalties, are not allowable expenses.
(iv) A lessee may use either depreciation or a return on depreciable
capital investment. After a lessee has elected to use either method for
a transportation system, the lessee may not later elect to change to the
other alternative without approval of MMS.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the transportation system services or on
a unit-of-production method. After an election is made, the lessee may
not change methods without MMS approval. A change in ownership of a
transportation system shall not alter the depreciation schedule
established by the original transporter/lessee for purposes of the
allowance calculation. With or without a change in ownership, a
transportation system shall be depreciated only once. Equipment shall
not be depreciated below a reasonable salvage value.
(B) MMS shall allow as a cost an amount equal to the initial capital
investment in the transportation system multiplied by the rate of return
determined under paragraph (b)(2)(v) of this section. No allowance shall
be provided for depreciation. This alternative shall apply only to
transportation facilities first placed in service after March 1, 1988.
(v) The rate of return shall be the industrial rate associated with
Standard and Poor's BBB rating. The rate of return shall be the monthly
average rate as published in Standard and Poor's Bond Guide for the
first month of the reporting period for which the allowance is
applicable and shall be effective during the reporting period. The rate
shall be redetermined at the beginning of each subsequent transportation
allowance reporting period (which is determined under paragraph (c) of
this section).
(3)(i) The deduction for transportation costs shall be determined on
the basis of the lessee's cost of transporting each product through each
individual transportation system. Where more than one liquid product is
transported, allocation of costs to each of the liquid products
transported shall be in the same proportion as the ratio of the volume
of each liquid product (excluding waste products which have no value) to
the volume of all liquid products (excluding waste products which have
no value) and such allocation shall be made in a consistent and
equitable manner. Except as provided in this paragraph, the lessee may
not take an allowance for transporting lease production which is not
royalty-bearing without MMS approval.
(ii) Notwithstanding the requirements of paragraph (i), the lessee
may propose to MMS a cost allocation method on the basis of the values
of the products transported. MMS shall approve the method unless it
determines that it is not consistent with the purposes of the
regulations in this part.
(4) Where both gaseous and liquid products are transported through
the same transportation system, the lessee shall propose a cost
allocation procedure to MMS. The lessee may use the oil transportation
allowance determined in accordance with its proposed allocation
procedure until MMS issues its determination on the acceptability of the
cost allocation. The lessee shall submit all available data to support
its proposal. The initial proposal must be submitted by June 30, 1988 or
within 3 months after the last day of the month for which the lessee
requests a transportation allowance, whichever is later (unless MMS
approves a longer period). MMS shall then determine the oil
transportation allowance on the basis of the lessee's proposal and any
additional information MMS deems necessary.
(5) A lessee may apply to MMS for an exception from the requirement
that it compute actual costs in accordance with paragraphs (b)(1)
through (b)(4) of
[[Page 46]]
this section. MMS will grant the exception only if the lessee has a
tariff for the transportation system approved by the Federal Energy
Regulatory Commission (FERC) for Indian leases. MMS shall deny the
exception request if it determines that the tariff is excessive as
compared to arm's-length transportation charges by pipelines, owned by
the lessee or others, providing similar transportation services in that
area. If there are no arm's-length transportation charges, MMS shall
deny the exception request if:
(i) No FERC cost analysis exists and the FERC has declined to
investigate under MMS timely objections upon filing; and
(ii) the tariff significantly exceeds the lessee's actual costs for
transportation as determined under this section.
(c) Reporting requirements. (1) Arm's-length contracts. (i) With the
exception of those transportation allowances specified in paragraphs
(c)(1)(v) and (c)(1)(vi) of this section, the lessee shall submit page
one of the initial Form MMS-4110 (and Schedule 1), Oil Transportation
Allowance Report, prior to, or at the same time as, the transportation
allowance determined, under an arm's-length contract, is reported on
Form MMS-2014, Report of Sales and Royalty Remittance. A Form MMS-4110
received by the end of the month that the Form MMS-2014 is due shall be
considered to be timely received.
(ii) The initial Form MMS-4110 shall be effective for a reporting
period beginning the month that the lessee is first authorized to deduct
a transportation allowance and shall continue until the end of the
calendar year, or until the applicable contract or rate terminates or is
modified or amended, whichever is earlier.
(iii) After the initial reporting period and for succeeding
reporting periods, lessees must submit page one of Form MMS-4110 (and
Schedule 1) within 3 months after the end of the calendar year, or after
the applicable contract or rate terminates or is modified or amended,
whichever is earlier, unless MMS approves a longer period (during which
period the lessee shall continue to use the allowance from the previous
reporting period).
(iv) MMS may require that a lessee submit arm's-length
transportation contracts, production agreements, operating agreements,
and related documents. Documents shall be submitted within a reasonable
time, as determined by MMS.
(v) Transportation allowances which are based on arm's-length
contracts and which are in effect at the time these regulations become
effective will be allowed to continue until such allowances terminate.
For the purposes of this section, only those allowances that have been
approved by MMS in writing shall qualify as being in effect at the time
these regulations become effective.
(vi) MMS may establish, in appropriate circumstances, reporting
requirements which are different from the requirements of this section.
(2) Non-arm's-length or no contract. (i) With the exception of those
transportation allowances specified in paragraphs (c)(2)(v), (c)(2)(vii)
and (c)(2)(viii) of this section, the lessee shall submit an initial
Form MMS-4110 prior to, or at the same time as, the transportation
allowance determined under a non-arm's-length contract or no-contract
situation is reported on Form MMS-2014. A Form MMS-4110 received by the
end of the month that the Form MMS-2014 is due shall be considered to be
timely received. The initial report may be based upon estimated costs.
(ii) The initial Form MMS-4110 shall be effective for a reporting
period beginning the month that the lessee first is authorized to deduct
a transportation allowance and shall continue until the end of the
calendar year, or until transportation under the non-arm's-length
contract or the no-contract situation terminates, whichever is earlier.
(iii) For calendar-year reporting periods succeeding the initial
reporting period, the lessee shall submit a completed Form MMS-4110
containing the actual costs for the previous reporting period. If oil
transportation is continuing, the lessee shall include on Form MMS-4110
its estimated costs for the next calendar year. The estimated
[[Page 47]]
oil transportation allowance shall be based on the actual costs for the
previous reporting period plus or minus any adjustments which are based
on the lessee's knowledge of decreases or increases that will affect the
allowance. MMS must receive the Form MMS-4110 within 3 months after the
end of the previous reporting period, unless MMS approves a longer
period (during which period the lessee shall continue to use the
allowance from the previous reporting period).
(iv) For new transportation facilities or arrangements, the lessee's
initial Form MMS-4110 shall include estimates of the allowable oil
transportation costs for the applicable period. Cost estimates shall be
based upon the most recently available operations data for the
transportation system or, if such data are not available, the lessee
shall use estimates based upon industry data for similar transportation
systems.
(v) Non-arm's-length contract or no-contract transportation
allowances which are in effect at the time these regulations become
effective will be allowed to continue until such allowances terminate.
For the purposes of this section, only those allowances that have been
approved by MMS in writing shall qualify as being in effect at the time
these regulations become effective.
(vi) Upon request by MMS, the lessee shall submit all data used to
prepare its Form MMS-4110. The data shall be provided within a
reasonable period of time, as determined by MMS.
(vii) MMS may establish, in appropriate circumstances, reporting
requirements which are different from the requirements of this section.
(viii) If the lessee is authorized to use its FERC-approved tariff
as its transportation cost in accordance with paragraph (b)(5) of this
section, it shall follow the reporting requirements of paragraph (c)(1)
of this section.
(3) MMS may establish reporting dates for individual lessees
different from those specified in this subpart in order to provide more
effective administration. Lessees will be notified of any change in
their reporting period.
(4) Transportation allowances must be reported as a separate 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
[[Page 48]]
shall apply to determine transportation costs when establishing value
using a netback valuation procedure or any other procedure that requires
deduction of transportation costs.
Subpart C--Federal Oil
Source: 65 FR 14088, Mar. 15, 2000, unless otherwise noted.
Sec. 206.100 What is the purpose of this subpart?
(a) This subpart applies to all oil produced from Federal oil and
gas leases onshore and on the Outer Continental Shelf (OCS). It explains
how you as a lessee must calculate the value of production for royalty
purposes consistent with the mineral leasing laws, other applicable
laws, and lease terms.
(b) If you are a designee and if you dispose of production on behalf
of a lessee, the terms ``you'' and ``your'' in this subpart refer to you
and not to the lessee. In this circumstance, you must determine and
report royalty value for the lessee's oil by applying the rules in this
subpart to your disposition of the lessee's oil.
(c) If you are a designee and only report for a lessee, and do not
dispose of the lessee's production, references to ``you'' and ``your''
in this subpart refer to the lessee and not the designee. In this
circumstance, you as a designee must determine and report royalty value
for the lessee's oil by applying the rules in this subpart to the
lessee's disposition of its oil.
(d) If the regulations in this subpart are inconsistent with:
(1) A Federal statute;
(2) A settlement agreement between the United States and a lessee
resulting from administrative or judicial litigation;
(3) A written agreement between the lessee and the MMS Director
establishing a method to determine the value of production from any
lease that MMS expects at least would approximate the value established
under this subpart; or
(4) An express provision of an oil and gas lease subject to this
subpart, then the statute, settlement agreement, written agreement, or
lease provision will govern to the extent of the inconsistency.
(e) MMS may audit and adjust all royalty payments.
Sec. 206.101 What definitions apply to this subpart?
The following definitions apply to this subpart:
Affiliate means a person who controls, is controlled by, or is under
common control with another person. For purposes of this subpart:
(1) Ownership or common ownership of more than 50 percent of the
voting securities, or instruments of ownership, or other forms of
ownership, of another person constitutes control. Ownership of less than
10 percent constitutes a presumption of noncontrol that MMS may rebut.
(2) If there is ownership or common ownership of between 10 and 50
percent of the voting securities or instruments of ownership, or other
forms of ownership, of another person, MMS will consider the following
factors in determining whether there is control under the circumstances
of a particular case:
(i) The extent to which there are common officers or directors;
(ii) With respect to the voting securities, or instruments of
ownership, or other forms of ownership: the percentage of ownership or
common ownership, the relative percentage of ownership or common
ownership compared to the percentage(s) of ownership by other persons,
whether a person is the greatest single owner, or whether there is an
opposing voting bloc of greater ownership;
(iii) Operation of a lease, plant, or other facility;
(iv) The extent of participation by other owners in operations and
day-to-day management of a lease, plant, or other facility; and
(v) Other evidence of power to exercise control over or common
control with another person.
(3) Regardless of any percentage of ownership or common ownership,
relatives, either by blood or marriage, are affiliates.
ANS means Alaska North Slope (ANS).
Area means a geographic region at least as large as the limits of an
oil
[[Page 49]]
field, in which oil has similar quality, economic, and legal
characteristics.
Arm's-length contract means a contract or agreement between
independent persons who are not affiliates and who have opposing
economic interests regarding that contract. To be considered arm's
length for any production month, a contract must satisfy this definition
for that month, as well as when the contract was executed.
Audit means a review, conducted under generally accepted accounting
and auditing standards, of royalty payment compliance activities of
lessees, designees or other persons who pay royalties, rents, or bonuses
on Federal leases.
BLM means the Bureau of Land Management of the Department of the
Interior.
Condensate means liquid hydrocarbons (normally exceeding 40 degrees
of API gravity) recovered at the surface without processing. Condensate
is the mixture of liquid hydrocarbons resulting from condensation of
petroleum hydrocarbons existing initially in a gaseous phase in an
underground reservoir.
Contract means any oral or written agreement, including amendments
or revisions, between two or more persons, that is enforceable by law
and that with due consideration creates an obligation.
Designee means the person the lessee designates to report and pay
the lessee's royalties for a lease.
Exchange agreement means an agreement where one person agrees to
deliver oil to another person at a specified location in exchange for
oil deliveries at another location. Exchange agreements may or may not
specify prices for the oil involved. They frequently specify dollar
amounts reflecting location, quality, or other differentials. Exchange
agreements include buy/sell agreements, which specify prices to be paid
at each exchange point and may appear to be two separate sales within
the same agreement. Examples of other types of exchange agreements
include, but are not limited to, exchanges of produced oil for specific
types of crude oil (e.g., West Texas Intermediate); exchanges of
produced oil for other crude oil at other locations (Location Trades);
exchanges of produced oil for other grades of oil (Grade Trades); and
multi-party exchanges.
Field means a geographic region situated over one or more subsurface
oil and gas reservoirs and encompassing at least the outermost
boundaries of all oil and gas accumulations known within those
reservoirs, vertically projected to the land surface. State oil and gas
regulatory agencies usually name onshore fields and designate their
official boundaries. MMS names and designates boundaries of OCS fields.
Gathering means the movement of lease production to a central
accumulation or treatment point on the lease, unit, or communitized
area, or to a central accumulation or treatment point off the lease,
unit, or communitized area that BLM or MMS approves for onshore and
offshore leases, respectively.
Gross proceeds means the total monies and other consideration
accruing for the disposition of oil produced. Gross proceeds also
include, but are not limited to, the following examples:
(1) Payments for services such as dehydration, marketing,
measurement, or gathering which the lessee must perform at no cost to
the Federal Government;
(2) The value of services, such as salt water disposal, that the
producer normally performs but that the buyer performs on the producer's
behalf;
(3) Reimbursements for harboring or terminaling fees;
(4) Tax reimbursements, even though the Federal royalty interest may
be exempt from taxation;
(5) Payments made to reduce or buy down the purchase price of oil to
be produced in later periods, by allocating such payments over the
production whose price the payment reduces and including the allocated
amounts as proceeds for the production as it occurs; and
(6) Monies and all other consideration to which a seller is
contractually or legally entitled, but does not seek to collect through
reasonable efforts.
Index pricing means using ANS crude oil spot prices, West Texas
Intermediate (WTI) crude oil spot prices at
[[Page 50]]
Cushing, Oklahoma, or other appropriate crude oil spot prices for
royalty valuation.
Index pricing point means the physical location where an index price
is established in an MMS-approved publication.
Lease means any contract, profit-share arrangement, joint venture,
or other agreement issued or approved by the United States under a
mineral leasing law that authorizes exploration for, development or
extraction of, or removal of oil or gas--or the land area covered by
that authorization, whichever the context requires.
Lessee means any person to whom the United States issues an oil and
gas lease, an assignee of all or a part of the record title interest, or
any person to whom operating rights in a lease have been assigned.
Location differential means an amount paid or received (whether in
money or in barrels of oil) under an exchange agreement that results
from differences in location between oil delivered in exchange and oil
received in the exchange. A location differential may represent all or
part of the difference between the price received for oil delivered and
the price paid for oil received under a buy/sell exchange agreement.
Market center means a major point MMS recognizes for oil sales,
refining, or transshipment. Market centers generally are locations where
MMS-approved publications publish oil spot prices.
Marketable condition means oil sufficiently free from impurities and
otherwise in a condition a purchaser will accept under a sales contract
typical for the field or area.
MMS-approved publication means a publication MMS approves for
determining ANS spot prices, other spot prices, or location
differentials.
Netting means reducing the reported sales value to account for
transportation instead of reporting a transportation allowance as a
separate entry on Form MMS-2014.
Oil means a mixture of hydrocarbons that existed in the liquid phase
in natural underground reservoirs, remains liquid at atmospheric
pressure after passing through surface separating facilities, and is
marketed or used as a liquid. Condensate recovered in lease separators
or field facilities is oil.
Outer Continental Shelf (OCS) means all submerged lands lying
seaward and outside of the area of lands beneath navigable waters as
defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of
which the subsoil and seabed appertain to the United States and are
subject to its jurisdiction and control.
Person means any individual, firm, corporation, association,
partnership, consortium, or joint venture (when established as a
separate entity).
Quality differential means an amount paid or received under an
exchange agreement (whether in money or in barrels of oil) that results
from differences in API gravity, sulfur content, viscosity, metals
content, and other quality factors between oil delivered and oil
received in the exchange. A quality differential may represent all or
part of the difference between the price received for oil delivered and
the price paid for oil received under a buy/sell agreement.
Rocky Mountain Region means the States of Colorado, Montana, North
Dakota, South Dakota, Utah, and Wyoming, except for those portions of
the San Juan Basin and other oil-producing fields in the ``Four
Corners'' area that lie within Colorado and Utah.
Sale means a contract between two persons where:
(1) The seller unconditionally transfers title to the oil to the
buyer and does not retain any related rights such as the right to buy
back similar quantities of oil from the buyer elsewhere;
(2) The buyer pays money or other consideration for the oil; and
(3) The parties' intent is for a sale of the oil to occur.
Spot price means the price under a spot sales contract where:
(1) A seller agrees to sell to a buyer a specified amount of oil at
a specified price over a specified period of short duration;
(2) No cancellation notice is required to terminate the sales
agreement; and
(3) There is no obligation or implied intent to continue to sell in
subsequent periods.
[[Page 51]]
Tendering program means a producer's offer of a portion of its crude
oil produced from a field or area for competitive bidding, regardless of
whether the production is offered or sold at or near the lease or unit
or away from the lease or unit.
Trading month means the span of time during which crude oil trading
occurs and spot prices are determined, generally for deliveries of
production in the following calendar month. For example, for ANS spot
prices, the trading month includes all business days in the calendar
month. For other spot prices, for example, the trading month may include
the span of time from the 26th of the previous month through the 25th of
the current month.
Transportation allowance means a deduction in determining royalty
value for the reasonable, actual costs of moving oil to a point of sale
or delivery off the lease, unit area, or communitized area. The
transportation allowance does not include gathering costs.
Sec. 206.102 How do I calculate royalty value for oil that I or my
affiliate sell(s) under an arm's-length contract?
(a) The value of oil under this section is the gross proceeds
accruing to the seller under the arm's-length contract, less applicable
allowances determined under Secs. 206.110 or 206.111. This value does
not apply if you exercise an option to use a different value provided in
paragraph (d)(1) or (d)(2)(i) of this section, or if one of the
exceptions in paragraph (c) of this section applies. Use this paragraph
(a) to value oil that:
(1) You sell under an arm's-length sales contract; or
(2) You sell or transfer to your affiliate or another person under a
non-arm's-length contract and that affiliate or person, or another
affiliate of either of them, then sells the oil under an arm's-length
contract, unless you exercise the option provided in paragraph (d)(2)(i)
of this section.
(b) If you have multiple arm's-length contracts to sell oil produced
from a lease that is valued under paragraph (a) of this section, the
value of the oil is the volume-weighted average of the values
established under this section for each contract for the sale of oil
produced from that lease.
(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
[[Page 52]]
exchange agreement(s). If MMS determines that any arm's-length exchange
agreement does not reflect reasonable location or quality differentials,
MMS may require you to value the oil under Sec. 206.103. You may not
otherwise use the price or differential specified in an arm's-length
exchange agreement to value your production.
(ii) When you elect under Sec. 206.102(d)(1) to use Sec. 206.102(a)
or Sec. 206.103, you must make the same election for all of your
production from the same unit, communitization agreement, or lease (if
the lease is not part of a unit or communitization agreement) sold under
arm's-length contracts following arm's-length exchange agreements. You
may not change your election more often than once every 2 years.
(2)(i) If you sell or transfer your oil production to your affiliate
and that affiliate or another affiliate then sells the oil under an
arm's-length contract, you may use either Sec. 206.102(a) or
Sec. 206.103 to value your production for royalty purposes.
(ii) When you elect under Sec. 206.102(d)(2)(i) to use
Sec. 206.102(a) or Sec. 206.103, you must make the same election for all
of your production from the same unit, communitization agreement, or
lease (if the lease is not part of a unit or communitization agreement)
that your affiliates resell at arm's length. You may not change your
election more often than once every 2 years.
(e) If you value oil under paragraph (a) of this section:
(1) MMS may require you to certify that your or your affiliate's
arm's-length contract provisions include all of the consideration the
buyer must pay, either directly or indirectly, for the oil.
(2) You must base value on the highest price the seller can receive
through legally enforceable claims under the contract.
(i) If the seller fails to take proper or timely action to receive
prices or benefits it is entitled to, you must pay royalty at a value
based upon that obtainable price or benefit. But you will owe no
additional royalties unless or until the seller receives monies or
consideration resulting from the price increase or additional benefits,
if:
(A) The seller makes timely application for a price increase or
benefit allowed under the contract;
(B) The purchaser refuses to comply; and
(C) The seller takes reasonable documented measures to force
purchaser compliance.
(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
[[Page 53]]
once every 2 years, unless the publication you use is no longer
published or MMS revokes its approval of the publication. If you are
required to change publications, you must begin a new 2-year period.
(b) Production from leases in the Rocky Mountain Region. This
paragraph provides methods and options for valuing your production under
different factual situations.
(1) If you have an MMS-approved tendering program, value your oil
under paragraph (b)(2) of this section. If you do not have an MMS-
approved tendering program, you may value your oil under either
paragraph (b)(3) or paragraph (b)(4) of this section.
(i) You must apply the same subparagraph of this section to value
all of your production from the same unit, communitization agreement, or
lease (if the lease is not part of a unit or communitization agreement)
that you cannot value under Sec. 206.102 or that you elect under
Sec. 206.102(d) to value under this section.
(ii) After you select either paragraph (b)(3) or (b)(4) of this
section, you may not change to the other method more often than once
every 2 years, unless the method you have been using is no longer
applicable and you must apply one of the other paragraphs. If you change
methods, you must begin a new 2-year period.
(2) If you have an MMS-approved tendering program, the value of
production from leases in the area the tendering program covers is the
highest winning bid price for tendered volumes.
(i) You must offer and sell at least 30 percent of your production
from both Federal and non-Federal leases in that area under your
tendering program.
(ii) You also must receive at least three bids for the tendered
volumes from bidders who do not have their own tendering programs that
cover some or all of the same area.
(iii) MMS will provide additional criteria for approval of a
tendering program in its revenue reporter handbook.
(3) Value is the volume-weighted average gross proceeds accruing to
the seller under your and your affiliates' arm's-length contracts for
the purchase or sale of production from the field or area during the
production month. The total volume purchased or sold under those
contracts must exceed 50 percent of your and your affiliates' production
from both Federal and non-Federal leases in the same field or area
during that month. Before calculating the volume-weighted average, you
must normalize the quality of the oil in your or your affiliates' arms-
length purchases or sales to the same gravity as that of the oil
produced from the lease.
(4) Value is the average of the daily mean spot prices published in
any MMS-approved publication for WTI crude at Cushing, Oklahoma, during
the trading month most concurrent with the production month. (For
example, if the production month is June and the trading month is May
26--June 25, compute the average of the daily mean prices using the
daily Cushing spot prices published in the MMS-approved publication for
all the business days between and including May 26 and June 25.)
(i) Calculate the daily mean spot price by averaging the daily high
and low prices for the period in the selected publication.
(ii) Use only the days and corresponding spot prices for which such
prices are published.
(iii) You must adjust the value for applicable location and quality
differentials, and you may adjust it for transportation costs, under
Sec. 206.112.
(iv) After you select an MMS-approved publication, you may not
select a different publication more often than once every 2 years,
unless the publication you use is no longer published or MMS revokes its
approval of the publication. If you are required to change publications,
you must begin a new 2-year period.
(5) If you demonstrate to MMS's satisfaction that paragraphs (b)(2)
through (b)(4) of this section result in an unreasonable value for your
production as a result of circumstances regarding that production, the
MMS Director may establish an alternative valuation method.
(c) Production from leases not located in California, Alaska, or the
Rocky
[[Page 54]]
Mountain Region. (1) Value is the average of the daily mean spot prices
published in any MMS-approved publication:
(i) For the market center nearest your lease for crude oil similar
in quality to that of your production (for example, at the St. James,
Louisiana, market center, spot prices are published for both Light
Louisiana Sweet and Eugene Island crude oils--their quality
specifications differ significantly); and
(ii) During the trading month most concurrent with the production
month. (For example, if the production month is June and the trading
month is May 26-June 25, compute the average of the daily mean prices
using the daily spot prices published in the MMS-approved publication
for all the business days between and including May 26 and June 25 for
the applicable market center.)
(2) Calculate the daily mean spot price by averaging the daily high
and low prices for the period in the selected publication. Use only the
days and corresponding spot prices for which such prices are published.
You must adjust the value for applicable location and quality
differentials, and you may adjust it for transportation costs, under
Sec. 206.112.
(3) After you select an MMS-approved publication, you may not select
a different publication more often than once every 2 years, unless the
publication you use is no longer published or MMS revokes its approval
of the publication. If you are required to change publications, you must
begin a new 2-year period.
(d) Unavailable or unreasonable index prices. If MMS determines that
any of the index prices referenced in paragraphs (a), (b), and (c) of
this section are unavailable or no longer represent reasonable royalty
value, in any particular case, MMS may establish reasonable royalty
value based on other relevant matters.
(e) Production delivered to your refinery and index price is
unreasonable.(1) Instead of valuing your production under paragraph (a),
(b), or (c) of this section, you may apply to the MMS Director to
establish a value representing the market at the refinery if:
(i) You transport your oil directly to your or your affiliate's
refinery, or exchange your oil for oil delivered to your or your
affiliate's refinery; and
(ii) You must value your oil under this section at an index price;
and
(iii) You believe that use of the index price is unreasonable.
(2) You must provide adequate documentation and evidence
demonstrating the market value at the refinery. That evidence may
include, but is not limited to:
(i) Costs of acquiring other crude oil at or for the refinery;
(ii) How adjustments for quality, location, and transportation were
factored into the price paid for other oil;
(iii) Volumes acquired for and refined at the refinery; and
(iv) Any other appropriate evidence or documentation that MMS
requires.
(3) If the MMS Director establishes a value representing market
value at the refinery, you may not take an allowance against that value
under Sec. 206.112(b) unless it is included in the Director's approval.
[65 FR 14088, Mar. 15, 2002, as amended at 67 FR 19111, Apr. 18, 2002]
Sec. 206.104 What index price publications are acceptable to MMS?
(a) MMS periodically will publish in the Federal Register a list of
acceptable index price publications based on certain criteria, including
but not limited to:
(1) Publications buyers and sellers frequently use;
(2) Publications frequently mentioned in purchase or sales
contracts;
(3) Publications that use adequate survey techniques, including
development of spot price estimates based on daily surveys of buyers and
sellers of ANS and other crude oil; and (4) Publications independent
from MMS, other lessors, and lessees.
(b) Any publication may petition MMS to be added to the list of
acceptable publications.
(c) MMS will reference the tables you must use in the publications
to determine the associated index prices.
(d) MMS may revoke its approval of a particular publication if it
determines
[[Page 55]]
that the prices published in the publication do not accurately represent
spot market values.
Sec. 206.105 What records must I keep to support my calculations of value
under this subpart?
If you determine the value of your oil under this subpart, you must
retain all data relevant to the determination of royalty value.
(a) You must be able to show:
(1) How you calculated the value you reported, including all
adjustments for location, quality, and transportation, and
(2) How you complied with these rules.
(b) Recordkeeping requirements are found at part 207 of this
chapter.
(c) MMS may review and audit your data, and MMS will direct you to
use a different value if it determines that the reported value is
inconsistent with the requirements of this subpart.
Sec. 206.106 What are my responsibilities to place production into
marketable condition and to market production?
You must place oil in marketable condition and market the oil for
the mutual benefit of the lessee and the lessor at no cost to the
Federal Government. If you use gross proceeds under an arm's-length
contract in determining value, you must increase those gross proceeds to
the extent that the purchaser, or any other person, provides certain
services that the seller normally would be responsible to perform to
place the oil in marketable condition or to market the oil.
Sec. 206.107 How do I request a value determination?
(a) You may request a value determination from MMS regarding any
Federal lease oil production. Your request must:
(1) Be in writing;
(2) Identify specifically all leases involved, the record title or
operating rights owners of those leases, and the designees for those
leases;
(3) Completely explain all relevant facts. You must inform MMS of
any changes to relevant facts that occur before we respond to your
request;
(4) Include copies of all relevant documents;
(5) Provide your analysis of the issue(s), including citations to
all relevant precedents (including adverse precedents); and
(6) Suggest your proposed valuation method.
(b) MMS will reply to requests expeditiously. MMS may either:
(1) Issue a value determination signed by the Assistant Secretary,
Land and Minerals Management; or
(2) Issue a value determination by MMS; or
(3) Inform you in writing that MMS will not provide a value
determination. Situations in which MMS typically will not provide any
value determination include, but are not limited to:
(i) Requests for guidance on hypothetical situations; and
(ii) Matters that are the subject of pending litigation or
administrative appeals.
(c)(1) A value determination signed by the Assistant Secretary, Land
and Minerals Management, is binding on both you and MMS until the
Assistant Secretary modifies or rescinds it.
(2) After the Assistant Secretary issues a value determination, you
must make any adjustments in royalty payments that follow from the
determination and, if you owe additional royalties, pay late payment
interest under 30 CFR 218.54.
(3) A value determination signed by the Assistant Secretary is the
final action of the Department and is subject to judicial review under 5
U.S.C. 701-706.
(d) A value determination issued by MMS is binding on MMS and
delegated States with respect to the specific situation addressed in the
determination unless the MMS (for MMS-issued value determinations) or
the Assistant Secretary modifies or rescinds it.
(1) A value determination by MMS is not an appealable decision or
order under 30 CFR part 290 subpart B.
(2) If you receive an order requiring you to pay royalty on the same
basis as the value determination, you may appeal that order under 30 CFR
part 290 subpart B.
(e) In making a value determination, MMS or the Assistant Secretary
may
[[Page 56]]
use any of the applicable valuation criteria in this subpart.
(f) A change in an applicable statute or regulation on which any
value determination is based takes precedence over the value
determination, regardless of whether the MMS or the Assistant Secretary
modifies or rescinds the value determination.
(g) The MMS or the Assistant Secretary generally will not
retroactively modify or rescind a value determination issued under
paragraph (d) of this section, unless:
(1) There was a misstatement or omission of material facts; or
(2) The facts subsequently developed are materially different from
the facts on which the guidance was based.
(h) MMS may make requests and replies under this section available
to the public, subject to the confidentiality requirements under
Sec. 206.108.
Sec. 206.108 Does MMS protect information I provide?
Certain information you submit to MMS regarding valuation of oil,
including transportation allowances, may be exempt from disclosure. To
the extent applicable laws and regulations permit, MMS will keep
confidential any data you submit that is privileged, confidential, or
otherwise exempt from disclosure. All requests for information must be
submitted under the Freedom of Information Act regulations of the
Department of the Interior at 43 CFR part 2.
Sec. 206.109 When may I take a transportation allowance in determining
value?
(a) Transportation allowances permitted when value is based on gross
proceeds. MMS will allow a deduction for the reasonable, actual costs to
transport oil from the lease to the point off the lease under
Secs. 206.110 or 206.111, as applicable. This paragraph applies when:
(1) You value oil under Sec. 206.102 based on gross proceeds from a
sale at a point off the lease, unit, or communitized area where the oil
is produced, and
(2) The movement to the sales point is not gathering.
(b) Transportation allowances and other adjustments that apply when
value is based on index pricing. If you value oil using an index price
under Sec. 206.103, MMS will allow a deduction for certain location/
quality adjustments and certain costs associated with transporting oil
as provided under Sec. 206.112.
(c) Limits on transportation allowances. (1) Except as provided in
paragraph (c)(2) of this section, your transportation allowance may not
exceed 50 percent of the value of the oil as determined under
Sec. 206.102 or Sec. 206.103 of this subpart. You may not use
transportation costs incurred to move a particular volume of production
to reduce royalties owed on production for which those costs were not
incurred.
(2) You may ask MMS to approve a transportation allowance in excess
of the limitation in paragraph (c)(1) of this section. You must
demonstrate that the transportation costs incurred were reasonable,
actual, and necessary. Your application for exception (using Form MMS-
4393, Request to Exceed Regulatory Allowance Limitation) must contain
all relevant and supporting documentation necessary for MMS to make a
determination. You may never reduce the royalty value of any production
to zero.
(d) Allocation of transportation costs. You must allocate
transportation costs among all products produced and transported as
provided in Secs. 206.110 and 206.111. You must express transportation
allowances for oil as dollars per barrel.
(e) Liability for additional payments. If MMS determines that you
took an excessive transportation allowance, then you must pay any
additional royalties due, plus interest under 30 CFR 218.54. You also
could be entitled to a credit with interest under applicable rules if
you understated your transportation allowance. If you take a deduction
for transportation on Form MMS-2014 by improperly netting the allowance
against the sales value of the oil instead of reporting the allowance as
a separate entry, MMS may assess you an amount under Sec. 206.116.
Sec. 206.110 How do I determine a transportation allowance under an
arm's-length transportation contract?
(a) If you or your affiliate incur transportation costs under an
arm's-
[[Page 57]]
length transportation contract, you may claim a transportation allowance
for the reasonable, actual costs incurred for transporting oil under
that contract, except as provided in paragraphs (a)(1) and (a)(2) of
this section and subject to the limitation in Sec. 206.109(c). You must
be able to demonstrate that your contract is arm's length. You do not
need MMS approval before reporting a transportation allowance for costs
incurred under an arm's-length transportation contract.
(1) If MMS determines that the contract reflects more than the
consideration actually transferred either directly or indirectly from
you or your affiliate to the transporter for the transportation, MMS may
require that you calculate the transportation allowance under
Sec. 206.111.
(2) You must calculate the transportation allowance under
Sec. 206.111 if MMS determines that the consideration paid under an
arm's-length transportation contract does not reflect the reasonable
value of the transportation due to either:
(i) Misconduct by or between the parties to the arm's-length
contract; or
(ii) Breach of your duty to market the oil for the mutual benefit of
yourself and the lessor.
(A) MMS will not use this provision to simply substitute its
judgment of the reasonable oil transportation costs incurred by you or
your affiliate under an arm's-length transportation contract.
(B) The fact that the cost you or your affiliate incur in an arm's
length transaction is higher than other measures of transportation
costs, such as rates paid by others in the field or area, is
insufficient to establish breach of the duty to market unless MMS finds
additional evidence that you or your affiliate acted unreasonably or in
bad faith in transporting oil from the lease.
(b) If your arm's-length transportation contract includes more than
one liquid product, and the transportation costs attributable to each
product cannot be determined from the contract, then you must allocate
the total transportation costs to each of the liquid products
transported.
(1) Your allocation must use the same proportion as the ratio of the
volume of each product (excluding waste products with no value) to the
volume of all liquid products (excluding waste products with no value).
(2) You may not claim an allowance for the costs of transporting
lease production that is not royalty-bearing.
(3) You may propose to MMS a cost allocation method on the basis of
the values of the products transported. MMS will approve the method
unless it is not consistent with the purposes of the regulations in this
subpart.
(c) If your arm's-length transportation contract includes both
gaseous and liquid products, and the transportation costs attributable
to each product cannot be determined from the contract, then you must
propose an allocation procedure to MMS.
(1) You may use your proposed procedure to calculate a
transportation allowance until MMS accepts or rejects your cost
allocation. If MMS rejects your cost allocation, you must amend your
Form MMS-2014 for the months that you used the rejected method and pay
any additional royalty and interest due.
(2) You must submit your initial proposal, including all available
data, within 3 months after first claiming the allocated deductions on
Form MMS-2014.
(d) If your payments for transportation under an arm's-length
contract are not on a dollar-per-unit basis, you must convert whatever
consideration is paid to a dollar-value equivalent.
(e) If your arm's-length sales contract includes a provision
reducing the contract price by a transportation factor, do not
separately report the transportation factor as a transportation
allowance on Form MMS-2014.
(1) You may use the transportation factor in determining your gross
proceeds for the sale of the product.
(2) You must obtain MMS approval before claiming a transportation
factor in excess of 50 percent of the base price of the product.
[[Page 58]]
Sec. 206.111 How do I determine a transportation allowance under a
non-arm's-length transportation arrangement?
(a) If you or your affiliate have a non-arm's-length transportation
contract or no contract, including those situations where you or your
affiliate perform your own transportation services, calculate your
transportation allowance based on your or your affiliate's reasonable,
actual transportation costs using the procedures provided in this
section.
(b) Base your transportation allowance for non-arm's-length or no-
contract situations on your or your affiliate's actual costs for
transportation during the reporting period, including:
(1) Operating and maintenance expenses under paragraphs (d) and (e)
of this section;
(2) Overhead under paragraph (f) of this section;
(3) Depreciation under paragraphs (g) and (h) of this section;
(4) A return on undepreciated capital investment under paragraph (i)
of this section; and
(5) Once the transportation system has been depreciated below ten
percent of total capital investment, a return on ten percent of total
capital investment under paragraph (j) of this section.
(c) Allowable capital costs are generally those for depreciable
fixed assets (including costs of delivery and installation of capital
equipment) which are an integral part of the transportation system.
(d) Allowable operating expenses include:
(i) Operations supervision and engineering;
(ii) Operations labor;
(iii) Fuel;
(iv) Utilities;
(v) Materials;
(vi) Ad valorem property taxes;
(vii) Rent;
(viii) Supplies; and
(ix) Any other directly allocable and attributable operating expense
which you can document.
(e) Allowable maintenance expenses include:
(i) Maintenance of the transportation system;
(ii) Maintenance of equipment;
(iii) Maintenance labor; and
(iv) Other directly allocable and attributable maintenance expenses
which you can document.
(f) Overhead directly attributable and allocable to the operation
and maintenance of the transportation system is 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.
[[Page 59]]
(4) If you or your affiliate purchase a transportation system at
arm's length from the original owner after June 1, 2000, you must base
your depreciation schedule used in calculating actual transportation
costs on your total capital investment in the system (including your
original purchase price and subsequent reinvestment). You must prorate
your depreciation for the year in which you or your affiliate purchased
the system to reflect the portion of that year for which you or your
affiliate own the system.
(5) If you or your affiliate purchase a transportation system at
arm's length after June 1, 2000, from anyone other than the original
owner, you must assume the depreciation schedule of the person who owned
the system on June 1, 2000.
(i)(1) To calculate a return on undepreciated capital investment,
multiply the remaining undepreciated capital balance as of the beginning
of the period for which you are calculating the transportation allowance
by the rate of return provided in paragraph (i)(2) of this section.
(2) The rate of return is the industrial bond yield index for
Standard and Poor's BBB rating. Use the monthly average rate published
in ``Standard and Poor's Bond Guide'' for the first month of the
reporting period for which the allowance applies. Calculate the rate at
the beginning of each subsequent transportation allowance reporting
period.
(j)(1) After a transportation system has been depreciated at or
below a value equal to ten percent of your total capital investment, you
may continue to include in the allowance calculation a cost equal to ten
percent of your total capital investment in the transportation system
multiplied by a rate of return under paragraph (i)(2) of this section.
(2) You may apply this paragraph to a transportation system that
before June 1, 2000, was depreciated at or below a value equal to ten
percent of your total capital investment.
(k) Calculate the deduction for transportation costs based on your
or your affiliate's cost of transporting each product through each
individual transportation system. Where more than one liquid product is
transported, allocate costs consistently and equitably to each of the
liquid products transported. Your allocation must use the same
proportion as the ratio of the volume of each liquid product (excluding
waste products with no value) to the volume of all liquid products
(excluding waste products with no value).
(1) You may not take an allowance for transporting lease production
that is not royalty-bearing.
(2) You may propose to MMS a cost allocation method on the basis of
the values of the products transported. MMS will approve the method if
it is consistent with the purposes of the regulations in this subpart.
(l)(1) Where you transport both gaseous and liquid products through
the same transportation system, you must propose a cost allocation
procedure to MMS.
(2) You may use your proposed procedure to calculate a
transportation allowance until MMS accepts or rejects your cost
allocation. If MMS rejects your cost allocation, you must amend your
Form MMS-2014 for the months that you used the rejected method and pay
any additional royalty and interest due.
(3) You must submit your initial proposal, including all available
data, within 3 months after first claiming the allocated deductions on
Form MMS-2014.
Sec. 206.112 What adjustments and transportation allowances apply when
I value oil using index pricing?
When you use index pricing to calculate the value of production
under Sec. 206.103, you must adjust the index price for location and
quality differentials and you may adjust it for certain transportation
costs, as specified in this section.
(a) If you dispose of your production under one or more arm's-length
exchange agreements, then each of the conditions in this paragraph
applies.
(1) You must adjust the index price for location/quality
differentials. You must determine those differentials from each of your
arm's-length exchange agreements applicable to the exchanged oil.
[[Page 60]]
(i) Therefore, for example, if you exchange 100 barrels of
production from a given lease under two separate arm's-length exchange
agreements for 60 barrels and 40 barrels respectively, separately
determine the location/quality differential under each of those exchange
agreements, and apply each differential to the corresponding index
price.
(ii) As another example, if you produce 100 barrels and exchange
that 100 barrels three successive times under arm's-length agreements to
obtain oil at a final destination, total the three adjustments from
those exchanges to determine the adjustment under this subparagraph. (If
one of the three exchanges was not at arm's length, you must request MMS
approval under paragraph (b) of this section for the location/quality
adjustment for that exchange to determine the total location/quality
adjustment for the three exchanges.) You also could have a combination
of these examples.
(2) You may adjust the index price for actual transportation costs,
determined under Sec. 206.110 or Sec. 206.111:
(i) From the lease to the first point where you give your oil in
exchange; and
(ii) From any intermediate point where you receive oil in exchange
to another intermediate point where you give the oil in exchange again;
and
(iii) From the point where you receive oil in exchange and transport
it without further exchange to a market center, or to a refinery that is
not at a market center.
(b) For non-arm's-length exchange agreements, you must request
approval from MMS for any location/quality adjustment.
(c) If you transport lease production directly to a market center or
to an alternate disposal point (for example, your refinery), you may
adjust the index price for your actual transportation costs, determined
under Sec. 206.110 or Sec. 206.111.
(d) If you adjust for location/quality or transportation costs under
paragraphs (a), (b), or (c) of this section, also adjust the index price
for quality based on premia or penalties determined by pipeline quality
bank specifications at intermediate commingling points or at the market
center. Make this adjustment only if and to the extent that such
adjustments were not already included in the location/quality
differentials determined from your arm's-length exchange agreements.
(e) For leases in the Rocky Mountain Region, for purposes of this
section, the term ``market center'' means Cushing, Oklahoma, unless MMS
specifies otherwise through notice published in the Federal Register.
(f) If you cannot determine your location/quality adjustment under
paragraph (a) or (c) of this section, you must request approval from MMS
for any location/quality adjustment.
(g) You may not use any transportation or quality adjustment that
duplicates all or part of any other adjustment that you use under this
section.
Sec. 206.113 How will MMS identify market centers?
MMS periodically will publish in the Federal Register a list of
market centers. MMS will monitor market activity and, if necessary, add
to or modify the list of market centers and will publish such
modifications in the Federal Register. MMS will consider the following
factors and conditions in specifying market centers:
(a) Points where MMS-approved publications publish prices useful for
index purposes;
(b) Markets served;
(c) Input from industry and others knowledgeable in crude oil
marketing and transportation;
(d) Simplification; and
(e) Other relevant matters.
Sec. 206.114 What are my reporting requirements under an arm's-length
transportation contract?
You or your affiliate must use a separate entry on Form MMS-2014 to
notify MMS of an allowance based on transportation costs you or your
affiliate incur. MMS may require you or your affiliate to submit arm's-
length transportation contracts, production agreements, operating
agreements, and related documents. Recordkeeping requirements are found
at part 207 of this chapter.
[[Page 61]]
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. 206.118 Are actual or theoretical losses permitted as part of a
transportation allowance?
You are allowed a deduction for oil transportation which results
from payments that you make (either volumetric or for value) for actual
or theoretical losses only under an arm's-length contract. You may not
take such a deduction under a non-arm's-length contract.
Sec. 206.119 How are royalty quantity and quality determined?
(a) Compute royalties based on the quantity and quality of oil as
measured at the point of settlement approved by BLM for onshore leases
or MMS for offshore leases.
(b) If the value of oil determined under this subpart is based upon
a quantity or quality different from the quantity or quality at the
point of royalty settlement approved by the BLM for onshore leases or
MMS for offshore leases, adjust the value for those differences in
quantity or quality.
(c) You may not claim a deduction from the royalty volume or royalty
value for actual or theoretical losses except as provided in
Sec. 206.118. Any actual loss that you may incur before the royalty
settlement metering or measurement point is not subject to royalty if
BLM or MMS, as appropriate, determines that the loss is unavoidable.
(d) Except as provided in paragraph (b) of this section, royalties
are due on 100 percent of the volume measured at the approved point of
royalty settlement. You may not claim a reduction in that measured
volume for actual losses beyond the approved point of royalty settlement
or for theoretical
[[Page 62]]
losses that are claimed to have taken place either before or after the
approved point of royalty settlement.
Sec. 206.120 How are operating allowances determined?
MMS may use an operating allowance for the purpose of computing
payment obligations when specified in the notice of sale and the lease.
MMS will specify the allowance amount or formula in the notice of sale
and in the lease agreement.
Sec. 206.121 Is there any grace period for reporting and paying royalties
after this subpart becomes effective?
You may adjust royalties reported and paid for the three production
months beginning June 1, 2000, without liability for late payment
interest. This section applies only if the adjustment results from
systems changes needed to comply with new requirements imposed under
this subpart that were not requirements under the predecessor rule.
Subpart D--Federal Gas
Source: 53 FR 1272, Jan. 15, 1988, unless otherwise noted.
Sec. 206.150 Purpose and scope.
(a) This subpart is applicable to all gas production from Federal
oil and gas leases. The purpose of this subpart is to establish the
value of production for royalty purposes consistent with the mineral
leasing laws, other applicable laws and lease terms.
(b) If the specific provisions of any statute or settlement
agreement between the United States and a lessee resulting from
administrative or judicial litigation, or oil and gas lease subject to
the requirements of this subpart are inconsistent with any regulation in
this subpart, then the lease, statute, or settlement agreement shall
govern to the extent of that inconsistency.
(c) All royalty payments made to MMS are subject to audit and
adjustment.
(d) The regulations in this subpart are intended to ensure that the
administration of oil and gas leases is discharged in accordance with
the requirements of the governing mineral leasing laws and lease terms.
[61 FR 5464, Feb. 12, 1996]
Sec. 206.151 Definitions.
For purposes of this subpart:
Allowance means a deduction in determining value for royalty
purposes. Processing allowance means an allowance for the reasonable
costs for processing gas determined under this subpart. Transportation
allowance means an allowance for the cost of moving royalty bearing
substances (identifiable, measurable oil and gas, including gas that is
not in need of initial separation) from the point at which it is first
identifiable and measurable to the sales point or other point where
value is established under this subpart.
Area means a geographic region at least as large as the defined
limits of an oil and/or gas field, in which oil and/or gas lease
products have similar quality, economic, and legal characteristics.
Arm's-length contract means a contract or agreement that has been
arrived at in the marketplace between independent, nonaffiliated persons
with opposing economic interests regarding that contract. For purposes
of this subpart, two persons are affiliated if one person controls, is
controlled by, or is under common control with another person. For
purposes of this subpart, based on the instruments of ownership of the
voting securities of an entity, or based on other forms of ownership:
(a) Ownership in excess of 50 percent constitutes control;
(b) Ownership of 10 through 50 percent creates a presumption of
control; and
(c) Ownership of less than 10 percent creates a presumption of
noncontrol which MMS may rebut if it demonstrates actual or legal
control, including the existence of interlocking directorates.
Notwithstanding any other provisions of this subpart, contracts between
relatives, either by blood or by marriage, are not arm's-length
contracts. The MMS may require the lessee to certify ownership control.
To be considered arm's-length for any production
[[Page 63]]
month, a contract must meet the requirements of this definition for that
production month as well as when the contract was executed.
Audit means a review, conducted in accordance with generally
accepted accounting and auditing standards, of royalty payment
compliance activities of lessees or other interest holders who pay
royalties, rents, or bonuses on Federal leases.
BLM means the Bureau of Land Management of the Department of the
Interior.
Compression means the process of raising the pressure of gas.
Condensate means liquid hydrocarbons (normally exceeding 40 degrees
of API gravity) recovered at the surface without resorting to
processing. Condensate is the mixture of liquid hydrocarbons that
results from condensation of petroleum hydrocarbons existing initially
in a gaseous phase in an underground reservoir.
Contract means any oral or written agreement, including amendments
or revisions thereto, between two or more persons and enforceable by law
that with due consideration creates an obligation.
Field means a geographic region situated over one or more subsurface
oil and gas reservoirs encompassing at least the outermost boundaries of
all oil and gas accumulations known to be within those reservoirs
vertically projected to the land surface. Onshore fields are usually
given names and their official boundaries are often designated by oil
and gas regulatory agencies in the respective States in which the fields
are located. Outer Continental Shelf (OCS) fields are named and their
boundaries are designated by MMS.
Gas means any fluid, either combustible or noncombustible,
hydrocarbon or nonhydrocarbon, which is extracted from a reservoir and
which has neither independent shape nor volume, but tends to expand
indefinitely. It is a substance that exists in a gaseous or rarefied
state under standard temperature and pressure conditions.
Gas plant products means separate marketable elements, compounds, or
mixtures, whether in liquid, gaseous, or solid form, resulting from
processing gas, excluding residue gas.
Gathering means the movement of lease production to a central
accumulation and/or treatment point on the lease, unit or communitized
area, or to a central accumulation or treatment point off the lease,
unit or communitized area as approved by BLM or MMS OCS operations
personnel for onshore and OCS leases, respectively.
Gross proceeds (for royalty payment purposes) means the total monies
and other consideration accruing to an oil and gas lessee for the
disposition of the gas, residue gas, and gas plant products produced.
Gross proceeds includes, but is not limited to, payments to the lessee
for certain services such as dehydration, measurement, and/or gathering
to the extent that the lessee is obligated to perform them at no cost to
the Federal Government. Tax reimbursements are part of the gross
proceeds accruing to a lessee even though the Federal royalty interest
may be exempt from taxation. Monies and other consideration, including
the forms of consideration identified in this paragraph, to which a
lessee is contractually or legally entitled but which it does not seek
to collect through reasonable efforts are also part of gross proceeds.
Lease means any contract, profit-share arrangement, joint venture,
or other agreement issued or approved by the United States under a
mineral leasing law that authorizes exploration for, development or
extraction of, or removal of lease products--or the land area covered by
that authorization, whichever is required by the context.
Lease products means any leased minerals attributable to,
originating from, or allocated to Outer Continental Shelf or onshore
Federal leases.
Lessee means any person to whom the United States issues a lease,
and any person who has been assigned an obligation to make royalty or
other payments required by the lease. This includes any person who has
an interest in a lease as well as an operator or payor who has no
interest in the lease but who has assumed the royalty payment
responsibility.
[[Page 64]]
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.
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
[[Page 65]]
or sources outside of the designated fields.
[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45084, Nov. 8, 1988; 61
FR 5464, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999]
Sec. 206.152 Valuation standards--unprocessed gas.
(a)(1) This section applies to the valuation of all gas that is not
processed and all gas that is processed but is sold or otherwise
disposed of by the lessee pursuant to an arm's-length contract prior to
processing (including all gas where the lessee's arm's-length contract
for the sale of that gas prior to processing provides for the value to
be determined on the basis of a percentage of the purchaser's proceeds
resulting from processing the gas). This section also applies to
processed gas that must be valued prior to processing in accordance with
Sec. 206.155 of this part. Where the lessee's contract includes a
reservation of the right to process the gas and the lessee exercises
that right, Sec. 206.153 of this part shall apply instead of this
section.
(2) The value of production, for royalty purposes, of gas subject to
this subpart shall be the value of gas determined under this section
less applicable allowances.
(b)(1)(i) The value of gas sold under an arm's-length contract is
the gross proceeds accruing to the lessee except as provided in
paragraphs (b)(1)(ii), (iii), and (iv) of this section. The lessee shall
have the burden of demonstrating that its contract is arm's-length. The
value which the lessee reports, for royalty purposes, is subject to
monitoring, review, and audit. For purposes of this section, gas which
is sold or otherwise transferred to the lessee's marketing affiliate and
then sold by the marketing affiliate pursuant to an arm's-length
contract shall be valued in accordance with this paragraph based upon
the sale by the marketing affiliate. Also, where the lessee's arm's-
length contract for the sale of gas prior to processing provides for the
value to be determined based upon a percentage of the purchaser's
proceeds resulting from processing the gas, the value of production, for
royalty purposes, shall never be less than a value equivalent to 100
percent of the value of the residue gas attributable to the processing
of the lessee's gas.
(ii) In conducting reviews and audits, MMS will examine whether the
contract reflects the total consideration actually transferred either
directly or indirectly from the buyer to the seller for the gas. If the
contract does not reflect the total consideration, then the MMS may
require that the gas sold pursuant to that contract be valued in
accordance with paragraph (c) of this section. Value may not be less
than the gross proceeds accruing to the lessee, including the additional
consideration.
(iii) If the MMS determines that the gross proceeds accruing to the
lessee pursuant to an arm's-length contract do not reflect the
reasonable value of the production because of misconduct by or between
the contracting parties, or because the lessee otherwise has breached
its duty to the lessor to market the production for the mutual benefit
of the lessee and the lessor, then MMS shall require that the gas
production be valued pursuant to paragraph (c)(2) or (c)(3) of this
section, and in accordance with the notification requirements of
paragraph (e) of this section. When MMS determines that the value may be
unreasonable, MMS will notify the lessee and give the lessee an
opportunity to provide written information justifying the lessee's
value.
(iv) How to value over-delivered volumes under a cash-out program.
This paragraph applies to situations where a pipeline purchases gas from
a lessee according to a cash-out program under a transportation
contract. For all over-delivered volumes, the royalty value is the price
the pipeline is required to pay for volumes within the tolerances for
over-delivery specified in the transportation contract. Use the same
value for volumes that exceed the over-delivery tolerances even if those
volumes are subject to a lower price under the transportation contract.
However, if MMS determines that the price specified in the
transportation contract for over-delivered volumes is unreasonably low,
the lessee must value all over-delivered volumes under paragraph (c)(2)
or (c)(3) of this section.
(2) Notwithstanding the provisions of paragraph (b)(1) of this
section, the
[[Page 66]]
value of gas sold pursuant to a warranty contract shall be determined by
MMS, and due consideration will be given to all valuation criteria
specified in this section. The lessee must request a value determination
in accordance with paragraph (g) of this section for gas sold pursuant
to a warranty contract; provided, however, that any value determination
for a warranty contract in effect on the effective date of these
regulations shall remain in effect until modified by MMS.
(3) MMS may require a lessee to certify that its arm's-length
contract provisions include all of the consideration to be paid by the
buyer, either directly or indirectly, for the gas.
(c) The value of gas subject to this section which is not sold
pursuant to an arm's-length contract shall be the reasonable value
determined in accordance with the first applicable of the following
methods:
(1) The gross proceeds accruing to the lessee pursuant to a sale
under its non-arm's-length contract (or other disposition other than by
an arm's-length contract), provided that those gross proceeds are
equivalent to the gross proceeds derived from, or paid under, comparable
arm's-length contracts for purchases, sales, or other dispositions of
like-quality gas in the same field (or, if necessary to obtain a
reasonable sample, from the same area). In evaluating the comparability
of arm's-length contracts for the purposes of these regulations, the
following factors shall be considered: price, time of execution,
duration, market or markets served, terms, quality of gas, volume, and
such other factors as may be appropriate to reflect the value of the
gas;
(2) A value determined by consideration of other information
relevant in valuing like-quality gas, including gross proceeds under
arm's-length contracts for like-quality gas in the same field or nearby
fields or areas, posted prices for gas, prices received in arm's-length
spot sales of gas, other reliable public sources of price or market
information, and other information as to the particular lease operation
or the saleability of the gas; or
(3) A net-back method or any other reasonable method to determine
value.
(d)(1) Notwithstanding any other provisions of this section, except
paragraph (h) of this section, if the maximum price permitted by Federal
law at which gas may be sold is less than the value determined pursuant
to this section, then MMS shall accept such maximum price as the value.
For purposes of this section, price limitations set by any State or
local government shall not be considered as a maximum price permitted by
Federal law.
(2) The limitation prescribed in paragraph (d)(1) of this section
shall not apply to gas sold pursuant to a warranty contract and valued
pursuant to paragraph (b)(2) of this section.
(e)(1) Where the value is determined pursuant to paragraph (c) of
this section, the lessee shall retain all data relevant to the
determination of royalty value. Such data shall be subject to review and
audit, and MMS will direct a lessee to use a different value if it
determines that the reported value is inconsistent with the requirements
of these regulations.
(2) Any Federal lessee will make available upon request to the
authorized MMS or State representatives, to the Office of the Inspector
General of the Department of the Interior, or other person authorized to
receive such information, arm's-length sales and volume data for like-
quality production sold, purchased or otherwise obtained by the lessee
from the field or area or from nearby fields or areas.
(3) A lessee shall notify MMS if it has determined value pursuant to
paragraph (c)(2) or (c)(3) of this section. The notification shall be by
letter to the MMS Associate Director for Minerals Revenue Management or
his/her designee. The letter shall identify the valuation method to be
used and contain a brief description of the procedure to be followed.
The notification required by this paragraph is a one-time notification
due no later than the end of the month following the month the lessee
first reports royalties on a Form MMS-2014 using a valuation method
authorized by paragraph (c)(2) or (c)(3) of this section, and each time
there is a change in a method under paragraph (c)(2) or (c)(3) of this
section.
(f) If MMS determines that a lessee has not properly determined
value, the
[[Page 67]]
lessee shall pay the difference, if any, between royalty payments made
based upon the value it has used and the royalty payments that are due
based upon the value established by MMS. The lessee shall also pay
interest on that difference computed pursuant to 30 CFR 218.54. If the
lessee is entitled to a credit, MMS will provide instructions for the
taking of that credit.
(g) The lessee may request a value determination from MMS. In that
event, the lessee shall propose to MMS a value determination method, and
may use that method in determining value for royalty purposes until MMS
issues its decision. The lessee shall submit all available data relevant
to its proposal. The MMS shall expeditiously determine the value based
upon the lessee's proposal and any additional information MMS deems
necessary. In making a value determination MMS may use any of the
valuation criteria authorized by this subpart. That determination shall
remain effective for the period stated therein. After MMS issues its
determination, the lessee shall make the adjustments in accordance with
paragraph (f) of this section.
(h) Notwithstanding any other provision of this section, under no
circumstances shall the value of production for royalty purposes be less
than the gross proceeds accruing to the lessee for lease production,
less applicable allowances.
(i) The lessee must place gas in marketable condition and market the
gas for the mutual benefit of the lessee and the lessor at no cost to
the Federal Government. Where the value established under this section
is determined by a lessee's gross proceeds, that value will be increased
to the extent that the gross proceeds have been reduced because the
purchaser, or any other person, is providing certain services the cost
of which ordinarily is the responsibility of the lessee to place the gas
in marketable condition or to market the gas.
(j) Value shall be based on the highest price a prudent lessee can
receive through legally enforceable claims under its contract. If there
is no contract revision or amendment, and the lessee fails to take
proper or timely action to receive prices or benefits to which it is
entitled, it must pay royalty at a value based upon that obtainable
price or benefit. Contract revisions or amendments shall be in writing
and signed by all parties to an arm's-length contract. If the lessee
makes timely application for a price increase or benefit allowed under
its contract but the purchaser refuses, and the lessee takes reasonable
measures, which are documented, to force purchaser compliance, the
lessee will owe no additional royalties unless or until monies or
consideration resulting from the price increase or additional benefits
are received. This paragraph shall not be construed to permit a lessee
to avoid its royalty payment obligation in situations where a purchaser
fails to pay, in whole or in part or timely, for a quantity of gas.
(k) Notwithstanding any provision in these regulations to the
contrary, no review, reconciliation, monitoring, or other like process
that results in a redetermination by MMS of value under this section
shall be considered final or binding as against the Federal Government
or its beneficiaries until the audit period is formally closed.
(l) Certain information submitted to MMS to support valuation
proposals, including transportation or extraordinary cost allowances, is
exempted from disclosure by the Freedom of Information Act, 5 U.S.C.
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
[[Page 68]]
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 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
[[Page 69]]
shall be the reasonable value determined in accordance with the first
applicable of the following methods:
(1) The gross proceeds accruing to the lessee pursuant to a sale
under its non-arm's-length contract (or other disposition other than by
an arm's-length contract), provided that those gross proceeds are
equivalent to the gross proceeds derived from, or paid under, comparable
arm's-length contracts for purchases, sales, or other dispositions of
like quality residue gas or gas plant products from the same processing
plant (or, if necessary to obtain a reasonable sample, from nearby
plants). In evaluating the comparability of arm's-length contracts for
the purposes of these regulations, the following factors shall be
considered: price, time of execution, duration, market or markets
served, terms, quality of residue gas or gas plant products, volume, and
such other factors as may be appropriate to reflect the value of the
residue gas or gas plant products;
(2) A value determined by consideration of other information
relevant in valuing like-quality residue gas or gas plant products,
including gross proceeds under arm's-length contracts for like-quality
residue gas or gas plant products from the same gas plant or other
nearby processing plants, posted prices for residue gas or gas plant
products, prices received in spot sales of residue gas or gas plant
products, other reliable public sources of price or market information,
and other information as to the particular lease operation or the
saleability of such residue gas or gas plant products; or
(3) A net-back method or any other reasonable method to determine
value.
(d)(1) Notwithstanding any other provisions of this section, except
paragraph (h) of this section, if the maximum price permitted by Federal
law at which any residue gas or gas plant products may be sold is less
than the value determined pursuant to this section, then MMS shall
accept such maximum price as the value. For the purposes of this
section, price limitations set by any State or local government shall
not be considered as a maximum price permitted by Federal law.
(2) The limitation prescribed by paragraph (d)(1) of this section
shall not apply to residue gas sold pursuant to a warranty contract and
valued pursuant to paragraph (b)(2) of this section.
(e)(1) Where the value is determined pursuant to paragraph (c) of
this section, the lessee shall retain all data relevant to the
determination of royalty value. Such data shall be subject to review and
audit, and MMS will direct a lessee to use a different value if it
determines upon review or audit that the reported value is inconsistent
with the requirements of these regulations.
(2) Any Federal lessee will make available upon request to the
authorized MMS or State representatives, to the Office of the Inspector
General of the Department of the Interior, or other persons authorized
to receive such information, arm's-length sales and volume data for
like-quality residue gas and gas plant products sold, purchased or
otherwise obtained by the lessee from the same processing plant or from
nearby processing plants.
(3) A lessee shall notify MMS if it has determined any value
pursuant to paragraph (c)(2) or (c)(3) of this section. The notification
shall be by letter to the MMS Associate Director for Minerals Revenue
Management or his/her designee. The letter shall identify the valuation
method to be used and contain a brief description of the procedure to be
followed. The notification required by this paragraph is a one-time
notification due no later than the end of the month following the month
the lessee first reports royalties on a Form MMS-2014 using a valuation
method authorized by paragraph (c)(2) or (c)(3) of this section, and
each time there is a change in a method under paragraph (c)(2) or (c)(3)
of this section.
(f) If MMS determines that a lessee has not properly determined
value, the lessee shall pay the difference, if any, between royalty
payments made based upon the value it has used and the royalty payments
that are due based upon the value established by MMS. The lessee shall
also pay interest computed on that difference pursuant to 30 CFR 218.54.
If the lessee is entitled to a credit, MMS will provide instructions for
the taking of that credit.
(g) The lessee may request a value determination from MMS. In that
event, the lessee shall propose to MMS
[[Page 70]]
a value determination method, and may use that method in determining
value for royalty purposes until MMS issues its decision. The lessee
shall submit all available data relevant to its proposal. The MMS shall
expeditiously determine the value based upon the lessee's proposal and
any additional information MMS deems necessary. In making a value
determination, MMS may use any of the valuation criteria authorized by
this subpart. That determination shall remain effective for the period
stated therein. After MMS issues its determination, the lessee shall
make the adjustments in accordance with paragraph (f) of this section.
(h) Notwithstanding any other provision of this section, under no
circumstances shall the value of production for royalty purposes be less
than the gross proceeds accruing to the lessee for residue gas and/or
any gas plant products, less applicable transportation allowances and
processing allowances determined pursuant to this subpart.
(i) The lessee must place residue gas and gas plant products in
marketable condition and market the residue gas and gas plant products
for the mutual benefit of the lessee and the lessor at no cost to the
Federal Government. Where the value established under this section is
determined by a lessee's gross proceeds, that value will be increased to
the extent that the gross proceeds have been reduced because the
purchaser, or any other person, is providing certain services the cost
of which ordinarily is the responsibility of the lessee to place the
residue gas or gas plant products in marketable condition or to market
the residue gas and gas plant products.
(j) Value shall be based on the highest price a prudent lessee can
receive through legally enforceable claims under its contract. Absent
contract revision or amendment, if the lessee fails to take proper or
timely action to receive prices or benefits to which it is entitled it
must pay royalty at a value based upon that obtainable price or benefit.
Contract revisions or amendments shall be in writing and signed by all
parties to an arm's-length contract. If the lessee makes timely
application for a price increase or benefit allowed under its contract
but the purchaser refuses, and the lessee takes reasonable measures,
which are documented, to force purchaser compliance, the lessee will owe
no additional royalties unless or until monies or consideration
resulting from the price increase or additional benefits are received.
This paragraph shall not be construed to permit a lessee to avoid its
royalty payment obligation in situations where a purchaser fails to pay,
in whole or in part, or timely, for a quantity of residue gas or gas
plant product.
(k) Notwithstanding any provision in these regulations to the
contrary, no review, reconciliation, monitoring, or other like process
that results in a redetermination by MMS of value under this section
shall be considered final or binding against the Federal Government or
its beneficiaries until the audit period is formally closed.
(l) Certain information submitted to MMS to support valuation
proposals, including transportation allowances, processing allowances or
extraordinary cost allowances, is exempted from disclosure by the
Freedom of Information Act, 5 U.S.C. 552, or other Federal law. Any data
specified by law to be privileged, confidential, or otherwise exempt,
will be maintained in a confidential manner in accordance with
applicable law and regulations. All requests for information about
determinations made under this part are to be submitted in accordance
with the Freedom of Information Act regulation of the Department of the
Interior, 43 CFR part 2.
[53 FR 1272, Jan. 15, 1988, as amended at 56 FR 46530, Sept. 13, 1991;
61 FR 5465, Feb. 12, 1996; 62 FR 65762, Dec. 16, 1997]
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/
[[Page 71]]
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 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-
[[Page 72]]
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 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
[[Page 73]]
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 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
[[Page 74]]
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.
(B) The MMS shall allow as a cost an amount equal to the allowable
initial capital investment in the transportation system multiplied by
the rate of return determined pursuant to paragraph (b)(2)(v) of this
section. No allowance shall be provided for depreciation. This
alternative shall apply only to transportation facilities first placed
in service after March 1, 1988.
(v) The rate of return must be the industrial rate associated with
Standard and Poor's BBB rating. The rate of return must be the monthly
average rate as published in Standard and Poor's Bond Guide for the
first month for which the allowance is applicable. The rate must be
redetermined at the beginning of each subsequent calendar year.
(3)(i) The deduction for transportation costs shall be determined on
the basis of the lessee's cost of transporting each product through each
individual transportation system. Where more than one product in a
gaseous phase is transported, the allocation of costs to each of the
products transported shall be made in a consistent and equitable manner
in the same proportion as the ratio of the volume of each product
(excluding waste products which have no value) to the volume of
[[Page 75]]
all products in the gaseous phase (excluding waste products which have
no value). Except as provided in this paragraph, the lessee may not take
an allowance for transporting a product which is not royalty bearing
without MMS approval.
(ii) Notwithstanding the requirements of paragraph (b)(3)(i), the
lessee may propose to the MMS a cost allocation method on the basis of
the values of the products transported. MMS shall approve the method
unless it determines that it is not consistent with the purposes of the
regulations in this part.
(4) Where both gaseous and liquid products are transported through
the same transportation system, the lessee shall propose a cost
allocation procedure to MMS. The lessee may use the transportation
allowance determined in accordance with its proposed allocation
procedure until MMS issues its determination on the acceptability of the
cost allocation. The lessee shall submit all relevant data to support
its proposal. MMS shall then determine the transportation allowance
based upon the lessee's proposal and any additional information MMS
deems necessary. The lessee must submit the allocation proposal within 3
months of claiming the allocated deduction on the Form MMS-2014.
(5) A lessee may apply to the MMS for an exception from the
requirement that it compute actual costs in accordance with paragraphs
(b)(1) through (b)(4) of this section. The MMS will grant the exception
only if the lessee has a tariff for the transportation system approved
by the Federal Energy Regulatory Commission (FERC) (for both Federal and
Indian leases) or a State regulatory agency (for Federal leases). The
MMS shall deny the exception request if it determines that the tariff is
excessive as compared to arm's-length transportation charges by
pipelines, owned by the lessee or others, providing similar
transportation services in that area. If there are no arm's-length
transportation charges, MMS shall deny the exception request if: (i) No
FERC or State regulatory agency cost analysis exists and the FERC or
State regulatory agency, as applicable, has declined to investigate
pursuant to MMS timely objections upon filing; and (ii) the tariff
significantly exceeds the lessee's actual costs for transportation as
determined under this section.
(c) Reporting requirements. (1) Arm's-length contracts. (i) The
lessee must notify MMS of an allowance based on incurred costs by using
a separate line entry on the Form MMS-2014.
(ii) The MMS may require that a lessee submit arm's-length
transportation contracts, production agreements, operating agreements,
and related documents. Documents shall be submitted within a reasonable
time, as determined by MMS.
(2) Non-arm's-length or no contract. (i) The lessee must notify MMS
of an allowance based on the incurred costs by using a separate line
entry on the Form MMS-2014.
(ii) For new transportation facilities or arrangements, the lessee's
initial deduction shall include estimates of the allowable gas
transportation costs for the applicable period. Cost estimates shall be
based upon the most recently available operations data for the
transportation system or, if such data are not available, the lessee
shall use estimates based upon industry data for similar transportation
systems.
(iii) Upon request by MMS, the lessee shall submit all data used to
prepare the allowance deduction. The data shall be provided within a
reasonable period of time, as determined by MMS.
(iv) If the lessee is authorized to use its FERC-approved or State
regulatory agency-approved tariff as its transportation cost in
accordance with paragraph (b)(5) of this section, it shall follow the
reporting requirements of paragraph (c)(1) of this section.
(d) Interest and assessments. (1) If a lessee nets a transportation
allowance against the royalty value on the Form MMS-2014, the lessee
shall be assessed an amount of up to 10 percent of the allowance netted
not to exceed $250 per lease selling arrangement per sales period.
(2) If a lessee deducts a transportation allowance on its Form MMS-
2014 that exceeds 50 percent of the value of the gas transported without
obtaining prior approval of MMS under Sec. 206.156, the lessee shall pay
interest
[[Page 76]]
on the excess allowance amount taken from the date such amount is taken
to the date the lessee files an exception request with MMS.
(3) If a lessee erroneously reports a transportation allowance which
results in an underpayment of royalties, interest shall be paid on the
amount of that underpayment.
(4) Interest required to be paid by this section shall be determined
in accordance with 30 CFR 218.54.
(e) Adjustments. (1) If the actual transportation allowance is less
than the amount the lessee has taken on Form MMS-2014 for each month
during the allowance reporting period, the lessee shall be required to
pay additional royalties due plus interest computed under 30 CFR 218.54
from the allowance reporting period when the lessee took the deduction
to the date the lessee repays the difference to MMS. If the actual
transportation allowance is greater than the amount the lessee has taken
on Form MMS-2014 for each month during the allowance reporting period,
the lessee shall be entitled to a credit without interest.
(2) For lessees transporting production from onshore Federal leases,
the lessee must submit a corrected Form MMS-2014 to reflect actual
costs, together with any payment, in accordance with instructions
provided by MMS.
(3) For lessees transporting gas production from leases on the OCS,
if the lessee's estimated transportation allowance exceeds the allowance
based on actual costs, the lessee must submit a corrected Form MMS-2014
to reflect actual costs, together with its payment, in accordance with
instructions provided by MMS. If the lessee's estimated transportation
allowance is less than the allowance based on actual costs, the refund
procedure will be specified by MMS.
(f) Allowable costs in determining transportation allowances.
Lessees may include, but are not limited to, the following costs in
determining the arm's-length transportation allowance under paragraph
(a) of this section or the non-arm's-length transportation allowance
under paragraph (b) of this section:
(1) Firm demand charges paid to pipelines. You must limit the
allowable costs for the firm demand charges to the applicable rate per
MMBtu multiplied by the actual volumes transported. You may not include
any losses incurred for previously purchased but unused firm capacity.
You also may not include any gains associated with releasing firm
capacity. If you receive a payment or credit from the pipeline for
penalty refunds, rate case refunds, or other reasons, you must reduce
the firm demand charge claimed on the Form MMS-2014. You must modify the
Form MMS-2014 by the amount received or credited for the affected
reporting period;
(2) Gas supply realignment (GSR) costs. The GSR costs result from a
pipeline reforming or terminating supply contracts with producers to
implement the restructuring requirements of FERC Orders in 18 CFR part
284;
(3) Commodity charges. The commodity charge allows the pipeline to
recover the costs of providing service;
(4) Wheeling costs. Hub operators charge a wheeling cost for
transporting gas from one pipeline to either the same or another
pipeline through a market center or hub. A hub is a connected manifold
of pipelines through which a series of incoming pipelines are
interconnected to a series of outgoing pipelines;
(5) Gas Research Institute (GRI) fees. The GRI conducts research,
development, and commercialization programs on natural gas related
topics for the benefit of the U.S. gas industry and gas customers. GRI
fees are allowable provided such fees are mandatory in FERC-approved
tariffs;
(6) Annual Charge Adjustment (ACA) fees. FERC charges these fees to
pipelines to pay for its operating expenses;
(7) Payments (either volumetric or in value) for actual or
theoretical losses. This paragraph does not apply to non-arm's-length
transportation arrangements unless the transportation allowance is based
on a FERC or State regulatory-approved tariff;
(8) Temporary storage services. This includes short duration storage
services offered by market centers or hubs (commonly referred to as
``parking'' or
[[Page 77]]
``banking''), or other temporary storage services provided by pipeline
transporters, whether actual or provided as a matter of accounting.
Temporary storage is limited to 30 days or less; and
(9) Supplemental costs for compression, dehydration, and treatment
of gas. MMS allows these costs only if such services are required for
transportation and exceed the services necessary to place production
into marketable condition required under Secs. 206.152(i) and 206.153(i)
of this part.
(g) Nonallowable costs in determining transportation allowances.
Lessees may not include the following costs in determining the arm's-
length transportation allowance under paragraph (a) of this section or
the non-arm's-length transportation allowance under paragraph (b) of
this section:
(1) Fees or costs incurred for storage. This includes storing
production in a storage facility, whether on or off the lease, for more
than 30 days;
(2) Aggregator/marketer fees. This includes fees you pay to another
person (including your affiliates) to market your gas, including
purchasing and reselling the gas, or finding or maintaining a market for
the gas production;
(3) Penalties you incur as shipper. These penalties include, but are
not limited to:
(i) Over-delivery cash-out penalties. This includes the difference
between the price the pipeline pays you for over-delivered volumes
outside the tolerances and the price you receive for over-delivered
volumes within the tolerances;
(ii) Scheduling penalties. This includes penalties you incur for
differences between daily volumes delivered into the pipeline and
volumes scheduled or nominated at a receipt or delivery point;
(iii) Imbalance penalties. This includes penalties you incur
(generally on a monthly basis) for differences between volumes delivered
into the pipeline and volumes scheduled or nominated at a receipt or
delivery point; and
(iv) Operational penalties. This includes fees you incur for
violation of the pipeline's curtailment or operational orders issued to
protect the operational integrity of the pipeline;
(4) Intra-hub transfer fees. These are fees you pay to hub operators
for administrative services (e.g., title transfer tracking) necessary to
account for the sale of gas within a hub; and
(5) Other nonallowable costs. Any cost you incur for services you
are required to provide at no cost to the lessor.
(h) Other transportation cost determinations. Use this section when
calculating transportation costs to establish value using a netback
procedure or any other procedure that requires deduction of
transportation costs.
[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45762, Nov. 14, 1988; 61
FR 5465, Feb. 12, 1996; 62 FR 65762, Dec. 16, 1997]
Sec. 206.158 Processing allowances--general.
(a) Where the value of gas is determined pursuant to Sec. 206.153 of
this subpart, a deduction shall be allowed for the reasonable actual
costs of processing.
(b) Processing costs must be allocated among the gas plant products.
A separate processing allowance must be determined for each gas plant
product and processing plant relationship. Natural gas liquids (NGL's)
shall be considered as one product.
(c)(1) Except as provided in paragraph (d)(2) of this section, the
processing allowance shall not be applied against the value of the
residue gas. Where there is no residue gas MMS may designate an
appropriate gas plant product against which no allowance may be applied.
(2) Except as provided in paragraph (c)(3) of this section, the
processing allowance deduction on the basis of an individual product
shall not exceed 66\2/3\ percent of the value of each gas plant product
determined in accordance with Sec. 206.153 of this subpart (such value
to be reduced first for any transportation allowances related to
postprocessing transportation authorized by Sec. 206.156 of this
subpart).
(3) Upon request of a lessee, MMS may approve a processing allowance
in excess of the limitation prescribed by paragraph (c)(2) of this
section. The lessee must demonstrate that the processing costs incurred
in excess of the limitation prescribed in paragraph (c)(2) of this
section were reasonable,
[[Page 78]]
actual, and necessary. An application for exception (using Form MMS-
4393, Request to Exceed Regulatory Allowance Limitation) shall contain
all relevant and supporting documentation for MMS to make a
determination. Under no circumstances shall the value for royalty
purposes of any gas plant product be reduced to zero.
(d)(1) Except as provided in paragraph (d)(2) of this section, no
processing cost deduction shall be allowed for the costs of placing
lease products in marketable condition, including dehydration,
separation, compression, or storage, even if those functions are
performed off the lease or at a processing plant. Where gas is processed
for the removal of acid gases, commonly referred to as ``sweetening,''
no processing cost deduction shall be allowed for such costs unless the
acid gases removed are further processed into a gas plant product. In
such event, the lessee shall be eligible for a processing allowance as
determined in accordance with this subpart. However, MMS will not grant
any processing allowance for processing lease production which is not
royalty bearing.
(2)(i) If the lessee incurs extraordinary costs for processing gas
production from a gas production operation, it may apply to MMS for an
allowance for those costs which shall be in addition to any other
processing allowance to which the lessee is entitled pursuant to this
section. Such an allowance may be granted only if the lessee can
demonstrate that the costs are, by reference to standard industry
conditions and practice, extraordinary, unusual, or unconventional.
(ii) Prior MMS approval to continue an extraordinary processing cost
allowance is not required. However, to retain the authority to deduct
the allowance the lessee must report the deduction to MMS in a form and
manner prescribed by MMS.
(e) If MMS determines that a lessee has improperly determined a
processing allowance authorized by this subpart, then the lessee shall
pay any additional royalties, plus interest determined in accordance
with 30 CFR 218.54, or shall be entitled to a credit, without interest.
If the lessee takes a deduction for processing on the Form 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
[[Page 79]]
opportunity to provide written information justifying the lessee's
processing costs.
(2) If an arm's-length processing contract includes more than one
gas plant product and the processing costs attributable to each product
can be determined from the contract, then the processing costs for each
gas plant product shall be determined in accordance with the contract.
No allowance may be taken for the costs of processing lease production
which is not royalty-bearing.
(3) If an arm's-length processing contract includes more than one
gas plant product and the processing costs attributable to each product
cannot be determined from the contract, the lessee shall propose an
allocation procedure to MMS. The lessee may use its proposed allocation
procedure until MMS issues its determination. The lessee shall submit
all relevant data to support its proposal. MMS shall then determine the
processing allowance based upon the lessee's proposal and any additional
information MMS deems necessary. No processing allowance will be granted
for the costs of processing lease production which is not royalty
bearing. The lessee must submit the allocation proposal within 3 months
of claiming the allocated deduction on Form MMS-2014.
(4) Where the lessee's payments for processing under an arm's-length
contract are not based on a dollar per unit basis, the lessee shall
convert whatever consideration is paid to a dollar value equivalent for
the purposes of this section.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length processing contract or has no contract, including those
situations where the lessee performs processing for itself, the
processing allowance will be based upon the lessee's reasonable actual
costs as provided in this paragraph. All processing allowances deducted
under a non-arm's-length or no-contract situation are subject to
monitoring, review, audit, and adjustment. The lessee must claim a
processing allowance by reflecting it as a separate line entry on the
Form MMS-2014. When necessary or appropriate, MMS may direct a lessee to
modify its estimated or actual processing allowance.
(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
[[Page 80]]
of a processing plant shall not alter the depreciation schedule
established by the original processor/lessee for purposes of the
allowance calculation. With or without a change in ownership, a
processing plant shall be depreciated only once. Equipment shall not be
depreciated below a reasonable salvage value.
(B) The MMS shall allow as a cost an amount equal to the allowable
initial capital investment in the processing plant multiplied by the
rate of return determined pursuant to paragraph (b)(2)(v) of this
section. No allowance shall be provided for depreciation. This
alternative shall apply only to plants first placed in service after
March 1, 1988.
(v) The rate of return must be the industrial rate associated with
Standard and Poor's BBB rating. The rate of return must be the monthly
average rate as published in Standard and Poor's Bond Guide for the
first month for which the allowance is applicable. The rate must be
redetermined at the beginning of each subsequent calendar year.
(3) The processing allowance for each gas plant product shall be
determined based on the lessee's reasonable and actual cost of
processing the gas. Allocation of costs to each gas plant product shall
be based upon generally accepted accounting principles. The lessee may
not take an allowance for the costs of processing lease production which
is not royalty bearing.
(4) A lessee may apply to MMS for an exception from the requirement
that it compute actual costs in accordance with paragraphs (b)(1)
through (b)(3) of this section. The MMS may grant the exception only if:
(i) The lessee has arm's-length contracts for processing other gas
production at the same processing plant; and (ii) at least 50 percent of
the gas processed annually at the plant is processed pursuant to arm's-
length processing contracts; if the MMS grants the exception, the lessee
shall use as its processing allowance the volume weighted average prices
charged other persons pursuant to arm's-length contracts for processing
at the same plant.
(c) Reporting requirements--(1) Arm's-length contracts. (i) The
lessee must notify MMS of an allowance based on incurred costs by using
a separate 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.
[[Page 81]]
(4) Interest required to be paid by this section shall be determined
in accordance with 30 CFR 218.54.
(e) Adjustments. (1) If the actual processing allowance is less than
the amount the lessee has taken on Form MMS-2014 for each month during
the allowance reporting period, the lessee shall pay additional
royalties due plus interest computed under 30 CFR 218.54 from the
allowance reporting period when the lessee took the deduction to the
date the lessee repays the difference to MMS. If the actual processing
allowance is greater than the amount the lessee has taken on Form MMS-
2014 for each month during the allowance reporting period, the lessee
shall be entitled to a credit without interest.
(2) For lessees processing production from onshore Federal leases,
the lessee must submit a corrected Form MMS-2014 to reflect actual
costs, together with any payment, in accordance with instructions
provided by MMS.
(3) For lessees processing gas production from leases on the OCS, if
the lessee's estimated processing allowance exceeds the allowance based
on actual costs, the lessee must submit a corrected Form MMS-2014 to
reflect actual costs, together with its payment, in accordance with
instructions provided by MMS. If the lessee's estimated costs were less
than the actual costs, the refund procedure will be specified by MMS.
(f) Other processing cost determinations. The provisions of this
section shall apply to determine processing costs when establishing
value using a net back valuation procedure or any other procedure that
requires deduction of processing costs.
[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45762, Nov. 14, 1988; 61
FR 5466, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999]
Sec. 206.160 Operating allowances.
Notwithstanding any other provisions in these regulations, an
operating allowance may be used for the purpose of computing payment
obligations when specified in the notice of sale and the lease. The
allowance amount or 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.
[[Page 82]]
Sec. 206.171 What definitions apply to this subpart?
The following definitions apply to this subpart and to subpart J of
part 202 of this title:
Accounting for comparison means the same as dual accounting.
Active spot market means a market where one or more MMS-acceptable
publications publish bidweek prices (or if bidweek prices are not
available, first of the month prices) for at least one index-pricing
point in the index zone.
Allowance means a deduction in determining value for royalty
purposes. Processing allowance means an allowance for the reasonable,
actual costs of processing gas determined under this subpart.
Transportation allowance means an allowance for the reasonable, actual
cost of transportation determined under this subpart.
Approved Federal Agreement (AFA) means a unit or communitization
agreement approved under departmental regulations.
Area means a geographic region at least as large as the defined
limits of an oil or gas field, in which oil or gas lease products have
similar quality, economic, or legal characteristics. An area may be all
lands within the boundaries of an Indian reservation.
Arm's-length contract means a contract or agreement that has been
arrived at in the marketplace between independent, nonaffiliated persons
with opposing economic interests regarding that contract. For purposes
of this subpart, two persons are affiliated if one person controls, is
controlled by, or is under common control with another person. The
following percentages (based on the instruments of ownership of the
voting securities of an entity, or based on other forms of ownership)
determine if persons are affiliated:
(1) Ownership in excess of 50 percent constitutes control.
(2) Ownership of 10 through 50 percent creates a presumption of
control.
(3) Ownership of less than 10 percent creates a presumption of
noncontrol which MMS may rebut if it demonstrates actual or legal
control, including the existence of interlocking directorates.
Notwithstanding any other provisions of this subpart, contracts between
relatives, either by blood or by marriage, are not arm's-length
contracts. MMS may require the lessee to certify the percentage of
ownership or control of the entity. To be considered arm's-length for
any production month, a contract must meet the requirements of this
definition for that production month as well as when the contract was
executed.
Audit means a review, conducted under generally accepted accounting
and auditing standards, of royalty payment compliance activities of
lessees or other persons who pay royalties, rents, or bonuses on Indian
leases.
BIA means the Bureau of Indian Affairs of the Department of the
Interior.
BLM means the Bureau of Land Management of the Department of the
Interior.
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
[[Page 83]]
to pay royalty based on a value which is the higher of the value of gas
prior to processing less any applicable allowances as compared to the
combined value of drip condensate, residue gas, and gas plant products
after processing, less applicable allowances.
Entitlement (or entitled share) means the gas production from a
lease, or allocable to lease acreage under the terms of an AFA,
multiplied by the operating rights owner's percentage of interest
ownership in the lease or the acreage.
Facility measurement point (or point of royalty settlement) means
the point where the BLM-approved measurement device is located for
determining the volume of gas removed from the lease. The facility
measurement point may be on the lease or off-lease with BLM approval.
Field means a geographic region situated over one or more subsurface
oil and gas reservoirs encompassing at least the outermost boundaries of
all oil and gas accumulations known to be within those reservoirs
vertically projected to the land surface. Onshore fields are usually
given names and their official boundaries are often designated by oil
and gas regulatory agencies in the respective States in which the fields
are located.
Gas means any fluid, either combustible or noncombustible,
hydrocarbon or nonhydrocarbon, which is extracted from a reservoir and
which has neither independent shape nor volume, but tends to expand
indefinitely. It is a substance that exists in a gaseous or rarefied
state under standard temperature and pressure conditions.
Gas plant products means separate marketable elements, compounds, or
mixtures, whether in liquid, gaseous, or solid form, resulting from
processing gas. However, it does not include residue gas.
Gathering means the movement of lease production to a central
accumulation or treatment point on the lease, unit, or communitized
area; or a central accumulation or treatment point off the lease, unit,
or communitized area as approved by BLM operations personnel.
Gross proceeds (for royalty payment purposes) means the total monies
and other consideration accruing to an oil and gas lessee for the
disposition of unprocessed gas, residue gas, and gas plant products
produced. Gross proceeds includes, but is not limited to, payments to
the lessee for certain services such as compression, dehydration,
measurement, or field gathering to the extent that the lessee is
obligated to perform them at no cost to the Indian lessor, and payments
for gas processing rights. Gross proceeds, as applied to gas, also
includes but is not limited to reimbursements for severance taxes and
other reimbursements. Tax reimbursements are part of the gross proceeds
accruing to a lessee even though the Indian royalty interest is exempt
from taxation. Monies and other consideration, including the forms of
consideration identified in this paragraph, to which a lessee is
contractually or legally entitled but which it does not seek to collect
through reasonable efforts are also part of gross proceeds.
Index means the calculated composite price ($/MMBtu) of spot-market
sales published by a publication that meets MMS-established criteria for
acceptability at the index-pricing point.
Index-pricing point (IPP) means any point on a pipeline for which
there is an index.
Index zone means a field or an area with an active spot market and
published indices applicable to that field or area that are acceptable
to MMS under 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.
[[Page 84]]
For purposes of this subpart, this definition excludes Federal leases.
Lease products means any leased minerals attributable to,
originating from, or allocated to a lease.
Lessee means any person to whom the United States, a tribe, and/or
individual Indian landowner issues a lease, and any person who has been
assigned an obligation to make royalty or other payments required by the
lease. This includes any person who has an interest in a lease
(including operating rights owners) as well as an operator or payor who
has no interest in the lease but who has assumed the royalty payment
responsibility.
Like-quality lease products means lease products which have similar
chemical, physical, and legal characteristics.
Marketable condition means a condition in which lease products are
sufficiently free from impurities and otherwise so conditioned that a
purchaser will accept them under a sales contract typical for the field
or area.
MMS means the Minerals Management Service, Department of the
Interior. MMS includes, where appropriate, tribal auditors acting under
agreements under the Federal Oil and Gas Royalty Management Act of 1982,
30 U.S.C. 1701 et seq. or other applicable agreements.
Minimum royalty means that minimum amount of annual royalty that the
lessee must pay as specified in the lease or in applicable leasing
regulations.
Natural gas liquids (NGL's) means those gas plant products
consisting of ethane, propane, butane, or heavier liquid hydrocarbons.
Net-back method (or work-back method) means a method for calculating
market value of gas at the lease under which costs of transportation,
processing, and manufacturing are deducted from the proceeds received
for, or the value of, the gas, residue gas, or gas plant products, and
any extracted, processed, or manufactured products, at the first point
at which reasonable values for any such products may be determined by a
sale under an arm's-length contract or comparison to other sales of such
products.
Net output means the quantity of residue gas and each gas plant
product that a processing plant produces.
Net profit share means the specified share of the net profit from
production of oil and gas as provided in the agreement.
Operating rights owner (or working interest owner) means any person
who owns operating rights in a lease subject to this subpart. A record
title owner is the owner of operating rights under a lease except to the
extent that the operating rights or a portion thereof have been
transferred from record title (see BLM regulations at 43 CFR 3100.0-
5(d)).
Person means any individual, firm, corporation, association,
partnership, consortium, or joint venture (when established as a
separate entity).
Point of royalty measurement means the same as facility measurement
point.
Processing means any process designed to remove elements or
compounds (hydrocarbon and nonhydrocarbon) from gas, including
absorption, adsorption, or refrigeration. Field processes which normally
take place on or near the lease, such as natural pressure reduction,
mechanical separation, heating, cooling, dehydration, desulphurization
(or ``sweetening''), and compression, are not considered processing. The
changing of pressures and/or temperatures in a reservoir is not
considered processing.
Residue gas means that hydrocarbon gas consisting principally of
methane resulting from processing gas.
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.
[[Page 85]]
Takes means when the operating rights owner sells or removes
production from, or allocated to, the lease, or when such sale or
removal occurs for the benefit of an operating rights owner.
Work-back method means the same as net-back method.
Sec. 206.172 How do I value gas produced from leases in an index zone?
(a) What leases this section applies to. This section explains how
lessees must value, for royalty purposes, gas produced from Indian
leases located in an index zone. For other leases, value must be
determined under Sec. 206.174.
(1) You must use the valuation provision of this section if your
lease is in an index zone and meets one of the following two
requirements:
(i) Has a major portion provision;
(ii) Does not have a major portion provision, but provides for the
Secretary to determine the value of production.
(2) This section does not apply to carbon dioxide, nitrogen, or
other non-hydrocarbon components of the gas stream. However, if they are
recovered and sold separately from the gas stream, you must determine
the value of these products under Sec. 206.174.
(b) Valuing residue gas and gas before processing. (1) Except as
provided in paragraphs (e), (f), and (g) of this section, this paragraph
(b) explains how you must value the following four types of gas:
(i) Gas production before processing;
(ii) Gas production that you certify on Form MMS-4410, Certification
for Not Performing Accounting for Comparison (Dual Accounting), is not
processed before it flows into a pipeline with an index but which may be
processed later;
(iii) Residue gas after processing; and
(iv) Gas that is never processed.
(2) The value of gas production that is not sold under an arm's-
length dedicated contract is the index-based value determined under
paragraph (d) of this section unless the gas was subject to a previous
contract which was part of a gas contract settlement. If the previous
contract was subject to a gas 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
[[Page 86]]
(iii) Reduce the number calculated under paragraph (d)(1)(ii) of
this section by 10 percent, but not by less than 10 cents per MMBtu or
more than 30 cents per MMBtu. The result is the index-based value per
MMBtu for production from all leases in that index zone.
(2) MMS will publish in the Federal Register the index zones that
are eligible for the index-based valuation method under this paragraph.
MMS will monitor the market activity in the index zones and, if
necessary, hold a technical conference to add or modify a particular
index zone. Any change to the index zones will be published in the
Federal Register. MMS will consider the following five factors and
conditions in determining eligible index zones:
(i) Areas for which MMS-approved publications establish index prices
that accurately reflect the value of production in the field or area
where the production occurs;
(ii) Common markets served;
(iii) Common pipeline systems;
(iv) Simplification; and
(v) Easy identification in MMS's systems, such as counties or Indian
reservations.
(3) If market conditions change so that an index-based method for
determining value is no longer appropriate for an index zone, MMS will
hold a technical conference to consider disqualification of an index
zone. MMS will publish notice in the Federal Register if an index zone
is disqualified. If an index zone is disqualified, then production from
leases in that index zone cannot be valued under this paragraph.
(4) MMS periodically will publish in the Federal Register a list of
acceptable publications based on certain criteria, including, but not
limited to the following five criteria:
(i) Publications buyers and sellers frequently use;
(ii) Publications frequently referenced in purchase or sales
contracts;
(iii) Publications that use adequate survey techniques, including
the gathering of information from a substantial number of sales;
(iv) Publications that publish the range of reported prices they use
to calculate their index; and
(v) Publications independent from DOI, lessors, and lessees.
(5) Any publication may petition MMS to be added to the list of
acceptable publications.
(6) MMS may exclude an individual index price for an index zone in
an MMS-approved publication if MMS determines that the index price does
not accurately reflect the value of production in that index zone. MMS
will publish a list of excluded indices in the Federal Register.
(7) MMS will reference which tables in the publications you must use
for determining the associated index prices.
(8) The index-based values determined under this paragraph are not
subject to deductions for transportation or processing allowances
determined under Secs. 206.177, 206.178, 206.179, and 206.180.
(e) Determining the minimum value for royalty purposes of gas sold
beyond the first index pricing point. (1) Notwithstanding any other
provision of this section, the value for royalty purposes of gas
production from an Indian lease that is sold beyond the first index
pricing point through which it flows cannot be less than the value
determined under this paragraph (e).
(2) By June 30 following any calendar year, you must calculate for
each month of that calendar year your safety net price per MMBtu using
the procedures in paragraph (e)(3) of this section. You must calculate a
safety net price for each month and for each index zone where you have
an Indian lease for which you report and pay royalties.
(3) Your safety net price (S) for an index zone is the volume-
weighted average contract price per delivered MMBtu under your or your
affiliate's arm's-length contracts for the disposition of residue gas or
unprocessed gas produced from your Indian leases in that index zone as
computed under this paragraph (e)(3).
(i) Include in your calculation only sales under those contracts
that establish a delivery point beyond the first index pricing point
through which the
[[Page 87]]
gas flows, and that include any gas produced from or allocable to one or
more of your Indian leases in that index zone, even if the contract also
includes gas produced from Federal, State, or fee properties. Include in
your volume-weighted average calculation those volumes that are
allocable to your Indian leases in that index zone.
(ii) Do not reduce the contract price for any transportation costs
incurred to deliver the gas to the purchaser.
(iii) For purposes of this paragraph (e), the contract price will
not include the following amounts:
(A) Any amounts you receive in compromise or settlement of a
predecessor contract for that gas;
(B) Deductions for you or any other person to put gas production
into marketable condition or to market the gas; and
(C) Any amounts related to marketable securities associated with the
sales contract.
(4) Next, you must determine for each month the safety net
differential (SND). You must perform this calculation separately for
each index zone.
(i) For each index zone, the safety net differential is equal to:
SND = [(0.80 x S) - (1.25 x I)] where (I) is the index-based value
determined under 30 CFR 206.172(d).
(ii) If the safety net differential is positive you owe additional
royalties.
(5)(i) To calculate the additional royalties you owe, make the
following calculation for each of your Indian leases in that index zone
that produced gas that was sold beyond the first index-pricing point
through which the gas flowed and that was used in the calculation in
paragraph (e)(3) of this section:
Lease royalties owed = SND x V x R, where R = the lease royalty rate
and V = the volume allocable to the lease which produced gas that was
sold beyond the first index pricing point.
(ii) If gas produced from any of your Indian leases is commingled or
pooled with gas produced from non-Indian properties, and if any of the
combined gas is sold at a delivery point beyond the first index pricing
point through which the gas flows, then the volume allocable to each
Indian lease for which gas was sold beyond the first index pricing point
in the calculation under paragraph (e)(5)(i) of this section is the
volume produced from the lease multiplied by the proportion that the
total volume of gas sold beyond the first index pricing point bears to
the total volume of gas commingled or pooled from all properties.
(iii) Add the numbers calculated for each lease under paragraph
(e)(5)(i) of this section. The total is the additional royalty you owe.
(6) You have the following responsibilities to comply with the
minimum value for royalty purposes:
(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
[[Page 88]]
the first day of the second month following the date MMS publishes
notice of its decision in the Federal Register.
(ii) Termination of an exclusion under paragraph (f)(2)(i) of this
section cannot take effect earlier than 1 year after the first day of
the production month that the exclusion was effective.
(3) The Indian tribe's request to MMS under either paragraph (f)(1)
or (2) of this section must be in the form of a tribal resolution.
(g) Excluding Indian allotted leases from valuation under this
section. (1)(i) MMS may exclude any Indian allotted leases from
valuation under this section. MMS will consult with BIA regarding the
exclusion.
(ii) If MMS excludes your lease, you must value your production
under Sec. 206.174 beginning with production on the first day of the
second month following the date MMS publishes notice of its decision in
the Federal Register.
(iii) If MMS excludes any Indian allotted leases under this
paragraph (g)(1), it will exclude all Indian allotted leases in the same
field.
(2)(i) MMS may terminate the exclusion of any Indian allotted leases
from valuation under this section. MMS will consult with BIA regarding
the termination.
(ii) If MMS terminates the exclusion, you must value your production
under Sec. 206.172 beginning with production on the first day of the
second month following the date MMS publishes notice of its decision in
the Federal Register.
Sec. 206.173 How do I calculate the alternative methodology for dual accounting?
(a) Electing a dual accounting method. (1) If you are required to
perform the accounting for comparison (dual accounting) under
Sec. 206.176, you have two choices. You may elect to perform the dual
accounting calculation according to either Sec. 206.176(a) (called
actual dual accounting), or paragraph (b) of this section (called the
alternative methodology for dual accounting).
(2) You must make a separate election to use the alternative
methodology for dual accounting for your Indian leases in each MMS-
designated area. Your election for a designated area must apply to all
of your Indian leases in that area.
(i) MMS will publish in the Federal Register a list of the lease
prefixes that will be associated with each designated area for purposes
of this section. The MMS-designated areas are as follows:
(A) Alabama-Coushatta;
(B) Blackfeet Reservation;
(C) Crow Reservation;
(D) Fort Belknap Reservation;
(E) Fort Berthold Reservation;
(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
[[Page 89]]
Sec. 206.174 to provide the value of the gas after processing. You must
use the value of the gas after processing for royalty payment purposes.
The amount of the increase depends on your relationship with the
owner(s) of the plant where the gas is processed. If you have no direct
or indirect ownership interest in the processing plant, then the
increase is lower, as provided in the table in paragraph (b)(2)(ii) of
this section. If you have a direct or indirect ownership interest in the
plant where the gas is processed, the increase is higher, as provided in
paragraph (b)(2)(ii) of this section.
(2) To calculate the value of the gas after processing using the
alternative methodology for dual accounting, you must apply the increase
to the value before processing, determined in either Sec. 206.172 or
Sec. 206.174, as follows:
(i) Value of gas after processing = (value determined under either
Sec. 206.172 or Sec. 206.174, as applicable) x (1 + increment for dual
accounting); and
(ii) In this equation, the increment for dual accounting is the
number you take from the applicable Btu range, determined under
paragraph (b)(3) of this section, in the following table:
------------------------------------------------------------------------
Increment Increment
if Lessee if lessee
has no has an
BTU range ownership ownership
interest in interest in
plant plant
------------------------------------------------------------------------
1001 to 1050.................................. .0275 .0375
1051 to 1100.................................. .0400 .0625
1101 to 1150.................................. .0425 .0750
1151 to 1200.................................. .0700 .1225
1201 to 1250.................................. .0975 .1700
1251 to 1300.................................. .1175 .2050
1301 to 1350.................................. .1400 .2400
1351 to 1400.................................. .1450 .2500
1401 to 1450.................................. .1500 .2600
1451 to 1500.................................. .1550 .2700
1501 to 1550.................................. .1600 .2800
1551 to 1600.................................. .1650 .2900
1601 to 1650.................................. .1850 .3225
1651 to 1700.................................. .1950 .3425
1701+......................................... .2000 .3550
------------------------------------------------------------------------
(3) The applicable Btu for purposes of this section is the volume
weighted-average Btu for the lease computed from measurements at the
facility measurement point(s) for gas production from the lease.
(4) If any of your gas from the lease is processed during a month,
use the following two paragraphs to determine which amounts are subject
to dual accounting and which dual accounting method you must use.
(i) Weighted-average Btu content determined under paragraph (b)(3)
of this section is greater than 1,000 Btu's per cubic foot (Btu/cf). All
gas production from the lease is subject to dual accounting and you must
use the alternative method for all that gas production if you elected to
use the alternative method under this section.
(ii) Weighted-average Btu content determined under paragraph (b)(3)
of this section is less than or equal to 1,000 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.
[[Page 90]]
(4) This paragraph applies if your lease has a major portion
provision. It also applies if your lease does not have a major portion
provision but the lease provides for the Secretary to determine value.
(i) The value of production you must initially report and pay is the
value determined in accordance with the other paragraphs of this
section.
(ii) MMS will determine the major portion value and notify you in
the Federal Register of that value. The value of production for royalty
purposes for your lease is the higher of either the value determined
under this section which you initially used to report and pay royalties,
or the major portion value calculated under this paragraph (a)(4). If
the major portion value is higher, you must submit an amended Form MMS-
2014 to MMS by the due date specified in the written notice from MMS of
the major portion value. Late-payment interest under 30 CFR 218.54 on
any underpayment will not begin to accrue until the date the amended
Form MMS-2014 is due to MMS.
(iii) Except as provided in paragraph (a)(4)(iv) of this section,
MMS will calculate the major portion value for each designated area
(which are the same designated areas as under Sec. 206.173) using values
reported for unprocessed gas and residue gas on Form MMS-2014 for gas
produced from leases on that Indian reservation or other designated
area. MMS will array the reported prices from highest to lowest price.
The major portion value is that price at which 25 percent (by volume) of
the gas (starting from the highest) is sold. MMS cannot unilaterally
change the major portion value after you are notified in writing of what
that value is for your leases.
(iv) MMS may calculate the major portion value using different data
than the data described in paragraph (a)(4)(iii) of this section or data
to augment the data described in paragraph (a)(4)(iii) of this section.
This may include price data reported to the State tax authority or price
data from leases MMS has reviewed in the designated area. MMS may use
this alternate or the augmented data source beginning with production on
the first day of the month following the date MMS publishes notice in
the Federal Register that it is calculating the major portion using a
method in this paragraph (a)(4)(iv) of this section.
(b) Arm's-length contracts. (1) The value of gas, residue gas, or
any gas plant product you sell under an arm's-length contract is the
gross proceeds accruing to you or your affiliate, except as provided in
paragraphs (b)(1)(ii)-(iv) of this section.
(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
[[Page 91]]
specified in the transportation contract. Use the same value for volumes
that exceed the over-delivery tolerances even if those volumes are
subject to a lower price specified in the transportation contract.
However, if MMS determines that the price specified in the
transportation contract for over-delivered volumes is unreasonably low,
the lessees must value all over-delivered volumes under paragraph (c)(2)
or (3) of this section.
(2) MMS may require you to certify that your arm's-length contract
provisions include all of the consideration the buyer pays, either
directly or indirectly, for the gas, residue gas, or gas plant product.
(c) Non-arm's-length contracts. If your gas, residue gas, or any gas
plant product is not sold under an arm's-length contract, then you must
value the production using the first applicable method of the following
three methods:
(1) The gross proceeds accruing to you under your non-arm's-length
contract sale (or other disposition other than by an arm's-length
contract), provided that those gross proceeds are equivalent to the
gross proceeds derived from, or paid under, comparable arm's-length
contracts for purchases, sales, or other dispositions of like-quality
gas in the same field (or, if necessary to obtain a reasonable sample,
from the same area). For residue gas or gas plant products, the
comparable arm's-length contracts must be for gas from the same
processing plant (or, if necessary to obtain a reasonable sample, from
nearby plants). In evaluating the comparability of arm's-length
contracts for the purposes of these regulations, the following factors
will be considered: price, time of execution, duration, market or
markets served, terms, quality of gas, residue gas, or gas plant
products, volume, and such other factors as may be appropriate to
reflect the value of the gas, residue gas, or gas plant products.
(2) A value determined by consideration of other information
relevant in valuing like-quality gas, residue gas, or gas plant
products, including gross proceeds under arm's-length contracts for
like-quality gas in the same field or nearby fields or areas, or for
residue gas or gas plant products from the same gas plant or other
nearby processing plants. Other factors to consider include prices
received in spot sales of gas, residue gas or gas plant products, other
reliable public sources of price or market information, and other
information as to the particular lease operation or the salability of
such gas, residue gas, or gas plant products.
(3) A net-back method or any other reasonable method to determine
value.
(d) Supporting data. If you determine the value of production under
paragraph (c) of this section, you must retain all data relevant to the
determination of royalty value.
(1) Such data will be subject to review and audit, and MMS will
direct you to use a different value if we determine upon review or audit
that the value you reported is inconsistent with the requirements of
these regulations.
(2) You must make all such data available upon request to the
authorized MMS or Indian representatives, to the Office of the Inspector
General of the Department, or other authorized persons. This includes
your arm's-length sales and volume data for like-quality gas, residue
gas, and gas plant products that are sold, purchased, or otherwise
obtained from the same processing plant or from nearby processing
plants, or from the same or nearby field or area.
(e) Improper values. If MMS determines that you have not properly
determined value, you must pay the difference, if any, between royalty
payments made based upon the value you used and the royalty payments
that are due based upon the value MMS established. You also must pay
interest computed on that difference under 30 CFR 218.54. If you are
entitled to a credit, MMS will provide instructions on how to take that
credit.
(f) Value guidance. You may ask MMS for guidance in determining
value. You may propose a valuation method to MMS. Submit all available
data related to your proposal and any additional information MMS deems
necessary. MMS will promptly review your proposal and provide you with a
non-binding determination of the guidance you request.
(g) Minimum value of production. (1) For gas, residue gas, and gas
plant products valued under this section,
[[Page 92]]
under no circumstances may the value of production for royalty purposes
be less than the gross proceeds accruing to the lessee (including its
affiliates) for gas, residue gas and/or any gas plant products, less
applicable transportation allowances and processing allowances
determined under this subpart.
(2) For gas plant products valued under this section and not valued
under Sec. 206.173, the alternative methodology for dual accounting, the
minimum value of production for each gas plant product is as follows:
(i) Leases in certain States and areas have specific minimum values.
(A) For production from leases in Colorado in the San Juan Basin,
New Mexico, and Texas, the monthly average minimum price reported in
commercial price bulletins for the gas plant product at Mont Belvieu,
Texas, minus 8.0 cents per gallon.
(B) For production in Arizona, in Colorado outside the San Juan
Basin, Minnesota, Montana, North Dakota, Oklahoma, South Dakota, Utah,
and Wyoming, the monthly average minimum price reported in commercial
price bulletins for the gas plant product at Conway, Kansas, minus 7.0
cents per gallon;
(ii) You may use any commercial price bulletin, but you must use the
same bulletin for all of the calendar year. If the commercial price
bulletin you are using stops publication, you may use a different
commercial price bulletin for the remaining part of the calendar year;
and (iii) If you use a commercial price bulletin that is published
monthly, the monthly average minimum price is the bulletin's minimum
price. If you use a commercial price bulletin that is published weekly,
the monthly average minimum price is the arithmetic average of the
bulletin's weekly minimum prices. If you use a commercial price bulletin
that is published daily, the monthly average minimum price is the
arithmetic average of the bulletin's minimum prices for each Wednesday
in the month.
(h) Marketable condition/Marketing. You are required to place gas,
residue gas, and gas plant products in marketable condition and market
the gas for the mutual benefit of the lessee and the lessor at no cost
to the Indian lessor. When your gross proceeds establish the value under
this section, that value must be increased to the extent that the gross
proceeds have been reduced because the purchaser, or any other person,
is providing certain services to place the gas, residue gas, or gas
plant products in marketable condition or to market the gas, the cost of
which ordinarily is your responsibility.
(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
[[Page 93]]
Federal law. Any data specified by law to be privileged, confidential,
or otherwise exempt, will be maintained in a confidential manner in
accordance with applicable laws and regulations. All requests for
information about determinations made under this subpart must be
submitted in accordance with the Freedom of Information Act regulation
of the Department of the Interior, 43 CFR part 2.
[64 FR 43515, Aug. 10, 1999, as amended at 65 FR 62614, Oct. 19, 2000]
Sec. 206.175 How do I determine quantities and qualities of production
for computing royalties?
(a) For unprocessed gas, you must pay royalties on the quantity and
quality at the facility measurement point BLM either allowed or
approved.
(b) For residue gas and gas plant products, you must pay royalties
on your share of the monthly net output of the plant even though residue
gas and/or gas plant products may be in temporary storage.
(c) If you have no ownership interest in the processing plant and
you do not operate the plant, you may use the contract volume allocation
to determine your share of plant products.
(d) If you have an ownership interest in the plant or if you operate
it, use the following procedure to determine the quantity of the residue
gas and gas plant products attributable to you for royalty payment
purposes:
(1) When the net output of the processing plant is derived from gas
obtained from only one lease, the quantity of the residue gas and gas
plant products on which you must pay royalty is the net output of the
plant.
(2) When the net output of a processing plant is derived from gas
obtained from more than one lease producing gas of uniform content, the
quantity of the residue gas and gas plant products allocable to each
lease must be in the same proportions as the ratios obtained by dividing
the amount of gas delivered to the plant from each lease by the total
amount of gas delivered from all leases.
(3) When the net output of a processing plant is derived from gas
obtained from more than one lease producing gas of non-uniform content,
the volumes of residue gas and gas plant products allocable to each
lease are based on theoretical volumes of residue gas and gas plant
products measured in the lease gas stream. You must calculate the
portion of net plant output of residue gas and gas plant products
attributable to each lease as follows:
(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
[[Page 94]]
this section, the actual dual accounting value, for royalty purposes, is
the greater of the following two values:
(1) The combined value of the following products:
(i) The residue gas and gas plant products resulting from processing
the gas determined under either Sec. 206.172 or Sec. 206.174, less any
applicable allowances; and
(ii) Any drip condensate associated with the processed gas recovered
downstream of the point of royalty settlement without resorting to
processing determined under Sec. 206.52, less applicable allowances.
(2) The value of the gas prior to processing determined under either
Sec. 206.172 or Sec. 206.174, including any applicable allowances.
(b) If you are required to account for comparison, you may elect to
use the alternative dual accounting methodology provided for in
Sec. 206.173 instead of the provisions in paragraph (a) of this section.
(c) Accounting for comparison is not required for gas if no gas from
the lease is processed until after the gas flows into a pipeline with an
index located in an index zone or into a mainline pipeline not in an
index zone. If you do not perform dual accounting, you must certify to
MMS that gas flows into such a pipeline before it is processed.
(d) Except as provided in paragraph (e) of this section, if you
value any gas production from a lease for a month using the dual
accounting provisions of this section or the alternative dual accounting
methodology of Sec. 206.173, then the value of that gas is the minimum
value for any other gas production from that lease for that month
flowing through the same facility measurement point.
(e) If the weighted-average Btu quality for your lease is less than
1,000 Btu's per cubic foot, see Sec. 206.173(b)(4)(ii) to determine if
you must perform a dual accounting calculation.
Transportation Allowances
Sec. 206.177 What general requirements regarding transportation allowances
apply to me?
(a) When you value gas under Sec. 206.174 at a point off the lease,
unit, or communitized area (for example, sales point or point of value
determination), you may deduct from value a transportation allowance to
reflect the value, for royalty purposes, at the lease, unit, or
communitized area. The allowance is based on the reasonable actual costs
you incurred to transport unprocessed gas, residue gas, or gas plant
products from a lease to a point off the lease, unit, or communitized
area. This would include, if appropriate, transportation from the lease
to a gas processing plant off the lease, unit, or communitized 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.
[[Page 95]]
Sec. 206.178 How do I determine a transportation allowance?
(a) Determining a transportation allowance under an arm's-length
contract. (1) This paragraph explains how to determine your allowance if
you have an arm's-length transportation contract.
(i) If you have an arm's-length contract for transportation of your
production, the transportation allowance is the reasonable, actual costs
you incur for transporting the unprocessed gas, residue gas and/or gas
plant products under that contract. Paragraphs (a)(1)(ii) and (iii) of
this section provide a limited exception. You have the burden of
demonstrating that your contract is arm's-length. Your allowances also
are subject to paragraph (e) of this section. You are required to submit
to MMS a copy of your arm's-length transportation contract(s) and all
subsequent amendments to the contract(s) within 2 months of the date MMS
receives your report which claims the allowance on the Form MMS-2014.
(ii) When either MMS or a tribe conducts reviews and audits, they
will examine whether or not the contract reflects more than the
consideration actually transferred either directly or indirectly from
you to the transporter of the transportation. If the contract reflects
more than the total consideration, then MMS may require that the
transportation allowance be determined under paragraph (b) of this
section.
(iii) If MMS determines that the consideration paid under an arm's-
length transportation contract does not reflect the value of the
transportation because of misconduct by or between the contracting
parties, or because you otherwise have breached your duty to the lessor
to market the production for the mutual benefit of you and the lessor,
then MMS will require that the transportation allowance be determined
under paragraph (b) of this section. In these circumstances, MMS will
notify you and give you an opportunity to provide written information
justifying your transportation costs.
(2) This paragraph explains how to allocate the costs to each
product if your arm's-length transportation contract includes more than
one product in a gaseous phase and the transportation costs attributable
to each product cannot be determined from the contract.
(i) If your arm's-length transportation contract includes more than
one product in a gaseous phase and the transportation costs attributable
to each product cannot be determined from the contract, the total
transportation costs must be allocated in a consistent and equitable
manner to each of the products transported. To make this allocation, use
the same proportion as 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
[[Page 96]]
based upon your proposal and any additional information MMS deems
necessary.
(4) If your payments for transportation under an arm's-length
contract are not based on a dollar per unit price, you must convert
whatever consideration is paid to a dollar value equivalent for the
purposes of this section.
(5) Where an arm's-length sales contract price includes a reduction
for a transportation factor, MMS will not consider the transportation
factor to be a transportation allowance. You may use the transportation
factor to determine your gross proceeds for the sale of the product.
However, the transportation factor may not exceed 50 percent of the base
price of the product without MMS approval.
(b) Determining a transportation allowance under a non-arm's-length
or no contract. (1) This paragraph explains how to determine your
allowance if you have a non-arm's-length transportation contract or no
contract.
(i) When you have a non-arm's-length transportation contract or no
contract, including those situations where you perform transportation
services for yourself, the transportation allowance is based upon your
reasonable, allowable, actual costs for transportation as provided in
this paragraph.
(ii) All transportation allowances deducted under a non-arm's-length
or no contract situation are subject to monitoring, review, audit, and
adjustment. You must submit the actual cost information to support the
allowance to MMS on Form MMS-4295, Gas Transportation Allowance Report,
within 3 months after the end of the 12-month period to which the
allowance applies. However, MMS may approve a longer time period. MMS
will monitor the allowance deductions to ensure that deductions are
reasonable and allowable. When necessary or appropriate, MMS may require
you to modify your actual transportation allowance deduction.
(2) This paragraph explains what actual transportation costs are
allowable under a non-arm's-length contract or no contract situation.
The transportation allowance for non-arm's-length or no-contract
situations is based upon your actual costs for transportation during the
reporting period. Allowable costs include operating and maintenance
expenses, overhead, and either depreciation and a return on
undepreciated capital investment (in accordance with paragraph
(b)(2)(iv)(A) of this section), or a cost equal to the initial
depreciable investment in the transportation system multiplied by a rate
of return in accordance with paragraph (b)(2)(iv)(B) of this section.
Allowable capital costs are generally those costs for depreciable fixed
assets (including costs of delivery and installation of capital
equipment) that are an integral part of the transportation system.
(i) Allowable operating expenses include operations supervision and
engineering, operations labor, fuel, utilities, materials, ad valorem
property taxes, rent, supplies, and any other directly allocable and
attributable operating expense that you can document.
(ii) Allowable maintenance expenses include maintenance of the
transportation system, maintenance of equipment, maintenance labor, and
other directly allocable and attributable maintenance expenses that you
can document.
(iii) Overhead directly attributable and allocable to the operation
and maintenance of the transportation system is an allowable expense.
State and Federal income taxes and severance taxes and other fees,
including royalties, are not allowable expenses.
(iv) You may use either depreciation with a return on undepreciated
capital investment or a return on depreciable capital investment. After
you have elected to use either method for a transportation system, you
may not later elect to change to the other alternative without MMS
approval.
(A) To compute depreciation, you may elect to use either a straight-
line depreciation method based on the life of equipment or on the life
of the reserves that the transportation system services, or a unit of
production method. Once you make an election, you may not change methods
without MMS approval. A change in ownership of a transportation system
will not alter the depreciation schedule that the original transporter/
lessee established
[[Page 97]]
for purposes of the allowance calculation. With or without a change in
ownership, a transportation system may be depreciated only once.
Equipment may not be depreciated below a reasonable salvage value. To
compute a return on undepreciated capital investment, you will multiply
the undepreciated capital investment in the transportation system by the
rate of return determined under paragraph (b)(2)(v) of this section.
(B) To compute a return on depreciable capital investment, you will
multiply the initial capital investment in the transportation system by
the rate of return determined under paragraph (b)(2)(v) of this section.
No allowance will be provided for depreciation. This alternative will
apply only to transportation facilities first placed in service after
March 1, 1988.
(v) The rate of return is the industrial rate associated with
Standard and Poor's BBB rating. The rate of return is the monthly
average rate as published in Standard and Poor's Bond Guide for the
first month of the reporting period for which the allowance is
applicable and is effective during the reporting period. The rate must
be redetermined at the beginning of each subsequent transportation
allowance reporting period that is determined under paragraph (b)(4) of
this section.
(3) This paragraph explains how to allocate transportation costs to
each product and transportation system.
(i) The deduction for transportation costs must be determined based
on your cost of transporting each product through each individual
transportation system. If you transport more than one product in a
gaseous phase, the allocation of costs to each of the products
transported must be made in a consistent and equitable manner. The
allocation should be in the same proportion that the volume of each
product (excluding waste products that have no value) bears to the
volume of all products in the gaseous phase (excluding waste products
that have no value). Except as provided in this paragraph, you may not
take an allowance for transporting a product that is not royalty bearing
without MMS approval.
(ii) As an alternative to the requirements of paragraph (b)(3)(i) of
this section, you may propose to MMS a cost allocation method based on
the values of the products transported. MMS will approve the method upon
determining that it meets one of the two following requirements:
(A) The methodology in paragraph (b)(3)(i) of this section cannot be
applied; and
(B) Your proposal is more reasonable than the method in paragraph
(b)(3)(i) of this section.
(4) Your transportation allowance under this paragraph (b) must be
determined based upon a calendar year or other period if you and MMS
agree to an alternative.
(5) If you transport both gaseous and liquid products through the
same transportation system, you must propose a cost allocation procedure
to MMS. You may use the transportation allowance determined in
accordance with your proposed allocation procedure until MMS issues its
determination on the acceptability of the cost allocation. You are
required to submit all relevant data to support your proposal. MMS will
then determine the transportation allowance based upon your proposal and
any additional information MMS deems necessary.
(c) Using the alternative transportation calculation when you have a
non-arm's-length or no contract. (1) As an alternative to computing your
transportation allowance under paragraph (b) of this section, you may
use as the transportation allowance 10 percent of your gross proceeds
but not to exceed 30 cents per MMBtu.
(2) Your election to use the alternative transportation allowance
calculation in paragraph (c)(1) of this section must be made at the
beginning of a month and must remain in effect for an entire calendar
year. Your first election will remain in effect until the end of the
succeeding calendar year, except for elections effective January 1 that
will be effective only for that calendar year.
(d) Reporting your transportation allowance. (1) If MMS requests,
you must submit all data used to determine your transportation
allowance. The data must be provided within a reasonable period of time
that MMS will determine.
[[Page 98]]
(2) You must report transportation allowances as a separate line
item on Form MMS-2014. MMS may approve a different reporting procedure
on allottee leases, and with lessor approval on tribal leases.
(e) Adjusting incorrect allowances. If for any month the
transportation allowance you are entitled to is less than the amount you
took on Form MMS-2014, you are required to report and pay additional
royalties due, plus interest computed under 30 CFR 218.54 from the first
day of the first month you deducted the improper transportation
allowance until the date you pay the royalties due. If the
transportation allowance you are entitled to is greater than the amount
you took on Form MMS-2014 for any royalties during the reporting period,
you are entitled to a credit. No interest will be paid on the
overpayment.
(f) Determining allowable costs for transportation allowances.
Lessees may include, but are not limited to, the following costs in
determining the arm's-length transportation allowance under paragraph
(a) of this section or the non-arm's-length transportation allowance
under paragraph (b) of this section:
(1) Firm demand charges paid to pipelines. You must limit the
allowable costs for the firm demand charges to the applicable rate per
MMBtu multiplied by the actual volumes transported. You may not include
any losses incurred for previously purchased but unused firm capacity.
You also may not include any gains associated with releasing firm
capacity. If you receive a payment or credit from the pipeline for
penalty refunds, rate case refunds, or other reasons, you must reduce
the firm demand charge claimed on the Form MMS-2014. You must modify the
Form MMS-2014 by the amount received or credited for the affected
reporting period.
(2) Gas supply realignment (GSR) costs. The GSR costs result from a
pipeline reforming or terminating supply contracts with producers to
implement the restructuring requirements of FERC orders in 18 CFR part
284.
(3) Commodity charges. The commodity charge allows the pipeline to
recover the costs of providing service.
(4) Wheeling costs. Hub operators charge a wheeling cost for
transporting gas from one pipeline to either the same or another
pipeline through a market center or hub. A hub is a connected manifold
of pipelines through which a series of incoming pipelines are
interconnected to a series of outgoing pipelines.
(5) Gas Research Institute (GRI) fees. The GRI conducts research,
development, and commercialization programs 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.
[[Page 99]]
(3) Penalties you incur as shipper. These penalties include, but are
not limited to the following:
(i) Over-delivery cash-out penalties. This includes the difference
between the price the pipeline pays you for over-delivered volumes
outside the tolerances and the price you receive for over-delivered
volumes within tolerances.
(ii) Scheduling penalties. This includes penalties you incur for
differences between daily volumes delivered into the pipeline and
volumes scheduled or nominated at a receipt or delivery point.
(iii) Imbalance penalties. This includes penalties you incur
(generally on a monthly basis) for differences between volumes delivered
into the pipeline and volumes scheduled or nominated at a receipt or
delivery point.
(iv) Operational penalties. This includes fees you incur for
violation of the pipeline's curtailment or operational orders issued to
protect the operational integrity of the pipeline.
(4) Intra-hub transfer fees. These are fees you pay to hub operators
for administrative services (e.g., title transfer tracking) necessary to
account for the sale of gas within a hub.
(5) Other nonallowable costs. Any cost you incur for services you
are required to provide at no cost to the lessor.
(h) Other transportation cost determinations. You must follow the
provisions of this section to determine transportation costs when
establishing value using either a net-back valuation procedure or any
other procedure that allows deduction of actual transportation costs.
Processing Allowances
Sec. 206.179 What general requirements regarding processing allowances
apply to me?
(a) When you value any gas plant product under Sec. 206.174, you may
deduct from value the reasonable actual costs of processing.
(b) You must allocate processing costs among the gas plant products.
You must determine a separate processing allowance for each gas plant
product and processing plant relationship. Natural gas liquids are
considered as one product.
(c) The processing allowance deduction based on an individual
product may not exceed 66 2/3 percent of the value of each gas plant
product determined under Sec. 206.174. Before you calculate the 66 2/3
percent limit, you must first reduce the value for any transportation
allowances related to post-processing transportation authorized under
Sec. 206.177.
(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
[[Page 100]]
218.54. Alternatively, you may be entitled to a credit, but you will not
receive any interest on your overpayment.
Sec. 206.180 How do I determine an actual processing allowance?
(a) Determining a processing allowance if you have an arms's-length
processing contract. (1) This paragraph explains how you determine an
allowance under an arm's-length processing contract.
(i) The processing allowance is the reasonable actual costs you
incur to process the gas under that contract. Paragraphs (a)(1)(ii) and
(iii) of this section provide a limited exception. You have the burden
of demonstrating that your contract is arm's-length. You are required to
submit to MMS a copy of your arm's-length contract(s) and all subsequent
amendments to the contract(s) within 2 months of the date MMS receives
your first report that deducts the allowance on the Form MMS-2014.
(ii) When MMS conducts reviews and audits, we will examine whether
the contract reflects more than the consideration actually transferred
either directly or indirectly from you to the processor for the
processing. If the contract reflects more than the total consideration,
then MMS may require that the processing allowance be determined under
paragraph (b) of this section.
(iii) If MMS determines that the consideration paid under an arm's-
length processing contract does not reflect the value of the processing
because of misconduct by or between the contracting parties, or because
you otherwise have breached your duty to the lessor to market the
production for the mutual benefit of you and the lessor, then MMS will
require that the processing allowance be determined under paragraph (b)
of this section. In these circumstances, MMS will notify you and give
you an opportunity to provide written information justifying your
processing costs.
(2) If your arm's-length processing contract includes more than one
gas plant product and the processing costs attributable to each product
can be determined from the contract, then the processing costs for each
gas plant product must be determined in accordance with the contract.
You may not take an allowance for the costs of processing lease
production that is not royalty-bearing.
(3) If your arm's-length processing contract includes more than one
gas plant product and the processing costs attributable to each product
cannot be determined from the contract, you must propose an allocation
procedure to MMS. You may use your proposed 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.
[[Page 101]]
(2) The processing allowance for non-arm's-length or no-contract
situations is based upon your actual costs for processing during the
reporting period. Allowable costs include operating and maintenance
expenses, overhead, and either depreciation and a return on
undepreciated capital investment (in accordance with paragraph
(b)(2)(iv)(A) of this section), or a cost equal to the initial
depreciable investment in the processing plant multiplied by a rate of
return in accordance with paragraph (b)(2)(iv)(B) of this section.
Allowable capital costs are generally those costs for depreciable fixed
assets (including costs of delivery and installation of capital
equipment) that are an integral part of the processing plant.
(i) Allowable operating expenses include operations supervision and
engineering, operations labor, fuel, utilities, materials, ad valorem
property taxes, rent, supplies, and any other directly allocable and
attributable operating expense that the lessee can document.
(ii) Allowable maintenance expenses include maintenance of the
processing plant, maintenance of equipment, maintenance labor, and other
directly allocable and attributable maintenance expenses that you can
document.
(iii) Overhead directly attributable and allocable to the operation
and maintenance of the processing plant is an allowable expense. State
and Federal income taxes and severance taxes, including royalties, are
not allowable expenses.
(iv) You may use either depreciation with a return on undepreciable
capital investment or a return on depreciable capital investment. After
you elect to use either method for a processing plant, you may not later
elect to change to the other alternative without MMS approval.
(A) To compute depreciation, you may elect to use either a straight-
line depreciation method based on the life of equipment or on the life
of the reserves that the processing plant services, or a unit-of-
production method. Once you make an election, you may not change methods
without MMS approval. A change in ownership of a processing plant will
not alter the depreciation schedule that the original processor/lessee
established for purposes of the allowance calculation. However, for
processing plants you or your affiliate purchase that do not have a
previously claimed MMS depreciation schedule, you may treat the
processing plant as a newly installed facility for depreciation
purposes. A processing plant may be depreciated only once, regardless of
whether there is a change in ownership. Equipment may not be depreciated
below a reasonable salvage value. To compute a return on undepreciated
capital investment, you must multiply the undepreciable capital
investment in the processing plant by the rate of return determined
under paragraph (b)(2)(v) of this section.
(B) To compute a return on depreciable capital investment, you must
multiply the initial capital investment in the processing plant by the
rate of return determined under paragraph (b)(2)(v) of this section. No
allowance will be provided for depreciation. This alternative will apply
only to plants first placed in service after March 1, 1988.
(v) The rate of return is the industrial rate associated with
Standard and Poor's BBB rating. The rate of return is the monthly
average rate as published in Standard and Poor's Bond Guide for the
first month for which the allowance is applicable. The rate must be
redetermined at the beginning of each subsequent calendar year.
(3) Your processing allowance under this paragraph (b) must be
determined based upon a calendar year or other period if you and MMS
agree to an alternative.
(4) The processing allowance for each gas plant product must be
determined based on your reasonable and actual cost of processing the
gas. You must base your allocation of costs to each gas plant product
upon generally accepted accounting principles. You may not take an
allowance for the costs of processing lease production that is not
royalty-bearing.
(c) Reporting your processing allowance. (1) If MMS requests, you
must submit all data used to determine your processing allowance. The
data must be provided within a reasonable period of time, as MMS
determines.
[[Page 102]]
(2) You must report gas processing allowances as a separate line
item on the Form MMS-2014. MMS may approve a different reporting
procedure for allottee leases, and with lessor approval on tribal
leases.
(d) Adjusting incorrect processing allowances. If for any month the
gas processing allowance you are entitled to is less than the amount you
took on Form MMS-2014, you are required to pay additional royalties,
plus interest computed under 30 CFR 218.54 from the first day of the
first month you deducted a processing allowance until the date you pay
the royalties due. If the processing allowance you are entitled is
greater than the amount you took on Form MMS-2014, you are entitled to a
credit. However, no interest will be paid on the overpayment.
(e) Other processing cost determinations. You must follow the
provisions of this section to determine processing costs when
establishing value using either a net-back valuation procedure or any
other procedure that requires deduction of actual processing costs.
Sec. 206.181 How do I establish processing costs for dual accounting
purposes when I do not process the gas?
Where accounting for comparison (dual accounting) is required for
gas production from a lease but neither you nor someone acting on your
behalf processes the gas, and you have elected to perform actual dual
accounting under Sec. 206.176, you must use the first applicable of the
following methods to establish processing costs for dual accounting
purposes:
(a) The average of the costs established in your current arm's-
length processing agreements for gas from the lease, provided that some
gas has previously been processed under these agreements.
(b) The average of the costs established in your current arm's-
length processing agreements for gas from the lease, provided that the
agreements are in effect for plants to which the lease is physically
connected and under which gas from other leases in the field or area is
being or has been processed.
(c) A proposed comparable processing fee submitted to either the
tribe and MMS (for tribal leases) or MMS (for allotted leases) with your
supporting documentation submitted to MMS. If MMS does not take action
on your proposal within 120 days, the proposal will be deemed to be
denied and subject to appeal to the MMS Director under 30 CFR part 290.
(d) Processing costs based on the regulations in Secs. 206.179 and
206.180.
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
[[Page 103]]
of delivery remote from both the lease and mine or wash plant.
Area means a geographic region in which coal has similar quality and
economic characteristics. Area boundaries are not officially designated
and the areas are not necessarily named.
Arm's-length contract means a contract or agreement that has been
arrived at in the marketplace between independent, nonaffiliated persons
with opposing economic interests regarding that contract. For purposes
of this subpart, two persons are affiliated if one person controls, is
controlled by, or is under common control with another person. For
purposes of this subpart, based on the instruments of ownership of the
voting securities of an entity, or based on other forms of ownership:
(a) Ownership in excess of 50 percent constitutes control;
(b) Ownership of 10 through 50 percent creates a presumption of
control; and
(c) Ownership of less than 10 percent creates a presumption of
noncontrol which MMS may rebut if it demonstrates actual or legal
control, including the existence of interlocking directorates.
Notwithstanding any other provisions of this subpart, contracts between
relatives, either by blood or by marriage, are not arm's-length
contracts. The MMS may require the lessee to certify ownership control.
To be considered arm's-length for any production month, a contract must
meet the requirements of this definition for that production month as
well as when the contract was executed.
Audit means a review, conducted in accordance with generally
accepted accounting and auditing standards, of royalty payment
compliance activities of lessees or other interest holders who pay
royalties, rents, or bonuses on Federal leases.
BLM means the Bureau of Land Management of the Department of the
Interior.
Coal means coal of all ranks from lignite through anthracite.
Coal washing means any treatment to remove impurities from coal.
Coal washing may include, but is not limited to, operations such as
flotation, air, water, or heavy media separation; drying; and related
handling (or combination thereof).
Contract means any oral or written agreement, including amendments
or revisions thereto, between two or more persons and enforceable by law
that with due consideration creates an obligation.
Gross proceeds (for royalty payment purposes) means the total monies
and other consideration accruing to a coal lessee for the production and
disposition of the coal produced. Gross proceeds includes, but is not
limited to, payments to the lessee for certain services such as
crushing, sizing, screening, storing, mixing, loading, treatment with
substances including chemicals or oils, and other preparation of the
coal to the extent that the lessee is obligated to perform them at no
cost to the Federal Government. Gross proceeds, as applied to coal, also
includes but is not limited to reimbursements for royalties, taxes or
fees, and other reimbursements. Tax reimbursements are part of the gross
proceeds accruing to a lessee even though the Federal royalty interest
may be exempt from taxation. Monies and other consideration, including
the forms of consideration identified in this paragraph, to which a
lessee is contractually or legally entitled but which it does not seek
to collect through reasonable efforts are also part of gross proceeds.
Lease means any contract, profit-share arrangement, joint venture,
or other agreement issued or approved by the United States for a Federal
coal resource under a mineral leasing law that authorizes exploration
for, development or extraction of, or removal of coal--or the land
covered by that authorization, whichever is required by the context.
Lessee means any person to whom the United States issues a lease,
and any person who has been assigned an obligation to make royalty or
other payments required by the lease. This includes any person who has
an interest in a lease as well as an operator or payor who has no
interest in the lease but who has assumed the royalty payment
responsibility.
Like-quality coal means coal that has similar chemical and physical
characteristics.
[[Page 104]]
Marketable condition means coal that is sufficiently free from
impurities and otherwise in a condition that it will be accepted by a
purchaser under a sales contract typical for that area.
Mine means an underground or surface excavation or series of
excavations and the surface or underground support facilities that
contribute directly or indirectly to mining, production, preparation,
and handling of lease products.
Net-back method means a method for calculating market value of coal
at the lease or mine. Under this method, costs of transportation,
washing, handling, etc., are deducted from the ultimate proceeds
received for the coal at the first point at which reasonable values for
the coal may be determined by a sale pursuant to an arm's-length
contract or by comparison to other sales of coal, to ascertain value at
the mine.
Net output means the quantity of washed coal that a washing plant
produces.
Netting is the deduction of an allowance from the sales value by
reporting a one line net sales value, instead of correctly reporting the
deduction as a separate line item on the Form MMS-4430.
Person means by individual, firm, corporation, association,
partnership, consortium, or joint venture.
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
[[Page 105]]
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 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 Secs. 206.258 through 206.262 of this
subpart, or any allowance authorized by Sec. 206.265 of this subpart.
The royalty due shall be equal to the value for royalty purposes
multiplied by the royalty rate in the lease.
(b)(1) The value of coal that is sold pursuant to an arm's-length
contract shall be the gross proceeds accruing to the lessee, except as
provided in paragraphs (b)(2), (b)(3), and (b)(5) of this section. The
lessee shall have the burden of demonstrating that its contract is
arm's-length. The value which the lessee reports, for royalty purposes,
is subject to monitoring, review, and audit.
(2) In conducting reviews and audits, MMS will examine whether the
contract reflects the total consideration actually transferred either
directly or indirectly from the buyer to the seller for the coal
produced. If the contract does not reflect the total consideration, then
the MMS may require that the coal sold pursuant to that contract be
valued in accordance with paragraph (c) of this section. Value may not
be based on less than the gross proceeds accruing to the lessee for the
coal production, including the additional consideration.
(3) If the MMS determines that the gross proceeds accruing to the
lessee pursuant to an arm's-length contract
[[Page 106]]
do not reflect the reasonable value of the production because of
misconduct by or between the contracting parties, or because the lessee
otherwise has breached its duty to the lessor to market the production
for the mutual benefit of the lessee and the lessor, then MMS shall
require that the coal production be valued pursuant to paragraph (c)(2)
(ii), (iii), (iv), or (v) of this section, and in accordance with the
notification requirements of paragraph (d)(3) of this section. When MMS
determines that the value may be unreasonable, MMS will notify the
lessee and give the lessee an opportunity to provide written information
justifying the lessee's reported coal value.
(4) The MMS may require a lessee to certify that its arm's-length
contract provisions include all of the consideration to be paid by the
buyer, either directly or indirectly, for the coal production.
(5) The value of production for royalty purposes shall not include
payments received by the lessee pursuant to a contract which the lessee
demonstrates, to MMS's satisfaction, were not part of the total
consideration paid for the purchase of coal production.
(c)(1) The value of coal from leases subject to this section and
which is not sold pursuant to an arm's-length contract shall be
determined in accordance with this section.
(2) If the value of the coal cannot be determined pursuant to
paragraph (b) of this section, then the value shall be determined
through application of other valuation criteria. The criteria shall be
considered in the following order, and the value shall be based upon the
first applicable criterion:
(i) The gross proceeds accruing to the lessee pursuant to a sale
under its non-arm's-length contract (or other disposition of produced
coal by other than an arm's-length contract), provided that those gross
proceeds are within the range of the gross proceeds derived from, or
paid under, comparable arm's-length contracts between buyers and sellers
neither of whom is affiliated with the lessee for sales, purchases, or
other dispositions of like-quality coal produced in the area. In
evaluating the comparability of arm's-length contracts for the purposes
of these regulations, the following factors shall be considered: Price,
time of execution, duration, market or markets served, terms, quality of
coal, quantity, and such other factors as may be appropriate to reflect
the value of the coal;
(ii) Prices reported for that coal to a public utility commission;
(iii) Prices reported for that coal to the Energy Information
Administration of the Department of Energy;
(iv) Other relevant matters including, but not limited to, published
or publicly available spot market prices, or information submitted by
the lessee concerning circumstances unique to a particular lease
operation or the saleability of certain types of coal;
(v) If a reasonable value cannot be determined using paragraphs
(c)(2) (i), (ii), (iii), or (iv) of this section, then a net-back method
or any other reasonable method shall be used to determine value.
(3) When the value of coal is determined pursuant to paragraph
(c)(2) of this section, that value determination shall be consistent
with the provisions contained in paragraph (b)(5) of this section.
(d)(1) Where the value is determined pursuant to paragraph (c) of
this section, that value does not require MMS's prior approval. However,
the lessee shall retain all data relevant to the determination of
royalty value. Such data shall be subject to review and audit, and MMS
will direct a lessee to use a different value if it determines that the
reported value is inconsistent with the requirements of these
regulations.
(2) Any Federal lessee will make available upon request to the
authorized MMS or State representatives, to the Inspector General of the
Department of the Interior or other persons authorized to receive such
information, arm's-length sales value and sales quantity data for like-
quality coal sold, purchased, or otherwise obtained by the lessee from
the area.
(3) A lessee shall notify MMS if it has determined value pursuant to
paragraphs (c)(2) (ii), (iii), (iv), or (v) of this section. The
notification shall be by letter to the Associate Director for Minerals
Revenue Management of his/her designee. The letter shall identify
[[Page 107]]
the valuation method to be used and contain a brief description of the
procedure to be followed. The notification required by this section is a
one-time notification due no later than the month the lessee first
reports royalties on the Form MMS-4430 using a valuation method
authorized by paragraphs (c)(2) (ii), (iii), (iv), or (v) of this
section, and each time there is a change in a method under paragraphs
(c)(2) (iv) or (v) of this section.
(e) If MMS determines that a lessee has not properly determined
value, the lessee shall be liable for the difference, if any, between
royalty payments made based upon the value it has used and the royalty
payments that are due based upon the value established by MMS. The
lessee shall also be liable for interest computed pursuant to 30 CFR
218.202. If the lessee is entitled to a credit, MMS will provide
instructions for the taking of that credit.
(f) The lessee may request a value determination from MMS. In that
event, the lessee shall propose to MMS a value determination method, and
may use that method in determining value for royalty purposes until MMS
issues its decision. The lessee shall submit all available data relevant
to its proposal. The MMS shall expeditiously determine the value based
upon the lessee's proposal and any additional information MMS deems
necessary. That determination shall remain effective for the period
stated therein. After MMS issues its determination, the lessee shall
make the adjustments in accordance with paragraph (e) of this section.
(g) Notwithstanding any other provisions of this section, under no
circumstances shall the value for royalty purposes be less than the
gross proceeds accruing to the lessee for the disposition of produced
coal less applicable provisions of paragraph (b)(5) of this section and
less applicable allowances determined pursuant to Secs. 206.258 through
206.262 and Sec. 206.265 of this subpart.
(h) The lessee is required to place coal in marketable condition at
no cost to the Federal Government. Where the value established under
this section is 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
[[Page 108]]
regulation of the Department of the Interior, 43 CFR part 2.
[54 FR 1523, Jan. 13, 1989, as amended at 55 FR 35433, Aug. 30, 1990; 57
FR 52720, Nov. 5, 1992; 61 FR 5480, Feb. 12, 1996; 66 FR 45769, Aug. 30,
2001]
Sec. 206.258 Washing allowances--general.
(a) For ad valorem leases subject to Sec. 206.257 of this subpart,
MMS shall, as authorized by this section, allow a deduction in
determining value for royalty purposes for the reasonable, actual costs
incurred to wash coal, unless the value determined pursuant to
Sec. 206.257 of this subpart was based upon like-quality unwashed coal.
Under no circumstances will the authorized washing allowance and the
transportation allowance reduce the value for royalty purposes to zero.
(b) If MMS determines that a lessee has improperly determined a
washing allowance authorized by this section, then the lessee shall be
liable for any additional royalties, plus interest determined in
accordance with 30 CFR 218.202, or shall be entitled to a credit without
interest.
(c) Lessees shall not disproportionately allocate washing costs to
Federal leases.
(d) No cost normally associated with mining operations and which are
necessary for placing coal in marketable condition shall be allowed as a
cost of washing.
(e) Coal washing costs shall only be recognized as allowances when
the washed coal is sold and royalties are reported and paid.
[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5480, Feb. 12, 1996; 64
FR 43288, Aug. 10, 1999]
Sec. 206.259 Determination of washing allowances.
(a) Arm's-length contracts. (1) For washing costs incurred by a
lessee under an arm's-length contract, the washing allowance shall be
the reasonable actual costs incurred by the lessee for washing the coal
under that contract, subject to monitoring, review, audit, and possible
future adjustment. 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
[[Page 109]]
necessary or appropriate, MMS may direct a lessee to modify its
estimated or actual washing allowance.
(2) The washing allowance for non-arm's-length or no contract
situations shall be based upon the lessee's actual costs for washing
during the reported period, including operating and maintenance
expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph (b)(2)(iv)
(A) of this section, or a cost equal to the depreciable investment in
the wash plant multiplied by the rate of return in accordance with
paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are
generally those for depreciable fixed assets (including costs of
delivery and installation of capital equipment) which are an integral
part of the wash plant.
(i) Allowable operating expenses include: Operations supervision and
engineering; operations labor; fuel; utilities; materials; ad valorem
property taxes, rent; supplies; and any other directly allocable and
attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the wash
plant; maintenance of equipment; maintenance labor; and other directly
allocable and attributable maintenance expenses which the lessee can
document.
(iii) Overhead attributable and allocable to the operation and
maintenance of the wash plant is an allowable expense. State and Federal
income taxes and severance taxes, including royalities, are not
allowable expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this
section. After a lessee has elected to use either method for a wash
plant, the lessee may not later elect to change to the other alternative
without approval of the MMS.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the wash plant services, whichever is
appropriate, or a unit of production method. After an election is made,
the lessee may not change methods without MMS approval. A change in
ownership of a wash plant shall not alter the depreciation schedule
established by the original operator/lessee for purposes of the
allowance calculation. With or without a change in ownership, a wash
plant shall be depreciated only once. Equipment shall not be depreciated
below a reasonable salvage value.
(B) The MMS shall allow as a cost an amount equal to the allowable
capital investment in the wash plant multiplied by the rate of return
determined pursuant to paragraph (b)(2)(v) of this section. No allowance
shall be provided for depreciation. This alternative shall apply only to
plants first placed in service or acquired after March 1, 1989.
(v) The rate of return must be the industrial rate associated with
Standard and Poor's BBB rating. The rate of return must be the monthly
average rate as published in Standard and Poor's Bond Guide for the
first month for which the allowance is applicable. The rate must be
redetermined at the beginning of each subsequent calendar year.
(3) The washing allowance for coal shall be determined based on the
lessee's reasonable and actual cost of washing the coal. The lessee may
not take an allowance for the costs of washing lease production that is
not royalty bearing.
(c) Reporting requirements--(1) Arm's-length contracts. (i) The
lessee must notify MMS of an allowance based on incurred costs by using
a separate line entry on the Form MMS-4430.
(ii) The MMS may require that a lessee submit arm's-length washing
contracts and related documents. Documents shall be submitted within a
reasonable time, as determined by MMS.
(2) Non-arm's-length or no contract. (i) The lessee must notify MMS
of an allowance based on the incurred costs by using a separate line
entry on the Form MMS-4430.
(ii) For new washing facilities or arrangements, the lessee's
initial washing deduction shall include estimates of the allowable coal
washing costs for the applicable period. Cost estimates shall be based
upon the most recently available operations data for the washing system
or, if such data are not
[[Page 110]]
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 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.
[[Page 111]]
(2) For coal that is not washed at a wash plant, the transportation
allowance shall be authorized for the total production which is
transported. Transportation allowances shall be expressed as a cost per
ton of coal transported.
(3) Transportation costs shall only be recognized as allowances when
the transported coal is sold and royalties are reported and paid.
(d) If, after a review and/or audit, MMS determines that a lessee
has improperly determined a transportation allowance authorized by this
section, then the lessee shall pay any additional royalties, plus
interest, determined in accordance with 30 CFR 218.202, or shall be
entitled to a credit, without interest.
(e) Lessees shall not disproportionately allocate transportation
costs to Federal leases.
[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5481, Feb. 12, 1996; 64
FR 43288, Aug. 10, 1999]
Sec. 206.262 Determination of transportation allowances.
(a) Arm's-length contracts. (1) For transportation costs incurred by
a lessee pursuant to an arm's-length contract, the transportation
allowance shall be the reasonable, actual costs incurred by the lessee
for transporting the coal under that contract, subject to monitoring,
review, audit, and possible future adjustment. The lessee shall have the
burden of demonstrating that its contract is arm's-length. The lessee
must claim a transportation allowance by reporting it as a separate line
entry on the Form MMS-4430.
(2) In conducting reviews and audits, MMS will examine whether the
contract reflects more than the consideration actually transferred
either directly or indirectly from the lessee to the transporter for the
transportation. If the contract reflects more than the total
consideration paid, then the MMS may require that the transportation
allowance be determined in accordance with paragraph (b) of this
section.
(3) If the MMS determines that the consideration paid pursuant to an
arm's-length transportation contract 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
[[Page 112]]
an integral part of the transportation system.
(i) Allowable operating expenses include: Operations supervision and
engineering; operations labor; fuel; utilities; materials; ad valorem
property taxes; rent; supplies; and any other directly allocable and
attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the
transportation system; maintenance of equipment; maintenance labor; and
other directly allocable and attributable maintenance expenses which the
lessee can document.
(iii) Overhead attributable and allocable to the operation and
maintenance of the transportation system is an allowable expense. State
and Federal income taxes and severance taxes and other fees, including
royalties, are not allowable expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or paragraph
(b)(2)(iv)(B) of this section. After a lessee has elected to use either
method for a transportation system, the lessee may not later elect to
change to the other alternative without approval of the MMS.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the transportation system services,
whichever is appropriate, or a unit of production method. After an
election is made, the lessee may not change methods without MMS
approval. A change in ownership of a transportation system shall not
alter the depreciation schedule established by the original transporter/
lessee for purposes of the allowance calculation. With or without a
change in ownership, a transportation system shall be depreciated only
once. Equipment shall not be depreciated below a reasonable salvage
value.
(B) The MMS shall allow as a cost an amount equal to the allowable
capital investment in the transportation system multiplied by the rate
of return determined pursuant to paragraph (b)(2)(B)(v) of this section.
No allowance shall be provided for depreciation. This alternative shall
apply only to transportation facilities first placed in service or
acquired after March 1, 1989.
(v) The rate of return must be the industrial rate associated with
Standard and Poor's BBB rating. The rate of return must be the monthly
average rate as published in Standard and Poor's Bond Guide for the
first month for which the allowance is applicable. The rate must be
redetermined at the beginning of each subsequent calendar year.
(3) A lessee may apply to MMS for exception from the requirement
that it compute actual costs in accordance with paragraphs (b)(1) and
(b)(2) of this section. MMS will grant the exception only if the lessee
has a rate for the transportation approved by a Federal agency or by a
State regulatory agency (for Federal leases). MMS shall deny the
exception request if it determines that the rate is excessive as
compared to arm's-length transportation charges by systems, owned by the
lessee or others, providing similar transportation services in that
area. If there are no arm's-length transportation charges, MMS shall
deny the exception request if:
(i) No Federal or State regulatory agency costs analysis exists and
the Federal or State regulatory agency, as applicable, has declined to
investigate under MMS timely objections upon filing; and
(ii) The rate significantly exceeds the lessee's actual costs for
transportation as determined under this section.
(c) Reporting requirements--(1) Arm's-length contracts. (i) The
lessee must notify MMS of an allowance based on incurred costs by using
a separate line entry on the Form MMS-4430.
(ii) The MMS may require that a lessee submit arm's-length
transportation contracts, production agreements, operating agreements,
and related documents. Documents shall be submitted within a reasonable
time, as determined by MMS.
(2) Non-arm's-length or no contract-- (i) The lessee must notify MMS
of an allowance based on the incurred costs by using a separate line
entry on Form MMS-4430.
(ii) For new transportation facilities or arrangements, the lessee's
initial deduction shall include estimates of the
[[Page 113]]
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.
(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.
[[Page 114]]
Subpart G--Other Solid Minerals
Sec. 206.301 Value basis for royalty computation.
(a) The gross value for royalty purposes shall be the sale or
contract unit price times the number of units sold, Provided, however,
That where the authorized officer determines:
(1) That a contract of sale or other business arrangement between
the lessee and a purchaser of some or all of the commodities produced
from the lease is not a bona fide transaction between independent
parties because it is based in whole or in part upon considerations
other than the value of the commodities, or
(2) That no bona fide sales price is received for some or all of
such commodities because the lessee is consuming them, the authorized
officer shall determine their gross value, taking into account: (i) All
prices received by the lessee in all bona fide transactions, (ii) Prices
paid for commodities of like quality produced from the same general
area, and (iii) Such other relevant factors as the authorized officer
may deem appropriate; and Provided further, That in a situation where an
estimated value is used, the authorized officer shall require the
payment of such additional royalties, or allow such credits or refunds
as may be necessary to adjust royalty payment to reflect the actual
gross value.
(b) The lessee is required to certify that the values reported for
royalty purposes are bona fide sales not involving considerations other
than the sale of the mineral, and he may be required by the authorized
officer to supply supporting information.
[43 FR 10341, Mar. 13, 1978. Redesignated at 48 FR 36588, Aug. 12, 1983,
and amended at 48 FR 44795, Sept. 30, 1983. Further redesignated at 51
FR 15212, Apr. 22, 1986. Redesignated at 53 FR 39461, Oct. 7, 1988]
Subpart H--Geothermal Resources
Source: 56 FR 57276, Nov. 8, 1991, unless otherwise noted.
Sec. 206.350 Purpose and scope.
(a) This subpart is applicable to all geothermal resources produced
from Federal geothermal leases issued pursuant to the Geothermal Steam
Act of 1970, as amended (30 U.S.C. 1001 et seq.). The purpose of this
subpart is to establish the value of geothermal production for royalty
purposes.
(b) All royalty payments made to MMS are subject to audit and
adjustment.
Sec. 206.351 Definitions.
For purposes of this subpart:
Arm's-length contract means a contract or agreement that has been
arrived at in the marketplace between independent, nonaffiliated persons
with opposing economic interests regarding that contract. For purposes
of this subpart, two persons are affiliated if one person controls, is
controlled by, or is under common control with, another person. For
purposes of this subpart, based on the instruments of ownership of the
voting securities of an entity, or based on other forms of ownership:
(1) Ownership in excess of 50 percent constitutes control;
(2) Ownership of 10 through 50 percent creates a rebuttable
presumption of control; and
(3) Ownership of less than 10 percent creates a presumption of
noncontrol which MMS may rebut if it demonstrates actual or legal
control, including the existence of interlocking directorates.
Notwithstanding any other provisions of this subpart, contracts between
relatives, either by blood or by marriage, are not arm's-length
contracts. The MMS may require the lessee to certify the claimed nature
of ownership control. To be considered arm's-length for any production
month, a contract must meet the requirements of this definition for the
production month as well as when the contract was executed.
Audit means a procedure having the same meaning and effect as that
described at 30 CFR part 217 for verifying royalty payment compliance
activities of lessees or other authorized persons who pay royalties,
rents, or bonuses on Federal geothermal leases.
Byproduct means:
[[Page 115]]
(1) Any mineral or minerals (exclusive of oil, hydrocarbon gas, and
helium) which are found in solution or developed in association with
geothermal fluids and which have a value of less than 75 per centum of
the value of the geothermal energy or are not, because of quantity,
quality, or technical difficulties in extraction and production, of
sufficient value to warrant extraction and production by themselves, and
(2) Commercially demineralized water.
Byproduct recovery facility means the facility or facilities at
which byproducts are placed in marketable condition.
Byproduct transportation allowance means an approved allowance for
the lessee's reasonable, actual costs, excluding gathering, incurred for
moving byproducts, including commercially demineralized water, to a
point of sale or point of delivery off the lease, unit area, or
communitized area.
Contract means any oral or written agreement, including amendments
or revisions thereto, between two or more persons and enforceable by law
that with due consideration creates an obligation.
Deduction means a subtraction used in the geothermal netback
procedure for determining the value of geothermal resources utilized by
the lessee to generate electricity. Transmission deduction means a
deduction for the lessee's reasonable actual costs incurred to wheel or
transmit the electricity from the lessee's powerplant to the purchaser's
delivery point. Generating deduction means a deduction for the lessee's
reasonable, actual costs of generating plant tailgate electricity.
Delivered electricity means the amount of electricity in
kilowatthours delivered to the purchaser.
Direct utilization means any process other than electrical
generation in which the thermal energy of the geothermal resource is
utilized, including, but not limited to, space heating, greenhouse
operations, and industrial or agricultural process heat.
Field means the land surface vertically projected over a subsurface
geothermal reservoir encompassing at least the outermost boundaries of
all geothermal accumulations known to be within that reservoir.
Geothermal fields are usually given names and their official boundaries
are often designated by regulatory agencies in the respective States in
which the fields are located.
Gathering means the efficient movement of lease production from the
wellhead to the point of utilization.
Geothermal netback procedure means the method of determining the
value of geothermal resources that are utilized in a lessee-owned
powerplant for the generation and sale of electricity by deducting the
lessee's reasonable, actual transmission and generating costs from the
sales price or value of the electricity to derive the value of the
geothermal resource at the powerplant inlet.
Geothermal resources means:
(1) All products of geothermal processes, including indigenous
steam, hot water, and hot brines;
(2) Steam and other gases, hot water, and hot brines resulting from
water, gas, or other fluids artificially introduced into geothermal
formations;
(3) Heat or other associated energy found in geothermal formations;
and
(4) Any byproducts.
Geothermal utilization facility means a powerplant or direct
utilization facility that utilizes the heat or other energy of the
geothermal resource.
Gross proceeds (for royalty purposes) means the total monies and
other consideration accruing to a geothermal lessee for any disposition
of geothermal resources, including total payments for the sale of
electricity generated by the lessee from lease-produced geothermal
resources. Gross proceeds includes, but is not limited to, payments to
the lessee for certain services such as effluent injection, field
operation and maintenance, drilling or workover of wells, and/or field
gathering to the extent that the lessee is obligated to perform them at
no cost to the Federal Government. Gross proceeds also includes, but is
not limited to, reimbursements for production taxes and other taxes. Tax
reimbursements are part of gross proceeds accruing to a lessee even
though the Federal royalty interest may be exempt from
[[Page 116]]
taxation. Monies and other consideration, including the forms of
consideration identified in this paragraph, to which a lessee is
contractually or legally entitled but which it does not seek to collect
through reasonable efforts are also part of gross proceeds.
Lease means a geothermal lease issued under authority of the
Geothermal Steam Act of 1970, as amended (30 U.S.C. 1001 et seq.),
unless the context indicates otherwise.
Lessee means any person to whom the United States issues a
geothermal lease, and any person who has been assigned an obligation to
make royalty or other payments required by the lease. This includes any
person who has an interest in a geothermal lease as well as an operator
or payor who has no interest in the lease but who has assumed the
royalty payment responsibility. This also includes any affiliate of the
lessee that utilizes the geothermal resource to generate electricity, in
a direct utilization process, or to recover byproducts, or any affiliate
that transports lease production.
Like-quality lease products means lease products that have similar
chemical, physical, and legal characteristics.
Marketable condition means lease products that are sufficiently free
from impurities and otherwise in a condition that they will be accepted
by a purchaser under a sales contract typical for the field.
Minimum royalty means the minimum amount of annual royalty as
specified in the lease or in applicable leasing regulations that the
lessee must pay after commencement of geothermal production in
commercial quantities.
No sales means the utilization or disposal of geothermal resources
without the benefit of a sale.
Person means any individual, firm, corporation, association,
partnership, consortium, or joint venture (when established as a
separate entity).
Plant tailgate electricity means the amount of electricity in
kilowatthours generated by the powerplant exclusive of plant parasitic
electricity, but inclusive of any electricity generated by the
powerplant and returned to the lease for lease operations. Plant
tailgate electricity should be measured at, or calculated for, the high
voltage side of the transformer in the plant switchyard.
Point of utilization means the powerplant or direct utilization
facility in which the geothermal resource (steam or hot water) is
utilized.
Reasonable alternative fuel means a conventional fuel (such as coal,
oil, gas, or wood) that would normally be used as a source of heat in
direct utilization operations.
Secretary means the Secretary of the Department of the Interior or
any person duly authorized to exercise the powers vested in that office.
Selling arrangement means the individually contracted arrangements
under which sales or dispositions of geothermal resources are made,
including sales or dispositions of byproducts and electricity sales
where the lessee generates electricity from lease geothermal production.
Spot market price means the price received under any sales
transaction when planned or actual deliveries span a short period of
time, usually not exceeding 1 year.
Wheeling means the transmission of electricity from a powerplant to
the point of delivery.
Sec. 206.352 Valuation standards for electrical generation.
(a) The value of geothermal resources produced from leases subject
to this subpart and used to generate electricity shall be determined
pursuant to this section.
(b)(1)(i) The value of geothermal resources that are sold pursuant
to an arm's-length contract shall be the gross proceeds accruing to the
lessee, except as provided in paragraphs (b)(1)(ii) and (b)(1)(iii) of
this section. The lessee shall have the burden of demonstrating that its
contract is arm's-length. The value that the lessee reports for royalty
purposes is subject to monitoring, review, and audit.
(ii) In conducting reviews and audits, MMS will examine whether the
contract reflects the total consideration actually transferred, either
directly or indirectly, from the buyer to the seller for the geothermal
resource. If the contract does not reflect the total consideration, MMS
may require that the
[[Page 117]]
geothermal resource sold pursuant to that contract be valued in
accordance with paragraph (d) of this section. Value shall not be less
than the gross proceeds accruing to the lessee, including any additional
consideration received.
(iii) If MMS determines that the gross proceeds accruing to the
lessee pursuant to an arm's-length contract do not reflect the
reasonable value of the production because of misconduct by or between
the contracting parties, or because the lessee otherwise has breached
its duty to the lessor to market the production for the mutual benefit
of the lessee and the lessor, MMS shall require the geothermal resource
to be valued pursuant to paragraph (d) of this section, and notification
provided to MMS in accordance with paragraph (e)(3) of this section. If
MMS determines that the value may be unreasonable, MMS will notify the
lessee and give the lessee an opportunity to provide written information
justifying the lessee's value.
(2) The MMS may require a lessee to certify that the provisions in
its arm's-length contract include all of the consideration to be paid by
the buyer, either directly or indirectly, for the geothermal resource.
(c)(1) The value of geothermal resources subject to this section
that are sold under a non-arm's-length contract shall be determined in
accordance with the first applicable of the following paragraphs:
(i) The gross proceeds accruing to the lessee pursuant to a sale
under its non-arm's-length contract provided that those gross proceeds
are not less than the gross proceeds derived from or paid under the
lowest-priced available comparable arm's-length contract for sales of
geothermal resources to the lessee-affiliate's same powerplant (the
``minimum value''). If the gross proceeds under the lessee's non-arm's-
length contract are less than the ``minimum value'' under available
comparable arm's-length contracts, or if there are no available
comparable arm's-length contracts, value will be determined by the
weighted average of the gross proceeds established under arm's-length
contracts for the sale of significant quantities of geothermal resources
to the same powerplant. Available contracts will mean contracts in the
possession of the lessee, the lessee's affiliate, or MMS. In evaluating
the comparability of arm's-length contracts for the purposes of these
regulations, the following factors shall be considered: Time of
execution, duration, terms, quality of the geothermal resource, volume,
dedication to the same powerplant, and other factors that may be
appropriate to reflect the value of the resource;
(ii) The value determined by the geothermal netback procedure. Under
the geothermal netback procedure, the lessee's reasonable actual costs
for the generation and transmission of electricity shall be deducted
from the lessee's gross proceeds received for the sale of electricity to
determine the value of the geothermal resource. Transmission deductions
shall be determined pursuant to Sec. 206.353 of this part. Generating
deductions shall be determined pursuant to Sec. 206.354 of this part; or
(iii) A value determined by any other reasonable valuation method
approved by MMS.
(2) Value determinations made pursuant to this paragraph are subject
to the notification requirements of paragraph (e) of this section.
(d)(1) The value of geothermal resources subject to this section
that are not subject to a sales transaction (``no sales'' geothermal
resources) but are instead utilized directly by the lessee in its own
powerplant for the generation and sale of electricity shall be
determined in accordance with the first applicable of the following
paragraphs:
(i) The weighted average of the gross proceeds established in arm's-
length contracts for the purchase of significant quantities of
geothermal resources to operate the lessee's same powerplant. In
evaluating the acceptability of arm's-length contracts, the following
factors shall be considered: Time of execution, duration, terms, volume,
quality of resource, and such other factors as may be appropriate to
reflect the value of the resource;
(ii) The value determined by the geothermal netback procedure. Under
the geothermal netback procedure, the lessee's reasonable actual costs
for the
[[Page 118]]
generation and transmission of electricity shall be deducted from the
lessee's gross proceeds received for the sale of electricity to
determine the value of the geothermal resource. Transmission deductions
shall be determined pursuant to Sec. 206.353 of this part. Generating
deductions shall be determined pursuant to Sec. 206.354 of this part; or
(iii) A value determined by any other reasonable valuation method
approved by MMS.
(2) Value determinations made pursuant to this paragraph are subject
to the notification requirements of paragraph (e) of this section.
(e)(1) Pursuant to subpart H of 30 CFR part 212, the lessee shall
retain all data relevant to the determination of royalty value,
particularly where the value is determined pursuant to paragraph (c) or
(d) of this section. Such data shall be subject to review and audit, and
MMS will direct a lessee to use a different value if it determines that
the reported value is inconsistent with the requirements of these
regulations.
(2) Upon request, lessees shall make available to authorized MMS
representatives or to other authorized persons any and all contracts for
the sale or other disposition of the lease production; contracts for the
sale, generation, and/or transmission of electricity attributable to
lease production; and any arm's-length sales and other data for like-
quality production sold, purchased, or otherwise obtained by the lessee
from the field as may be necessary to support a value determination.
(3) A lessee shall notify MMS if it has determined value pursuant to
paragraph (c) or (d) of this section. The notification shall be by
letter to the MMS Associate Director for 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) or (d) of this section.
(f) If MMS determines that a lessee has not properly determined
value, the lessee shall pay the difference, if any, between royalty
payments made based upon the value it has used and the royalty payments
that are due based upon the value established by MMS. The lessee shall
also pay interest on that difference computed pursuant to 30 CFR
218.302. If the lessee is entitled to a credit, MMS will provide
instructions for the taking of that credit.
(g) The lessee may request a value determination from MMS. In that
event, the lessee shall propose to MMS a value determination method and
may use that method in determining value, for royalty purposes, until
MMS issues its decision. The lessee shall submit all available data
relevant to its proposal. The MMS shall expeditiously determine the
value based upon the lessee's proposal and any additional information
MMS deems necessary. In making a value determination, MMS may use any of
the valuation criteria consistent with this subpart. That determination
shall remain effective for the period stated therein. After MMS issues
its determination, the lessee shall make the adjustments in accordance
with paragraph (f) of this section.
(h) Notwithstanding any other provision of this section, under no
circumstances shall the value of production for royalty purposes be less
than the gross proceeds accruing to the lessee where geothermal
resources are directly sold.
(i) The lessee is required to place geothermal resources in
marketable condition and to deliver geothermal resources to the
powerplant at no cost to the Federal lessor. Where the value established
pursuant to this section is determined by a lessee's gross proceeds,
that value shall be increased to the extent that the gross proceeds have
been reduced because the purchaser, or any other person, is providing
certain services the cost of which ordinarily is the responsibility of
the lessee to place the geothermal resource in marketable condition or
deliver it to the powerplant.
(j) Value shall be based on the highest price a prudent lessee can
receive
[[Page 119]]
through legally enforceable claims under its contract. Absent contract
revision or amendment, if the lessee fails to take proper or timely
action to receive prices or benefits to which it is entitled, it must
pay royalty at a value based upon that obtainable price or benefit.
Contract revisions or amendments shall be in writing and signed by all
parties to the contract. If the lessee makes timely application for a
price increase or benefit allowed under its contract but the purchaser
refuses and the lessee takes reasonable measures, which are documented,
to force purchaser compliance, the lessee will owe no additional
royalties unless or until monies or consideration resulting from the
price increase or additional benefits are received. This paragraph shall
not be construed to permit a lessee to avoid its royalty payment
obligation in situations where a purchaser fails to pay, in whole or in
part or timely, for a quantity of geothermal resources.
(k) Notwithstanding any provision in these regulations to the
contrary, no review, reconciliation, monitoring, or other like process
that results in a redetermination by MMS of value under this section
shall be considered final or binding as against the Federal Government
or its beneficiaries until the audit period is formally closed.
(l) Certain information submitted to MMS to support value
determinations is exempted from disclosure by the Freedom of Information
Act, 5 U.S.C. 552, or other Federal law. Any data specified by law to be
privileged, confidential, or otherwise exempt will be maintained in a
confidential manner in accordance with applicable law and regulations.
All requests for information about determinations made under this
subpart are to be submitted in accordance with the Freedom of
Information Act regulations of the Department, 43 CFR part 2.
Sec. 206.353 Determination of transmission deductions.
(a) Where the value of geothermal energy is determined by the
geothermal netback procedure pursuant to paragraphs (c)(1)(ii) and
(d)(1)(ii) of Sec. 206.352 of this subpart, a transmission deduction
shall be subtracted from the lessee's gross proceeds received for the
sale of electricity to determine the plant tailgate value of the
electricity. The transmission deduction consists of either or both of
two components:
(1) Transmission line costs as determined pursuant to paragraph (b)
of this section, and
(2) Wheeling costs if the electricity is transmitted across a third-
party's transmission line under an arm's-length wheeling agreement.
Transmission deductions are subject to the limitation prescribed in
paragraph (c) of this section.
(b)(1) Transmission-line costs shall be based on the lessee's actual
costs associated with the construction and operation of a transmission
line for the purpose of transmitting electricity attributable and
allocable to the lessee's powerplant utilizing Federal geothermal
resources. The monthly transmission line cost component of the
transmission deduction is determined by multiplying the annual
transmission line cost rate (in dollars per kilowatthour) by the amount
of electricity delivered for the reporting month. The transmission line
cost rate shall be redetermined annually at the beginning of the same
month of the year in which the transmission line was placed into
service, the same month of the year in which the powerplant was placed
into service, or, at the lessee's option, at a time concurrent with the
beginning of the lessee's annual corporate accounting period; Provided,
however, the period selected must coincide with the same period chosen
for the generating deduction pursuant to Sec. 206.354(b)(1). After a
deduction period is chosen, the lessee may not later elect to use a
different deduction period without MMS approval.
(2) Allowable transmission-line costs include operating and
maintenance expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph
(b)(2)(iv)(A) of this section, or a cost equal to the capital investment
in the transmission line multiplied by a rate of return in accordance
[[Page 120]]
with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs
are generally those costs for depreciable assets, including costs of
delivery and installation of capital equipment, that are an integral
part of the transmission line. A return on capital invested in the
purchase of real estate for transmission facilities may be allowed
provided that the lessee demonstrates the necessity for such purchase,
the purchased land is not on a Federal geothermal lease, and MMS
approves the deduction; the rate of return shall be the same rate
determined in paragraph (b)(2)(v) of this section.
(i) Allowable operating expenses include operations supervision and
engineering, operations labor, materials, ad valorem property taxes,
rent, supplies, and any other directly allocable and attributable
operating expenses that the lessee can document.
(ii) Allowable maintenance expenses include maintenance of the
transmission line, maintenance of equipment, maintenance labor, and
other directly allocable and attributable maintenance expenses that the
lessee can document.
(iii) Overhead directly attributable and allocable to the operation
and maintenance of the transmission line is an allowable expense. State
and Federal income taxes and severance taxes and other fees, including
royalties, are not allowable expenses.
(iv) To compute costs associated with capital investment, a lessee
may use either depreciation with a return on undepreciated capital
investment, or a return on capital investment. After a lessee has
elected to use either method, the lessee may not later elect to change
to the other alternative without MMS approval.
(A) To compute depreciation, the lessee must use a straight-line
depreciation method based on the expected life of the geothermal
project, usually the term of the electricity sales contract or other
depreciation period acceptable to MMS. A change in ownership of a
transmission line shall not alter the depreciation schedule established
by the original lessee-owner for purposes of computing transmission line
costs. With or without a change in ownership, a transmission line shall
be depreciated only once. The rate of return used to compute the return
on undepreciated capital investment shall be determined pursuant to
paragraph (b)(2)(v) of this section.
(B) To compute a return on capital investment, the allowed cost
shall be the amount equal to the allowable capital investment in the
transmission line multiplied by the rate of return determined pursuant
to paragraph (b)(2)(v) of this section. No allowance shall be provided
for depreciation. This alternative shall apply only to transmission
lines first placed into service on or after March 1, 1988.
(v) The rate of return shall be 2 times Standard and Poor's
industrial BBB bond rate. The rate of return shall be 2 times the
monthly average rate as published in Standard and Poor's Bond Guide for
the first month of the annual deduction period and shall be effective
during the following deduction period. The rate shall be redetermined
annually at the beginning of the same month beginning the annual
deduction period chosen pursuant to paragraph (b)(1) of this section.
(3) Transmission-line cost rates, determined annually, are computed
by dividing the sum of the operating, maintenance, overhead, and capital
costs by the annual amount of delivered electricity.
(4) For new transmission lines, the lessee's costs for the first
deduction period shall be based on estimated expenses (including
overhead) for operating and maintaining the transmission line. For
subsequent deduction periods, the transmission line costs shall be
estimated based on the lessee's actual operating and maintenance
expenses for the previous period adjusted for decreases or increases
that the lessee knows will affect the deduction in the current period.
(c) Under no circumstances shall the transmission deduction plus the
generating deduction determined pursuant to Sec. 206.354 of this subpart
reduce the royalty value of the geothermal resource to zero.
(d)(1) If the actual transmission deduction determined at the end of
the annual reporting period is less than the amount the lessee estimated
and used
[[Page 121]]
in the netback procedure during the reporting period, the lessee shall
be required to pay additional royalties retroactive to the first month
of the reporting period, plus interest computed pursuant to 30 CFR
218.302. If the actual transmission deduction is greater than the amount
applied in the netback calculation, the lessee shall be entitled to a
credit.
(2) Lessees must submit corrected Forms MMS-2014 to reflect
adjustments to royalty payments in accordance with MMS instructions.
(e)(1) All transmission deductions are subject to review, audit, and
adjustment. When necessary or appropriate, MMS may direct a lessee to
modify its estimated or actual transmission deduction and adjust royalty
values accordingly.
(2) Pursuant to subpart H of 30 CFR part 212, the lessee must
maintain all data and records supporting its transmission deduction,
including wheeling and other transmission-related agreements. These data
and records must be made available to MMS and other authorized personnel
upon request, and shall be maintained in a confidential manner in
accordance with applicable laws and regulations pursuant to Sec. 206.352
of this subpart.
(f) A one-time refund of royalties equal to the royalty amount of
actual dismantlement costs attributable to the transmission line that
are in excess of actual income attributable to the salvage of the
transmission line will be allowed at the completion of the dismantlement
and salvage operations.
Sec. 206.354 Determination of generating deductions.
(a) Where the value of geothermal energy is determined by the
geothermal netback procedure pursuant to paragraphs (c)(1)(ii) and
(d)(1)(ii) of Sec. 206.352 of this subpart, that value shall be
determined by deducting the lessee's reasonable actual costs incurred to
generate electricity from the plant tailgate value of the electricity
(usually the transmission-reduced value of the delivered electricity).
Generating deductions are subject to the limitation prescribed in
paragraph (c) of this section.
(b)(1) Generating costs shall be based on the lessee's actual annual
costs associated with the construction and operation of a geothermal
powerplant. The monthly generating deduction is determined by
multiplying the annual generating cost rate (in dollars per
kilowatthour) by the amount of plant tailgate electricity measured (or
computed) for the reporting month. The generating cost rate is
determined from the annual amount of plant tailgate electricity and must
be redetermined annually at the beginning of the same month of the year
in which the powerplant was placed into service or, at the lessee's
option, at a time concurrent with the beginning of the lessee's annual
corporate accounting period; Provided, however, the period selected must
coincide with the same period chosen for the transmission deduction
pursuant to Sec. 206.353(b)(1). After a deduction period is chosen, the
lessee may not later elect to use a different deduction period without
MMS approval.
(2) Allowable generating costs include operating and maintenance
expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph
(b)(2)(iv)(A) of this section, or a cost equal to the capital investment
in the powerplant multiplied by a rate of return in accordance with
paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are
generally those costs for depreciable assets, including costs of
delivery and installation of capital equipment, that are an integral
part of the powerplant or are required by the design specifications of
the power conversion cycle. A return on capital invested in the purchase
of real estate for a powerplant site may be allowed provided that the
lessee demonstrates the necessity for such purchase, the purchased land
is not on a Federal geothermal lease, and MMS approves the deduction;
the rate of return shall be the same rate determined in paragraph
(b)(2)(v) of this section. The costs of gathering systems and other
production-related facilities are not allowed.
(i) Allowable operating expenses include operations supervision and
engineering, operations labor, materials, ad
[[Page 122]]
valorem property taxes, rent, supplies, auxiliary fuel and/or utilities
used to operate the powerplant during down time, and any other directly
allocable and attributable operating expense that the lessee can
document.
(ii) Allowable maintenance expenses include maintenance of the
powerplant, maintenance of equipment, maintenance labor, and other
directly allocable and attributable maintenance expenses that the lessee
can document.
(iii) Overhead directly attributable and allocable to the operation
and maintenance of the powerplant is an allowable expense. State and
Federal income taxes and severance taxes, including royalties, are not
allowable expenses.
(iv) To compute costs associated with capital investment, a lessee
may use either depreciation with a return on undepreciated capital
investment, or a return on capital investment. After a lessee has
elected to use either method, the lessee may not later elect to change
to the other alternative without MMS approval.
(A) To compute depreciation, the lessee must use a straight-line
depreciation method based on the life of the geothermal project, usually
the term of the electricity sales contract or other depreciation period
acceptable to MMS. A change in ownership of a powerplant shall not alter
the depreciation schedule established by the original lessee-owner for
computing the generating costs. With or without a change in ownership, a
powerplant shall be depreciated only once. The rate of return used to
compute the return on undepreciated capital investment shall be
determined pursuant to paragraph (b)(2)(v) of this section.
(B) To compute a return on capital investment, the allowed cost
shall be the amount equal to the allowable capital investment in the
powerplant multiplied by the rate of return determined pursuant to
paragraph (b)(2)(v) of this section. No allowance shall be provided for
depreciation. This alternative shall apply only to powerplants first
placed into service on or after March 1, 1988.
(v) The rate of return shall be 2 times Standard and Poor's
industrial BBB bond rate. The rate of return shall be 2 times the
monthly average rate as published in Standard and Poor's Bond Guide for
the first month of the annual deduction period and shall be effective
during the following deduction period. The rate shall be redetermined
annually at the beginning of the same month beginning the annual
deduction period chosen pursuant to paragraph (b)(1) of this section.
(3) Generating cost rates, determined annually, shall be computed by
dividing the sum of the operating, maintenance, overhead, and capital
costs by the annual amount of plant tailgate electricity.
(4) For new powerplants, the lessee's generating costs for the first
deduction period shall be based on estimated expenses (including
overhead) for operating and maintaining the powerplant. For subsequent
deduction periods, the generating costs shall be estimated based on the
lessee's actual operating and maintenance expenses for the previous
period adjusted for decreases or increases that the lessee knows will
affect the deduction in the current period.
(c) Under no circumstances shall the generating deduction plus the
transmission deduction determined pursuant to Sec. 206.353 of this
subpart reduce the royalty value of the geothermal resource to zero.
(d)(1) If the actual generating deduction determined at the end of
the annual reporting period is less than the amount the lessee estimated
and used in the netback procedure during the reporting period, the
lessee shall be required to pay additional royalties retroactive to the
first month of the reporting period, plus interest computed pursuant to
30 CFR 218.302. If the actual generating deduction is greater than the
amount applied in the netback calculation, the lessee shall be entitled
to a credit.
(2) Lessees must submit corrected Forms MMS-2014 to reflect
adjustments to royalty payments in accordance with MMS instructions.
(e)(1) All generating deductions are subject to review, audit, and
adjustment. When necessary or appropriate, MMS may direct a lessee to
modify its
[[Page 123]]
estimated or actual generating deduction and adjust royalty values
accordingly.
(2) Pursuant to subpart H of 30 CFR part 212, the lessee must
maintain all data and records supporting its generating deduction. These
data and records must be made available to MMS and other authorized
personnel upon request, and shall be maintained in a confidential manner
in accordance with applicable laws and regulations pursuant to
Sec. 206.352 of this subpart.
(f) A one-time refund of royalties equal to the royalty amount of
actual dismantlement costs attributable to the powerplant that are in
excess of actual income attributable to the salvage of the powerplant
will be allowed at the completion of the dismantlement and salvage
operations.
Sec. 206.355 Valuation standards for direct utilization.
(a) The value of geothermal resources produced for leases subject to
this subpart and used in direct utilization processes shall be
determined pursuant to this section.
(b)(1)(i) The value of geothermal resources that are sold pursuant
to an arm's-length contract shall be the gross proceeds accruing to the
lessee, except as provided in paragraphs (b)(1)(ii) and (b)(1)(iii) of
this section. The lessee shall have the burden of demonstrating that its
contract is arm's-length. The value that the lessee reports for royalty
purposes is subject to monitoring, review, and audit.
(ii) In conducting these reviews and audits, MMS will examine
whether or not the contract reflects the total consideration actually
transferred either directly or indirectly from the buyer to the seller
for the geothermal resource. If the contract does not reflect the total
consideration, MMS may require that the geothermal resource sold
pursuant to that contract be valued in accordance with paragraph (d) of
this section. Value shall not be less than the gross proceeds accruing
to the lessee, including any additional consideration received.
(iii) If MMS determines that the gross proceeds accruing to the
lessee pursuant to an arm's-length contract do not reflect the
reasonable value of the geothermal resource because of misconduct by or
between the contracting parties, or because the lessee otherwise has
breached its duty to the lessor to market the production for the mutual
benefit of the lessee and the lessor, MMS shall require the geothermal
resource to be valued pursuant to paragraph (d) of this section and in
accordance with the notification requirements of paragraph (e) of this
section. When MMS determines that the value may be unreasonable, MMS
will notify the lessee and give the lessee an opportunity to provide
written information justifying the lessee's value.
(2) The MMS may require a lessee to certify that its arm's-length
contract provisions include all of the consideration to be paid by the
buyer, either directly or indirectly, for the geothermal resource.
(c)(1) The value of geothermal resources subject to this section
that are sold under a non-arm's-length contract shall be determined in
accordance with the first applicable of the following paragraphs:
(i) The gross proceeds accruing to the lessee pursuant to a sale
under its non-arm's-length contract provided that those gross proceeds
are not less than the gross proceeds derived from or paid under the
lowest-priced available comparable arm's-length contract for sales of
geothermal resources to the lessee-affiliate's same direct utilization
facility (the ``minimun value''). If the gross proceeds under the
lessee's non-arm's-length contract are less than the ``minimum value''
under available comparable arm's-length contracts, or if there are no
available comparable arm's-length contracts, value will be determined by
the weighted average of the gross proceeds established under arm's-
length contracts for the sale of significant quantities of geothermal
resources to the same direct utilization facility. Available contracts
will mean contracts in the possession of the lessee, the lessee's
affiliate, or MMS. In evaluating the comparability of arm's-length
contracts for the purposes of these regulations, the following factors
shall be considered: Time of execution, duration, terms, quality of the
geothermal resource, volume, dedication to the same direct utilization
facility,
[[Page 124]]
and other factors that may be appropriate to reflect the value of the
resource;
(ii) The equivalent value of the least expensive, reasonable
alternative energy source (fuel). The equivalent value of the least
expensive, reasonable alternative energy source shall be based on the
amount of thermal energy that would otherwise be used by the direct
utilization process in place of the geothermal resource. That amount of
thermal energy (in Btu's) displaced by the geothermal resource shall be
determined by the equation
thermal energy displaced =
[GRAPHIC] [TIFF OMITTED] TC15NO91.017
where hin is the enthalpy in Btu's/lb at the utilization
facility inlet (based on measured inlet temperature), hout is
the enthalpy in Btu's/lb at the facility outlet (based on measured
outlet temperature), density is in lbs/cu ft based on inlet temperature,
the factor 0.133681 (cu ft/gal) converts gallons to cubic feet, and
volume is the quantity of geothermal fluid in gallons produced at the
wellhead or measured at an approved point. The efficiency of the
alternative energy source shall be 0.7 for coal and 0.8 for oil, natural
gas, and other fuels derived from oil and natural gas, or an efficiency
factor proposed by the lessee and approved by MMS. The methods of
measuring resource parameters (temperature, volume, etc.) and the
frequency of computing and accumulating the amount of thermal energy
displaced shall be determined and approved by BLM; or
(iii) A value determined by any other reasonable valuation method
approved by MMS.
(2) Valuations made pursuant to this paragraph are subject to the
notification requirements of paragraph (e) of this section.
(d)(1) The value of geothermal resources subject to this section
that are not subject to a sales transaction but are instead used by the
lessee in its own direct utilization facility (``no sales'' geothermal
resources) shall be determined in accordance with the first applicable
of the following paragraphs:
(i) The weighted average of the gross proceeds established in arm's-
length contracts for the purchase of significant quantities of
geothermal resources to operate the lessee's same direct utilization
facility. In evaluating the acceptability of arm's-length contracts, the
following factors shall be considered: Time of execution, duration,
terms, volume, quality of resource, and such other factors as may be
appropriate to reflect the value of the resource;
(ii) The equivalent value of the least expensive, reasonable
alternative energy source (fuel). The equivalent value of the least
expensive, reasonable alternative energy source shall be based on the
amount of thermal energy that would otherwise be used by the direct
utilization process in place of the geothermal resource. That amount of
thermal energy (in Btu's) displaced by the geothermal resource shall be
determined by the equation
thermal energy displaced =
[GRAPHIC] [TIFF OMITTED] TC15NO91.018
where hin is the enthalpy in Btu's/lb at the utilization
facility inlet (based on measured inlet temperature), hout is
the enthalpy in Btu's/lb at the facility outlet (based on measured
outlet temperature), density is in lbs/cu ft based on inlet temperature,
the factor 0.133681 (cu ft/gal) converts gallons to cubic feet, and
volume is the quantity of geothermal fluid in gallons produced at the
wellhead or measured at an approved point. The efficiency of the
alternative energy source shall be 0.7 for coal and 0.8 for oil, natural
gas, and other fuels derived from oil and natural gas, or an efficiency
factor proposed by the lessee and approved by MMS. The methods of
measuring resource parameters (temperature, volume, etc.) and the
frequency of computing and accumulating the amount of thermal energy
displaced shall be determined and approved by BLM; or
(iii) A value determined by any other reasonable valuation method
approved by MMS.
[[Page 125]]
(2) Valuations made pursuant to this paragraph are subject to the
notification requirements of paragraph (e) of this section.
(e)(1) Pursuant to subpart H of 30 CFR part 212, the lessee shall
retain all data relevant to the determination of royalty value,
particularly where the value is determined pursuant to paragraph (c) or
(d) of this section. Such data shall be subject to review and audit, and
MMS will direct a lessee to use a different value if it determines that
the reported value is inconsistent with the requirements of these
regulations.
(2) Upon request, lessees shall make available to authorized MMS
representatives or to other authorized persons any and all contracts for
the sale or other disposition of the lease production, and any arm's-
length sales and other data for like-quality production sold, purchased,
or otherwise obtained by the lessee from the field as may be necessary
to support a value determination.
(3) A lessee shall notify MMS if it has determined value pursuant to
paragraph (c) or (d) of this section. The notification shall be by
letter to the MMS Associate Director for 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) or (d) of this section.
(f) If MMS determines that a lessee has not properly determined
value, the lessee shall pay the difference, if any, between royalty
payments made based upon the value it has used and the royalty payments
that are due based upon the value established by MMS. The lessee shall
also pay interest on that difference computed pursuant to 30 CFR
218.302. If the lessee is entitled to a credit, MMS will provide
instructions for the taking of that credit.
(g) The lessee may request a value determination from MMS. In that
event, the lessee shall propose to MMS a value determination method and
may use that method in determining value, for royalty purposes, until
MMS issues its decision. The lessee shall submit all available data
relevant to its proposal. The MMS shall expeditiously determine the
value based upon the lessee's proposal and any additional information
MMS deems necessary. In making a value determination, MMS may use any of
the valuation criteria consistent with this subpart. That determination
shall remain effective for the period stated therein. After MMS issues
its determination, the lessee shall make adjustments in accordance with
paragraph (f) of this section.
(h) Notwithstanding any other provision of this section, under no
circumstances shall the value of production, for royalty purposes, be
less than the gross proceeds accruing to the lessee where geothermal
energy is directly sold.
(i) The lessee is required to place geothermal resources in
marketable condition and to deliver geothermal resources to the direct
utilization facility at no cost to the Federal lessor. Where the value
established pursuant to this section is determined by a lessee's gross
proceeds, that value shall be increased to the extent that the gross
proceeds have been reduced because the purchaser, or any other person,
is providing certain services the cost of which ordinarily is the
responsibility of the lessee to place the geothermal resource in
marketable condition or to deliver it to the direct utilization
facility.
(j) Value shall be based on the highest price a prudent lessee can
receive through legally enforceable claims under its contract. Absent
contract revision or amendment, if the lessee fails to take proper or
timely action to receive prices or benefits to which it is entitled, it
must pay royalty at a value based upon that obtainable price or benefit.
Contract revisions or amendments shall be in writing and signed by all
parties to the contract. If the lessee makes timely application for a
price increase or benefit allowed under its contract but the purchaser
refuses and the lessee takes reasonable measures, which are documented,
to force purchaser compliance, the lessee shall owe
[[Page 126]]
no additional royalties unless or until monies or consideration
resulting from the price increase or additional benefits are received.
This paragraph shall not be construed to permit a lessee to avoid its
royalty payment obligation in situations where a purchaser fails to pay,
in whole or in part or timely, for a quantity of geothermal resources.
(k) Notwithstanding any provision in these regulations to the
contrary, no review, reconciliation, monitoring, or other like process
that results in a redetermination by MMS of value under this section
shall be considered final or binding against the Federal Government or
its beneficiaries until the audit period is formally closed.
(l) Certain information submitted to MMS to support value
determinations is exempted from disclosure by the Freedom of Information
Act, 5 U.S.C. 552, or other Federal law. Any data specified by law to be
privileged, confidential, or otherwise exempt will be maintained in a
confidential manner in accordance with applicable laws and regulations.
All requests for information about determinations made under this
subpart are to be submitted in accordance with the Freedom of
Information Act regulation of the Department, 43 CFR part 2.
[56 FR 57276, Nov. 8, 1991; 57 FR 12376, Apr. 9, 1992]
Sec. 206.356 Valuation standards for byproducts.
(a) The value of geothermal byproducts, including commercially
demineralized water, shall be determined pursuant to this section, less
applicable byproducts transportation allowances determined pursuant to
Secs. 206.357 and 206.358 of this subpart.
(b)(1)(i) The value of byproducts that are sold pursuant to an
arm's-length contract shall be the gross proceeds accruing to the
lessee, except as provided in paragraphs (b)(1)(ii) and (b)(1)(iii) of
this section. The lessee shall have the burden of demonstrating that its
contract is arm's-length. The value that the lessee reports for royalty
purposes is subject to monitoring, review, and audit.
(ii) In conducting reviews and audits, MMS will examine whether the
contract reflects the total consideration actually transferred, either
directly or indirectly, from the buyer to the seller for the byproducts.
If the contract does not reflect the total consideration, MMS may
require that the byproducts sold pursuant to that contract be valued in
accordance with paragraph (c) of this section. Value may not be less
than the gross proceeds accruing to the lessee, including any additional
consideration received .
(iii) If MMS determines that the gross proceeds accruing to the
lessee pursuant to an arm's-length contract do not reflect the
reasonable value of the production because of misconduct by or between
the contracting parties, or because the lessee otherwise has breached
its duty to the lessor to market the production for the mutual benefit
of the lessee and the lessor, MMS shall require that the byproduct
production be valued pursuant to paragraph (c) of this section and in
accordance with the notification requirements of paragraph (d) of this
section. If MMS determines that the value may be unreasonable, MMS will
notify the lessee and give the lessee an opportunity to provide written
information justifying the lessee's reported byproduct value.
(2) The MMS may require a lessee to certify that the provisions in
its arm's-length contract include all of the consideration to be paid by
the buyer, either directly or indirectly, for the byproduct.
(c) The value of byproducts that are sold pursuant to a non-arm's-
length contract or that are utilized by the lessee (no sales), except
demineralized water used for the benefit of the lease pursuant to
paragraph (b)(2) of Sec. 202.351 of this subpart, shall be determined in
accordance with the first applicable of the following paragraphs:
(1) The gross proceeds accruing to the lessee pursuant to a sale
under its non arm's-length contract (or other disposition by other than
an arm's-length contract), provided that those gross proceeds are not
less than the gross proceeds derived from or paid under the lowest-
priced available comparable arm's-length contract for sales, purchases,
or other dispositions of like-quality byproducts in the field or, if
necessary to obtain a representative
[[Page 127]]
sample, from the same area (the ``minimum value''). If the gross
proceeds under the lessee's non-arm's-length contract are less than the
``minimum value'' under available comparable arms length contracts, or
if there are no available comparable arm's-length contracts, value will
be determined by the weighted average of the gross proceeds established
under arm's-length contracts for the sale of like-quality products in
the field or, if necessary to obtain a representative sample, from the
same area. Available contracts will mean contracts in the possession of
the lessee, the lessee's affiliate, or MMS. In evaluating the
comparability of arm's-length contracts for the purposes of these
regulations, the following factors shall be considered: Field or area,
price, time of execution, duration, terms, quality of the byproduct,
volume, market or markets served, and other factors that may be
appropriate to reflect the value of the byproduct;
(2) Other relevant matters including, but not limited to, published
or publicly available spot-market prices, or information submitted by
the lessee concerning circumstances unique to a particular lease
operation or the saleability of certain byproducts; or
(3) A netback method or any other reasonable method used to
determine value.
(d)(1) Pursuant to subpart H of 30 CFR part 212, the lessee shall
retain all data relevant to the determination of royalty value,
particularly where the value is determined pursuant to paragraph (c) of
this section. Such data shall be subject to review and audit, and MMS
will direct a lessee to use a different value if it determines that the
reported value is inconsistent with the requirements of these
regulations.
(2) Upon request, lessees shall make available to authorized MMS
representatives or to other authorized persons any and all contracts
and/or invoices for the sale or other disposition of the byproducts, and
any arm's-length sales and other data for like-quality production sold,
purchased, or otherwise obtained by the lessee from the field or other
area as may be necessary to support a value determination.
(3) A lessee shall notify MMS if it has determined value pursuant to
paragraph (c) of this section. The notification shall be by letter to
the MMS Associate Director for 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) of this section, and each time there is a change in a
method under paragraph (c) of this section.
(e) If MMS determines that a lessee has not properly determined
value, the lessee shall pay the difference, if any, between royalty
payments made based upon the value it has used and the royalty payments
that are due based upon the value established by MMS. The lessee shall
also pay interest on that difference computed pursuant to 30 CFR
218.302. If the lessee is entitled to a credit, MMS will provide
instructions for the taking of that credit.
(f) The lessee may request a value determination from MMS. In that
event, the lessee shall propose to MMS a value determination method and
may use that method in determining value, for royalty purposes, until
MMS issues its decision. The lessee shall submit all available data
relevant to its proposal. The MMS shall expeditiously determine the
value based upon the lessee's proposal and any additional information
MMS deems necessary. In making a value determination, MMS may use any of
the valuation criteria consistent with this subpart. That determination
shall remain effective for the period stated therein. After MMS issues
its determination, the lessee shall make the adjustments in accordance
with paragraph (e) of this section.
(g) Notwithstanding any other provisions of the section, under no
circumstances shall the value of byproducts for royalty purposes be less
than the gross proceeds accruing to the lessee, less applicable
byproduct transportation allowances determined pursuant to Secs. 206.357
and 206.358 of this subpart.
[[Page 128]]
(h) The lessee is required to place the byproducts in marketable
condition at no cost to the Federal Government. Where the value
established pursuant to this section is determined by a lessee's gross
proceeds, that value shall be increased to the extent that the gross
proceeds have been reduced because the purchaser, or any other person,
is providing certain services the cost of which ordinarily is the
responsibility of the lessee to place the byproducts in marketable
condition.
(i) Value shall be based on the highest price a prudent lessee can
receive through legally enforceable claims under its contract. Absent
contract revision or amendment, if the lessee fails to take proper or
timely action to receive prices or benefits to which it is entitled, it
must pay royalty at a value based upon that obtainable price or benefit.
Contract revisions or amendments shall be in writing and signed by all
parties to the contract, and may be retroactively applied to value
byproducts, for royalty purposes, for a period not to exceed 2 years,
unless MMS approves a longer period. If the lessee makes timely
application for a price increase allowed under its contract but the
purchaser refuses and the lessee takes reasonable measures, which are
documented, to force purchaser compliance, the lessee will owe no
additional royalties unless or until monies or consideration resulting
from the price increase are received. This paragraph shall not be
construed to permit a lessee to avoid its royalty payment obligation in
situations where a purchaser fails to pay, in whole or in part or
timely, for a quantity of byproducts.
(j) Notwithstanding any provision in these regulations to the
contrary, no review, reconciliation, monitoring, or other like process
that results in a redetermination by MMS of value under this section
shall be considered final or binding against the Federal Government or
its beneficiaries until the audit period is formally closed.
(k) Certain information submitted to MMS to support valuation
proposals, including byproduct transportation allowances pursuant to
Secs. 206.357 and 206.358 of this subpart, is exempted from disclosure
by the Freedom of Information Act, 5 U.S.C. 552. Any data specified by
the act to be privileged, confidential, or otherwise exempt shall be
maintained in a confidential manner in accordance with applicable laws
and regulations. All requests for information about determinations made
under this subpart are to be submitted in accordance with the Freedom of
Information Act regulation of the Department, 43 CFR part 2.
Sec. 206.357 Byproduct transportation allowances--general.
(a) Where the value of byproducts has been determined at a point off
the geothermal lease, unit, or participating area, MMS shall allow a
deduction in determining value, for royalty purposes, for the lessee's
reasonable, actual costs incurred to:
(1) Transport the byproducts from a Federal lease, unit, or
participating area to a sales point or point of delivery that is off the
lease, unit, or participating area; or
(2) Transport the byproducts from a Federal lease, unit, or
participating area, or from a geothermal utilization facility to a
byproduct recovery facility when that byproduct recovery facility is off
the lease, unit, or participating area and, if applicable, from the
recovery facility to a sales point or point of delivery off the lease,
unit, or participating area. Costs for transporting geothermal fluids
from the lease to the geothermal utilization facility, whether on or off
the lease, shall not be included in the transportation allowance.
(b) Under no circumstances shall the byproduct transportation
allowance authorized by paragraph (a) of this section reduce the value
of the byproducts under any selling arrangement to zero.
(c)(1) When byproducts are transported from a lease, unit,
participating area, or geothermal utilization facility to a byproduct
recovery facility, the lessee is not required to allocate transportation
costs between the quantity of marketable byproducts and the rejected
waste material. The byproduct transportation allowance shall be
authorized for the total production that is transported. Byproduct
transportation allowances shall be expressed as a cost per unit of
marketable byproducts transported.
[[Page 129]]
(2) For byproducts that are extracted on the lease, unit, or
participating area, or at the geothermal utilization facility, the
byproduct transportation allowance shall be authorized for the total
production that is transported to a point of sale off the lease, unit,
or participating area. Byproduct transportation allowances shall be
expressed as a cost per unit of byproduct transported.
(3) Transportation costs shall be authorized as allowances only when
the transported byproduct is sold, delivered, or otherwise utilized by
the lessee and royalties are reported and paid.
(d) Byproduct transportation allowances are subject to monitoring,
review, and audit. If, after a review and/or audit, MMS determines that
a lessee has improperly determined a byproduct transportation allowance
authorized by this section, then the lessee shall pay any additional
royalties plus interest determined in accordance with 30 CFR 218.302, or
shall be entitled to a credit without interest.
(e) If byproducts produced from Federal and non-Federal leases are
commingled for transportation, lessees shall not disproportionately
allocate transportation costs to Federal lease production.
(f) Upon request, the lessee shall make available to authorized MMS
representatives or to other authorized persons all transportation
contracts and all other information as may be necessary to support a
byproduct transportation allowance.
(g) Byproduct transportation allowances are to be reported as
separate lines on Form MMS-2014.
Sec. 206.358 Determination of byproduct transportation allowances.
(a) Arm's-length contracts. (1) For transportation costs incurred by
a lessee pursuant to an arm's-length contract, the transportation
allowance shall be the reasonable, actual costs incurred by the lessee
for transporting the byproducts under that contract, subject to
monitoring, review, audit, and possible future adjustments. The MMS's
prior approval is not required before a lessee may deduct costs incurred
under an arm's-length transportation contract.
(2) In conducting reviews and audits, MMS will examine whether the
contract reflects more than the consideration actually transferred
either directly or indirectly from the lessee to the transporter for the
transportation. If the contract reflects more than the total
consideration paid, MMS may require that the byproduct transportation
allowance be determined in accordance with paragraph (b) of this
section.
(3) If MMS determines that the consideration paid pursuant to an
arm's-length byproduct transportation contract does not reflect the
reasonable value of the transportation because of misconduct by or
between the contracting parties, or because the lessee otherwise has
breached its duty to the lessor to market the production for the mutual
benefit of the lessee and the lessor, MMS shall require that the
byproduct transportation allowance be determined in accordance with
paragraph (b) of this section. When MMS determines that the value of the
transportation may be unreasonable, MMS will notify the lessee and give
the lessee an opportunity to provide written information justifying the
lessee's transportation costs.
(4) Where the lessee's payments for transportation under an arm's-
length contract are not established on a dollars-per-unit basis, the
lessee shall convert whatever consideration is paid to a dollar value
equivalent for the purposes of this section.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length transportation contract or has no contract, including those
situations where the lessee performs transportation services for itself,
the byproduct transportation allowance shall be based upon the lessee's
reasonable actual costs. All byproduct transportation allowances
deducted under a non-arm's-length or no-contract situation are subject
to monitoring, review, audit, and possible future adjustment. Prior MMS
approval of byproduct transportation allowances is not required for non-
arm's-length or no-contract situations.
(2) The byproduct transportation allowance for non-arm's-length or
no-contract situations shall be based upon
[[Page 130]]
the lessee's actual costs for transportation during the reporting
period, including operating and maintenance expenses, overhead, and
either depreciation and a return on undepreciated capital investment in
accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal
to the capital investment in the transportation system multiplied by the
rate of return in accordance with paragraph (b)(2)(iv)(B) of this
section. Allowable capital costs are generally those for depreciable
assets, including costs of delivery and installation of capital
equipment, that are an integral part of the transportation system. A
return on capital invested in the purchase of real estate to locate the
byproduct transportation facilities may be allowed provided that the
lessee demonstrates the necessity for such purchase, the purchased land
is not on a Federal geothermal lease, and MMS approves the deduction;
the rate of return shall be the same rate determined in paragraph
(b)(2)(v) of this section.
(i) Allowable operating expenses include operations supervision and
engineering, operations labor, fuel, utilities, materials, ad valorem
property taxes, rent, supplies, and any other allocable and attributable
operating expenses that the lessee can document.
(ii) Allowable maintenance expenses include maintenance of the
transportation system, maintenance of equipment, maintenance labor, and
other directly allocable and attributable maintenance expenses that the
lessee can document.
(iii) Overhead attributable and allocable to the operation and
maintenance of the transportation system is an allowable expense. State
and Federal income taxes and severance taxes and other fees, including
royalties, are not allowable expenses.
(iv) To compute costs associated with capital investment, a lessee
may use either paragraph (b)(2)(iv)(A) or (b)(2)(iv)(B) of this section.
After a lessee has elected to use either method for a transportation
system, the lessee may not later elect to change to the other
alternative without MMS approval.
(A) To compute depreciation, the lessee must use a straight-line
depreciation method based on, as appropriate, either the life of
equipment or the life of the geothermal project that the transportation
system services. After an election is made, the lessee may not change
methods. A change in ownership of a transportation system shall not
alter the depreciation schedule established by the original transporter/
lessee for purposes of the allowance calculation. With or without a
change in ownership, a transportation system shall be depreciated only
once. Equipment shall not be depreciated below a reasonable salvage
value. The rate of return used to compute the return on undepreciated
capital investment shall be determined pursuant to paragraph (b)(2)(v)
of this section.
(B) To compute a return on capital investment, the allowed cost
shall be the amount equal to the allowable capital investment in the
transportation system multiplied by the rate of return determined
pursuant to paragraph (b)(2)(v) of this section. No allowance shall be
provided for depreciation.
(v) The rate of return shall be Standard and Poor's industrial BBB
bond rate. The rate of return shall be the monthly average rate as
published in Standard and Poor's Bond Guide for the first month of the
annual reporting period for which the allowance is applicable and shall
be effective during the reporting period. The rate shall be redetermined
at the beginning of each subsequent transportation allowance reporting
period.
Subpart I--OCS Sulfur [Reserved]
Subpart J--Indian Coal
Source: 61 FR 5481, Feb. 12, 1996, unless otherwise noted.
Sec. 206.450 Purpose and scope.
(a) This subpart prescribes the procedures to establish the value,
for royalty purposes, of all coal from Indian Tribal and allotted leases
(except leases on the Osage Indian Reservation, Osage County, Oklahoma).
(b) If the specific provisions of any statute, treaty, or settlement
agreement between the Indian lessor and a lessee resulting from
administrative or judicial litigation, or any coal lease
[[Page 131]]
subject to the requirements of this subpart, are inconsistent with any
regulation in this subpart, then the statute, treaty, lease provision,
or settlement shall govern to the extent of that inconsistency.
(c) All royalty payments are subject to later audit and adjustment.
(d) The regulations in this subpart are intended to ensure that the
trust responsibilities of the United States with respect to the
administration of Indian coal leases are discharged in accordance with
the requirements of the governing mineral leasing laws, treaties, and
lease terms.
Sec. 206.451 Definitions.
Ad valorem lease means a lease where the royalty due to the lessor
is based upon a percentage of the amount or value of the coal.
Allowance means an approved, or an MMS-initially accepted deduction
in determining value for royalty purposes. Coal washing allowance means
an allowance for the reasonable, actual costs incurred by the lessee for
coal washing, or an approved or MMS-initially accepted deduction for the
costs of washing coal, determined pursuant to this subpart.
Transportation allowance means an allowance for the reasonable, actual
costs incurred by the lessee for moving coal to a point of sale or point
of delivery remote from both the lease and mine or wash plant, or an
approved MMS-initially accepted deduction for costs of such
transportation, determined pursuant to this subpart.
Area means a geographic region in which coal has similar quality and
economic characteristics. Area boundaries are not officially designated
and the areas are not necessarily named.
Arm's-length contract means a contract or agreement that has been
arrived at in the marketplace between independent, nonaffiliated persons
with opposing economic interests regarding that contract. For purposes
of this subpart, two persons are affiliated if one person controls, is
controlled by, or is 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
[[Page 132]]
the Indian lessor. Gross proceeds, as applied to coal, also includes but
is not limited to reimbursements for royalties, taxes or fees, and other
reimbursements. Tax reimbursements are part of the gross proceeds
accruing to a lessee even though the Indian royalty interest may be
exempt from taxation. Monies and other consideration, including the
forms of consideration identified in this paragraph, to which a lessee
is contractually or legally entitled but which it does not seek to
collect through reasonable efforts are also part of gross proceeds.
Indian allottee means any Indian for whom land or an interest in
land is held in trust by the United States or who holds title subject to
Federal restriction against alienation.
Indian Tribe means any Indian Tribe, band, nation, pueblo,
community, rancheria, colony, or other group of Indians for which any
land or interest in land is held in trust by the United States or which
is subject to Federal restriction against alienation.
Lease means any contract, profit-share arrangement, joint venture,
or other agreement issued or approved by the United States for an Indian
coal resource under a mineral leasing law that authorizes exploration
for, development or extraction of, or removal of coal--or the land
covered by that authorization, whichever is required by the context.
Lessee means any person to whom the Indian Tribe or an Indian
allottee issues a lease, and any person who has been assigned an
obligation to make royalty or other payments required by the lease. This
includes any person who has an interest in a lease as well as an
operator or payor who has no interest in the lease but who has assumed
the royalty payment responsibility.
Like-quality coal means coal that has similar chemical and physical
characteristics.
Marketable condition means coal that is sufficiently free from
impurities and otherwise in a condition that it will be accepted by a
purchaser under a sales contract typical for that area.
Mine means an underground or surface excavation or series of
excavations and the surface or underground support facilities that
contribute directly or indirectly to mining, production, preparation,
and handling of lease products.
MMS means the Minerals Management Service of the Department of the
Interior.
Net-back method means a method for calculating market value of coal
at the lease or mine. Under this method, costs of transportation,
washing, handling, etc., are deducted from the ultimate proceeds
received for the coal at the first point at which reasonable values for
the coal may be determined by a sale pursuant to an arm's-length
contract or by comparison to other sales of coal, to ascertain value at
the mine.
Net output means the quantity of washed coal that a washing plant
produces.
Person means by individual, firm, corporation, association,
partnership, consortium, or joint venture.
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
[[Page 133]]
method used to initially mine coal in the waste pile or slurry pond;
i.e., underground mining method or surface mining method. Coal in waste
pits or slurry ponds initially mined from Indian leases shall be
allocated to such leases regardless of whether it is stored on Indian
lands. The lessee shall maintain accurate records to determine to which
individual Indian lease coal in the waste pit or slurry pond should be
allocated. However, nothing in this section requires payment of a
royalty on coal for which a royalty has already been paid.
Sec. 206.453 Quality and quantity measurement standards for reporting
and paying royalties.
For all leases subject to this subpart, the quantity of coal on
which royalty is due shall be measured in short tons (of 2,000 pounds
each) by methods prescribed by the BLM. Coal quantity information 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
Secs. 206.457 through 206.461 of this subpart, or any allowance
authorized by Sec. 206.464 of this subpart. The royalty due shall be
equal
[[Page 134]]
to the value for royalty purposes multiplied by the royalty rate in the
lease.
(b)(1) The value of coal that is sold pursuant to an arm's-length
contract shall be the gross proceeds accruing to the lessee, except as
provided in paragraphs (b)(2), (b)(3), and (b)(5) of this section. The
lessee shall have the burden of demonstrating that its contract is
arm's-length. The value which the lessee reports, for royalty purposes,
is subject to monitoring, review, and audit.
(2) In conducting reviews and audits, MMS will examine whether the
contract reflects the total consideration actually transferred either
directly or indirectly from the buyer to the seller for the coal
produced. If the contract does not reflect the total consideration, then
MMS may require that the coal sold pursuant to that contract be valued
in accordance with paragraph (c) of this section. Value may not be based
on less than the gross proceeds accruing to the lessee for the coal
production, including the additional consideration.
(3) If MMS determines that the gross proceeds accruing to the lessee
pursuant to an arm's-length contract do not reflect the reasonable value
of the production because of misconduct by or between the contracting
parties, or because the lessee otherwise has breached its duty to the
lessor to market the production for the mutual benefit of the lessee and
the lessor, then MMS shall require that the coal production be valued
pursuant to paragraphs (c)(2)(ii), (c)(2)(iii), (c)(2)(iv), or (c)(2)(v)
of this section, and in accordance with the notification requirements of
paragraph (d)(3) of this section. When MMS determines that the value may
be unreasonable, MMS will notify the lessee and give the lessee an
opportunity to provide written information justifying the lessee's
reported coal value.
(4) MMS may require a lessee to certify that its arm's-length
contract provisions include all of the consideration to be paid by the
buyer, either directly or indirectly, for the coal production.
(5) The value of production for royalty purposes shall not include
payments received by the lessee pursuant to a contract which the lessee
demonstrates, to MMS' satisfaction, were not part of the total
consideration paid for the purchase of coal production.
(c)(1) The value of coal from leases subject to this section and
which is not sold pursuant to an arm's-length contract shall be
determined in accordance with this section.
(2) If the value of the coal cannot be determined pursuant to
paragraph (b) of this section, then the value shall be determined
through application of other valuation criteria. The criteria shall be
considered in the following order, and the value shall be based upon the
first applicable criterion:
(i) The gross proceeds accruing to the lessee pursuant to a sale
under its non-arm's-length contract (or other disposition of produced
coal by other than an arm's-length contract), provided that those gross
proceeds are within the range of the gross proceeds derived from, or
paid under, comparable arm's-length contracts between buyers and sellers
neither of whom is affiliated with the lessee for sales, purchases, or
other dispositions of like-quality coal produced in the area. In
evaluating the comparability of arm's-length contracts for the purposes
of these regulations, the following factors shall be considered: price,
time of execution, duration, market or markets served, terms, quality of
coal, quantity, and such other factors as may be appropriate to reflect
the value of the coal;
(ii) Prices reported for that coal to a public utility commission;
(iii) Prices reported for that coal to the Energy Information
Administration of the Department of Energy;
(iv) Other relevant matters including, but not limited to, published
or publicly available spot market prices, or information submitted by
the lessee concerning circumstances unique to a particular lease
operation or the salability of certain types of coal;
(v) If a reasonable value cannot be determined using paragraphs
(c)(2)(i), (c)(2)(ii), (c)(2)(iii), or (c)(2)(iv) of this section, then
a net-back method or any other reasonable method shall be used to
determine value.
(3) When the value of coal is determined pursuant to paragraph
(c)(2) of this section, that value determination shall be consistent
with the provisions
[[Page 135]]
contained in paragraph (b)(5) of this section.
(d)(1) Where the value is determined pursuant to paragraph (c) of
this section, that value does not require MMS' prior approval. However,
the lessee shall retain all data relevant to the determination of
royalty value. Such data shall be subject to review and audit, and MMS
will direct a lessee to use a different value if it determines that the
reported value is inconsistent with the requirements of these
regulations.
(2) An Indian lessee will make available upon request to the
authorized MMS or Indian representatives, or to the Inspector General of
the Department of the Interior or other persons authorized to receive
such information, arm's-length sales and sales quantity data for like-
quality coal sold, purchased, or otherwise obtained by the lessee from
the area.
(3) A lessee shall notify MMS if it has determined value pursuant to
paragraphs (c)(2)(ii), (c)(2)(iii), (c)(2)(iv), or (c)(2)(v) of this
section. The notification shall be by letter to the Associate Director
for Minerals Revenue Management or his/her designee. The letter shall
identify the valuation method to be used and contain a brief description
of the procedure to be followed. The notification required by this
section is a one-time notification due no later than the month the
lessee first reports royalties on the Form MMS-4430 using a valuation
method authorized by paragraphs (c)(2)(ii), (c)(2)(iii), (c)(2)(iv), or
(c)(2)(v) of this section, and each time there is a change in a method
under paragraphs (c)(2)(iv) or (c)(2)(v) of this section.
(e) If MMS determines that a lessee has not properly determined
value, the lessee shall be liable for the difference, if any, between
royalty payments made based upon the value it has used and the royalty
payments that are due based upon the value established by MMS. The
lessee shall also be liable for interest computed pursuant to 30 CFR
218.202. If the lessee is entitled to a credit, MMS will provide
instructions for the taking of that credit.
(f) The lessee may request a value determination from MMS. In that
event, the lessee shall propose to MMS a value determination method, and
may use that method in determining value for royalty purposes until MMS
issues its decision. The lessee shall submit all available data relevant
to its proposal. MMS shall expeditiously determine the value based upon
the lessee's proposal and any additional information MMS deems
necessary. That determination shall remain effective for the period
stated therein. After MMS issues its determination, the lessee shall
make the adjustments in accordance with paragraph (e) of this section.
(g) Notwithstanding any other provisions of this section, under no
circumstances shall the value for royalty purposes be less than the
gross proceeds accruing to the lessee for the disposition of produced
coal less applicable provisions of paragraph (b)(5) of this section and
less applicable allowances determined pursuant to Secs. 206.457 through
206.461 and Sec. 206.464 of this subpart.
(h) The lessee is required to place coal in marketable condition at
no cost to the Indian lessor. Where the value established pursuant to
this section is determined by a lessee's gross proceeds, that value
shall be increased to the extent that the gross proceeds has been
reduced because the purchaser, or any other person, is providing certain
services, the cost of which ordinarily is the responsibility of the
lessee to place the coal in marketable condition.
(i) Value shall be based on the highest price a prudent lessee can
receive through legally enforceable claims under its contract. Absent
contract revision or amendment, if the lessee fails to take proper or
timely action to receive prices or benefits to which it is entitled, it
must pay royalty at a value based upon that obtainable price or benefit.
Contract revisions or amendments shall be in writing and signed by 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
[[Page 136]]
royalties unless or until monies or consideration resulting from the
price increase are received. This paragraph shall not be construed to
permit a lessee to avoid its royalty payment obligation in situations
where a purchaser fails to pay, in whole or in part or timely, for a
quantity of coal.
(j) Notwithstanding any provision in these regulations to the
contrary, no review, reconciliation, monitoring, or other like process
that results in a redetermination by MMS of value under this section
shall be considered final or binding as against the Indian Tribes or
allottees until the audit period is formally closed.
(k) Certain information submitted to MMS to support valuation
proposals, including transportation, coal washing, or other allowances
pursuant to Secs. 206.457 through 206.461 and Sec. 206.464 of this
subpart, is exempted from disclosure by the Freedom of Information Act,
5 U.S.C. 522. Any data specified by the Act to be privileged,
confidential, or otherwise exempt shall be maintained in a confidential
manner in accordance with applicable law and regulations. All requests
for information about determinations made under this part are to be
submitted in accordance with the Freedom of Information Act regulation
of the Department of the Interior, 43 CFR part 2. Nothing in this
section is intended to limit or diminish in any manner whatsoever the
right of an Indian lessor to obtain any and all information as such
lessor may be lawfully entitled from MMS or such lessor's lessee
directly under the terms of the lease or applicable law.
[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
[[Page 137]]
that the washing allowance be determined in accordance with paragraph
(b) of this section.
(3) If MMS determines that the consideration paid pursuant to an
arm's-length washing contract does not reflect the reasonable value of
the washing because of misconduct by or between the contracting parties,
or because the lessee otherwise has breached its duty to the lessor to
market the production for the mutual benefit of the lessee and the
lessor, then MMS shall require that the washing allowance be determined
in accordance with paragraph (b) of this section. When MMS determines
that the value of the washing may be unreasonable, MMS will notify the
lessee and give the lessee an opportunity to provide written information
justifying the lessee's washing costs.
(4) Where the lessee's payments for washing under an arm's-length
contract are not based on a dollar-per-unit basis, the lessee shall
convert whatever consideration is paid to a dollar value equivalent.
Washing allowances shall be expressed as a cost per ton of coal washed.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length contract or has no contract, including those situations
where the lessee performs washing for itself, the washing allowance will
be based upon the lessee's reasonable actual costs. All washing
allowances deducted under a non-arm's-length or no contract situation
are subject to monitoring, review, audit, and possible future
adjustment. Prior MMS approval of washing allowances is not required for
non-arm's-length or no contract situations. However, before any
estimated or actual deduction may be taken, the lessee must submit a
completed Form MMS-4292 in accordance with paragraph (c)(2) of this
section. A washing allowance may be claimed retroactively for a period
of not more than 3 months prior to the first day of the month that Form
MMS-4292 is filed with MMS, unless MMS approves a longer period upon a
showing of good cause by the lessee. MMS will monitor the allowance
deduction to ensure that deductions are reasonable and allowable. When
necessary or appropriate, MMS may direct a lessee to modify its actual
washing allowance.
(2) The washing allowance for non-arm's-length or no contract
situations shall be based upon the lessee's actual costs for washing
during the reported period, including operating and maintenance
expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph
(b)(2)(iv)(A) of this section, or a cost equal to the depreciable
investment in the wash plant multiplied by the rate of return in
accordance with paragraph (b)(2)(iv)(B) of this section. Allowable
capital costs are generally those for depreciable fixed assets
(including costs of delivery and installation of capital equipment)
which are an integral part of the wash plant.
(i) Allowable operating expenses include: Operations supervision and
engineering; operations labor; fuel; utilities; materials; ad valorem
property taxes; rent; supplies; and any other directly allocable and
attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the wash
plant; maintenance of equipment; maintenance labor; and other directly
allocable and attributable maintenance expenses which the lessee can
document.
(iii) Overhead attributable and allocable to the operation and
maintenance of the wash plant is an allowable expense. State and Federal
income taxes and severance taxes, including royalties, are not allowable
expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or
(b)(2)(iv)(B) of this section. After a lessee has elected to use either
method for a wash plant, the lessee may not later elect to change to the
other alternative without approval of MMS.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the wash plant services, whichever is
appropriate, or a unit of production method. After an election is made,
the lessee may not change methods without MMS approval. A change in
ownership of a wash plant shall not
[[Page 138]]
alter the depreciation schedule established by the original operator/
lessee for purposes of the allowance calculation. With or without a
change in ownership, a wash plant shall be depreciated only once.
Equipment shall not be depreciated below a reasonable salvage value.
(B) MMS shall allow as a cost an amount equal to the allowable
capital investment in the wash plant multiplied by the rate of return
determined pursuant to paragraph (b)(2)(v) of this section. No allowance
shall be provided for depreciation. This alternative shall apply only to
plants first placed in service or acquired after March 1, 1989.
(v) The rate of return shall be the industrial rate associated with
Standard and Poor's BBB rating. The rate of return shall be the monthly
average rate as published in Standard and Poor's Bond Guide for the
first month of the reporting period for which the allowance is
applicable and shall be effective during the reporting period. The rate
shall be redetermined at the beginning of each subsequent washing
allowance reporting period (which is determined pursuant to paragraph
(c)(2) of this section).
(3) The washing allowance for coal shall be determined based on the
lessee's reasonable and actual cost of washing the coal. The lessee may
not take an allowance for the costs of washing lease production that is
not royalty bearing.
(c) Reporting requirements. (1) Arm's-length contracts. (i) With the
exception of those washing allowances specified in paragraphs (c)(1)(v)
and (c)(1)(vi) of this section, the lessee shall submit page one of the
initial Form MMS-4292 prior to, or at the same time, as the washing
allowance determined pursuant to an arm's-length contract is reported on
Form MMS-4430, Solid Minerals Production and Royalty Report. A Form MMS-
4292 received by the end of the month that the Form MMS-4430 is due
shall be considered to be received timely.
(ii) The initial Form MMS-4292 shall be effective for a reporting
period beginning the month that the lessee is first authorized to deduct
a washing allowance and shall continue until the end of the calendar
year, or until the applicable contract or rate terminates or is modified
or amended, whichever is earlier.
(iii) After the initial reporting period and for succeeding
reporting periods, lessees must submit page one of Form MMS-4292 within
3 months after the end of the calendar year, or after the applicable
contract or rate terminates or is modified or amended, whichever is
earlier, unless MMS approves a longer period (during which period the
lessee shall continue to use the allowance from the previous reporting
period).
(iv) MMS may require that a lessee submit arm's-length washing
contracts and related documents. Documents shall be submitted within a
reasonable time, as determined by MMS.
(v) Washing allowances which are based on arm's-length contracts and
which are in effect at the time these regulations become effective will
be allowed to continue until such allowances terminate. For the purposes
of this section, only those allowances that have been approved by MMS in
writing shall qualify as being in effect at the time these regulations
become effective.
(vi) MMS may establish, in appropriate circumstances, reporting
requirements that are different from the requirements of this section.
(2) Non-arm's-length or no contract. (i) With the exception of those
washing allowances specified in paragraphs (c)(2)(v) and (c)(2)(vii) of
this section, the lessee shall submit an initial Form MMS-4292 prior to,
or at the same time as, the washing allowance determined pursuant to a
non-arm's-length contract or no contract situation is reported on Form
MMS-4430, Solid Minerals Production and Royalty Report. A Form MMS-4292
received by the end of the month that the Form MMS-4430 is due shall be
considered to be timely received. The initial reporting may be based on
estimated costs.
(ii) The initial Form MMS-4292 shall be effective for a reporting
period beginning the month that the lessee first is authorized to deduct
a washing allowance and shall continue until the end of the calendar
year, or until the washing under the non-arm's-length contract or the no
contract situation terminates, whichever is earlier.
[[Page 139]]
(iii) For calendar-year reporting periods succeeding the initial
reporting period, the lessee shall submit a completed Form MMS-4292
containing the actual costs for the previous reporting period. If coal
washing is continuing, the lessee shall include on Form MMS-4292 its
estimated costs for the next calendar year. The estimated coal washing
allowance shall be based on the actual costs for the previous period
plus or minus any adjustments which are based on the lessee's knowledge
of decreases or increases which will affect the allowance. Form MMS-4292
must be received by MMS within 3 months after the end of the previous
reporting period, unless MMS approves a longer period (during which
period the lessee shall continue to use the allowance from the previous
reporting period).
(iv) For new wash plants, the lessee's initial Form MMS-4292 shall
include estimates of the allowable coal washing costs for the applicable
period. Cost estimates shall be based upon the most recently available
operations data for the plant, or if such data are not available, the
lessee shall use estimates based upon industry data for similar coal
wash plants.
(v) Washing allowances based on non-arm's-length or no contract
situations which are in effect at the time these regulations become
effective will be allowed to continue until such allowances terminate.
For the purposes of this section, only those allowances that have been
approved by MMS in writing shall qualify as being in effect at the time
these regulations become effective.
(vi) Upon request by MMS, the lessee shall submit all data used by
the lessee to prepare its Forms MMS-4292. The data shall be provided
within a reasonable period of time, as determined by MMS.
(vii) MMS may establish, in appropriate circumstances, reporting
requirements which are different from the requirements of this section.
(3) MMS may establish coal washing allowance reporting dates for
individual leases different from those specified in this subpart in
order to provide more effective administration. Lessees will be notified
of any change in their reporting period.
(4) Washing allowances must be reported as a separate line on the
Form MMS-4430, unless MMS approves a different reporting procedure.
(d) Interest assessments for incorrect or late reports and failure
to report. (1) If a lessee deducts a washing allowance on its Form MMS-
4430 without complying with the requirements of this section, the lessee
shall be liable for interest on the amount of such deduction until the
requirements of this section are complied with. The lessee also shall
repay the amount of any allowance which is disallowed by this section.
(2) If a lessee erroneously reports a washing allowance which
results in an underpayment of royalties, interest shall be paid on the
amount of that underpayment.
(3) Interest required to be paid by this section shall be determined
in accordance with 30 CFR 218.202.
(e) Adjustments. (1) If the actual coal washing allowance is less
than the amount the lessee has taken on Form MMS-4430 for each month
during the allowance form reporting period, the lessee shall be required
to pay additional royalties due plus interest computed pursuant to 30
CFR 218.202, retroactive to the first month the lessee is authorized to
deduct a washing allowance. If the actual washing allowance is greater
than the amount the lessee has estimated and taken during the reporting
period, the lessee shall be entitled to a credit, without interest.
(2) The lessee must submit a corrected Form MMS-4430 to reflect
actual costs, together with any payment, in accordance with instructions
provided by MMS.
(f) Other washing cost determinations. The provisions of this
section shall apply to determine washing costs when establishing value
using a net-back valuation procedure or any other procedure that
requires deduction of washing costs.
[61 FR 5481, Feb. 12, 1996, as amended at 66 FR 45769, Aug. 30, 2001]
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.
[[Page 140]]
(b) When the net output of coal from a washing plant is derived from
coal obtained from only one lease, the quantity of washed coal allocable
to the lease will be based on the net output of the washing plant.
(c) When the net output of coal from a washing plant is derived from
coal obtained from more than one lease, unless determined otherwise by
BLM, the quantity of net output of washed coal allocable to each lease
will be based on the ratio of measured quantities of coal delivered to
the washing plant and washed from each lease compared to the total
measured quantities of coal delivered to the washing plant and washed.
Sec. 206.460 Transportation allowances--general.
(a) For ad valorem leases subject to Sec. 206.456 of this subpart,
where the value for royalty purposes has been determined at a point
remote from the lease or mine, MMS shall, as authorized by this section,
allow a deduction in determining value for royalty purposes for the
reasonable, actual costs incurred to:
(1) Transport the coal from an Indian lease to a sales point which
is remote from both the lease and mine; or
(2) Transport the coal from an Indian lease to a wash plant when
that plant is remote from both the lease and mine and, if applicable,
from the wash plant to a remote sales point. In-mine transportation
costs shall not be included in the transportation allowance.
(b) Under no circumstances will the authorized washing allowance and
the transportation allowance reduce the value for royalty purposes to
zero.
(c)(1) When coal transported from a mine to a wash plant is eligible
for a transportation allowance in accordance with this section, the
lessee is not required to allocate transportation costs between the
quantity of clean coal output and the rejected waste material. The
transportation allowance shall be authorized for the total production
which is transported. Transportation allowances shall be expressed as a
cost per ton of cleaned coal transported.
(2) For coal that is not washed at a wash plant, the transportation
allowance shall be authorized for the total production which is
transported. Transportation allowances shall be expressed as a cost per
ton of coal transported.
(3) Transportation costs shall only be recognized as allowances when
the transported coal is sold and royalties are reported and paid.
(d) If, after a review and/or audit, MMS determines that a lessee
has improperly determined a transportation allowance authorized by this
section, then the lessee shall pay any additional royalties, plus
interest, determined in accordance with 30 CFR 218.202, or shall be
entitled to a credit, without interest.
(e) Lessees shall not disproportionately allocate transportation
costs to Indian leases.
[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999]
Sec. 206.461 Determination of transportation allowances.
(a) Arm's-length contracts. (1) For transportation costs incurred by
a lessee pursuant to an arm's-length contract, the transportation
allowance shall be the reasonable, actual costs incurred by the lessee
for transporting the coal under that contract, subject to monitoring,
review, audit, and possible future adjustment. MMS' prior approval is
not required before a lessee may deduct costs incurred under an arm's-
length contract. However, before any deduction may be taken, the lessee
must submit a completed page one of Form MMS-4293, Coal Transportation
Allowance Report, in accordance with paragraph (c)(1) of this section. A
transportation allowance may be claimed retroactively for a period of
not more than 3 months prior to the first day of the month that Form
MMS-4293 is filed with MMS, unless MMS approves a longer period upon a
showing of good cause by the lessee.
(2) In conducting reviews and audits, MMS will examine whether the
contract reflects more than the consideration actually transferred
either directly or indirectly from the lessee to the transporter for the
transportation. If the contract reflects more than the total
consideration paid, then MMS
[[Page 141]]
may require that the transportation allowance be determined in
accordance with paragraph (b) of this section.
(3) If MMS determines that the consideration paid pursuant to an
arm's-length transportation contract does not reflect the reasonable
value of the transportation because of misconduct by or between the
contracting parties, or because the lessee otherwise has breached its
duty to the lessor to market the production for the mutual benefit of
the lessee and the lessor, then MMS shall require that the
transportation allowance be determined in accordance with paragraph (b)
of this section. When MMS determines that the value of the
transportation may be unreasonable, MMS will notify the lessee and give
the lessee an opportunity to provide written information justifying the
lessee's transportation costs.
(4) Where the lessee's payments for transportation under an arm's-
length contract are not based on a dollar-per-unit basis, the lessee
shall convert whatever consideration is paid to a dollar value
equivalent for the purposes of this section.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length contract or has no contract, including those situations
where the lessee performs transportation services for itself, the
transportation allowance will be based upon the lessee's reasonable
actual costs. All transportation allowances deducted under a non-arm's-
length or no contract situation are subject to monitoring, review,
audit, and possible future adjustment. Prior MMS approval of
transportation allowances is not required for non-arm's-length or no
contract situations. However, before any estimated or actual deduction
may be taken, the lessee must submit a completed Form MMS-4293 in
accordance with paragraph (c)(2) of this section. A transportation
allowance may be claimed retroactively for a period of not more than 3
months prior to the first day of the month that Form MMS-4293 is filed
with MMS, unless MMS approves a longer period upon a showing of good
cause by the lessee. MMS will monitor the allowance deductions to ensure
that deductions are reasonable and allowable. When necessary or
appropriate, MMS may direct a lessee to modify its estimated or actual
transportation allowance deduction.
(2) The transportation allowance for non-arm's-length or no contract
situations shall be based upon the lessee's actual costs for
transportation during the reporting period, including operating and
maintenance expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph
(b)(2)(iv)(A) of this section, or a cost equal to the depreciable
investment in the transportation system multiplied by the rate of return
in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable
capital costs are generally those for depreciable fixed assets
(including costs of delivery and installation of capital equipment)
which are an integral part of the transportation system.
(i) Allowable operating expenses include: Operations supervision and
engineering; operations labor; fuel; utilities; materials; ad valorem
property taxes; rent; supplies; and any other directly allocable and
attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the
transportation system; maintenance of equipment; maintenance labor; and
other directly allocable and attributable maintenance expenses which the
lessee can document.
(iii) Overhead attributable and allocable to the operation and
maintenance of the transportation system is an allowable expense. State
and Federal income taxes and severance taxes and other fees, including
royalties, are not allowable expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or paragraph
(b)(2)(iv)(B) of this section. After a lessee has elected to use either
method for a transportation system, the lessee may not later elect to
change to the other alternative without approval of MMS.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the transportation system services,
whichever is appropriate,
[[Page 142]]
or a unit of production method. After an election is made, the lessee
may not change methods without MMS approval. A change in ownership of a
transportation system shall not alter the depreciation schedule
established by the original transporter/lessee for purposes of the
allowance calculation. With or without a change in ownership, a
transportation system shall be depreciated only once. Equipment shall
not be depreciated below a reasonable salvage value.
(B) MMS shall allow as a cost an amount equal to the allowable
capital investment in the transportation system multiplied by the rate
of return determined pursuant to paragraph (b)(2)(B)(v) of this section.
No allowance shall be provided for depreciation. This alternative shall
apply only to transportation facilities first placed in service or
acquired after March 1, 1989.
(v) The rate of return shall be the industrial rate associated with
Standard and Poor's BBB rating. The rate of return shall be the monthly
average as published in Standard and Poor's Bond Guide for the first
month of the reporting period of which the allowance is applicable and
shall be effective during the reporting period. The rate shall be
redetermined at the beginning of each subsequent transportation
allowance reporting period (which is determined pursuant to paragraph
(c)(2) of this section).
(3) A lessee may apply to MMS for exception from the requirement
that it compute actual costs in accordance with paragraphs (b)(1) and
(b)(2) of this section. MMS will grant the exception only if the lessee
has a rate for the transportation approved by a Federal agency for
Indian leases. MMS shall deny the exception request if it determines
that the rate is excessive as compared to arm's-length transportation
charges by systems, owned by the lessee or others, providing similar
transportation services in that area. If there are no arm's-length
transportation charges, MMS shall deny the exception request if:
(i) No Federal regulatory agency cost analysis exists and the
Federal regulatory agency has declined to investigate pursuant to MMS
timely objections upon filing; and
(ii) The rate significantly exceeds the lessee's actual costs for
transportation as determined under this section.
(c) Reporting requirements. (1) Arm's-length contracts. (i) With the
exception of those transportation allowances specified in paragraphs
(c)(1)(v) and (c)(1)(vi) of this section, the lessee shall submit page
one of the initial Form MMS-4293 prior to, or at the same time as, the
transportation allowance determined pursuant to an arm's-length contract
is reported on Form MMS-4430, Solid Minerals Production and Royalty
Report.
(ii) The initial Form MMS-4293 shall be effective for a reporting
period beginning the month that the lessee is first authorized to deduct
a transportation allowance and shall continue until the end of the
calendar year, or until the applicable contract or rate terminates or is
modified or amended, whichever is earlier.
(iii) After the initial reporting period and for succeeding
reporting periods, lessees must submit page one of Form MMS-4293 within
3 months after the end of the calendar year, or after the applicable
contract or rate terminates or is modified or amended, whichever is
earlier, unless MMS approves a longer period (during which period the
lessee shall continue to use the allowance from the previous reporting
period). Lessees may request special reporting procedures in unique
allowance reporting situations, such as those related to spot sales.
(iv) MMS may require that a lessee submit arm's-length
transportation contracts, production agreements, operating agreements,
and related documents. Documents shall be submitted within a reasonable
time, as determined by MMS.
(v) Transportation allowances that are based on arm's-length
contracts and which are in effect at the time these regulations become
effective will be allowed to continue until such allowances terminate.
For the purposes of this section, only those allowances that have been
approved by MMS in writing shall qualify as being in effect at the time
these regulations become effective.
[[Page 143]]
(vi) MMS may establish, in appropriate circumstances, reporting
requirements that are different from the requirements of this section.
(2) Non-arm's-length or no contract. (i) With the exception of those
transportation allowances specified in paragraphs (c)(2)(v) and
(c)(2)(vii) of this section, the lessee shall submit an initial Form
MMS-4293 prior to, or at the same time as, the transportation allowance
determined pursuant to a non-arm's-length contract or no contract
situation is reported on Form MMS-4430, Solid Minerals Production and
Royalty Report. The initial report may be based on estimated costs.
(ii) The initial Form MMS-4293 shall be effective for a reporting
period beginning the month that the lessee first is authorized to deduct
a transportation allowance and shall continue until the end of the
calendar year, or until the transportation under the non-arm's-length
contract or the no contract situation terminates, whichever is earlier.
(iii) For calendar-year reporting periods succeeding the initial
reporting period, the lessee shall submit a completed Form MMS-4293
containing the actual costs for the previous reporting period. If the
transportation is continuing, the lessee shall include on Form MMS-4293
its estimated costs for the next calendar year. The estimated
transportation allowance shall be based on the actual costs for the
previous reporting period plus or minus any adjustments that are based
on the lessee's knowledge of decreases or increases that will affect the
allowance. Form MMS-4293 must be received by MMS within 3 months after
the end of the previous reporting period, unless MMS approves a longer
period (during which period the lessee shall continue to use the
allowance from the previous reporting period).
(iv) For new transportation facilities or arrangements, the lessee's
initial Form MMS-4293 shall include estimates of the allowable
transportation costs for the applicable period. Cost estimates shall be
based upon the most recently available operations data for the
transportation system, or, if such data are not available, the lessee
shall use estimates based upon industry data for similar transportation
systems.
(v) Non-arm's-length contract or no contract-based transportation
allowances that are in effect at the time these regulations become
effective will be allowed to continue until such allowances terminate.
For purposes of this section, only those allowances that have been
approved by MMS in writing shall qualify as being in effect at the time
these regulations become effective.
(vi) Upon request by MMS, the lessee shall submit all data used to
prepare its Form MMS-4293. The data shall be provided within a
reasonable period of time, as determined by MMS.
(vii) MMS may establish, in appropriate circumstances, reporting
requirements that are different from the requirements of this section.
(viii) If the lessee is authorized to use its Federal-agency-
approved rate as its transportation cost in accordance with paragraph
(b)(3) of this section, it shall follow the reporting requirements of
paragraph (c)(1) of this section.
(3) MMS may establish reporting dates for individual lessees
different than those specified in this paragraph in order to provide
more effective administration. Lessees will be notified as to any change
in their reporting period.
(4) Transportation allowances must be reported as a separate line
item on Form MMS-4430, unless MMS approves a different reporting
procedure.
(d) Interest assessments for incorrect or late reports and failure
to report. (1) If a lessee deducts a transportation allowance on its
Form MMS-4430 without complying with the requirements of this section,
the lessee shall be liable for interest on the amount of such deduction
until the requirements of this section are complied with. The lessee
also shall repay the amount of any allowance which is disallowed by this
section.
(2) If a lessee erroneously reports a transportation allowance which
results in an underpayment of royalties, interest shall be paid on the
amount of that underpayment.
(3) Interest required to be paid by this section shall be determined
in accordance with 30 CFR 218.202.
[[Page 144]]
(e) Adjustments. (1) If the actual transportation allowance is less
than the amount the lessee has taken on Form MMS-4430 for each month
during the allowance form reporting period, the lessee shall be required
to pay additional royalties due plus interest, computed pursuant to 30
CFR 218.202, retroactive to the first month the lessee is authorized to
deduct a transportation allowance. If the actual transportation
allowance is greater than the amount the lessee has estimated and taken
during the reporting period, the lessee shall be entitled to a credit,
without interest.
(2) The lessee must submit a corrected Form MMS-4430 to reflect
actual costs, together with any payment, in accordance with instructions
provided by MMS.
(f) Other transportation cost determinations. The provisions of this
section shall apply to determine transportation costs when establishing
value using a net-back valuation procedure or any other procedure that
requires deduction of transportation costs.
[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999; 66
FR 45769, Aug. 30, 2001]
Sec. 206.462 [Reserved]
Sec. 206.463 In-situ and surface gasification and liquefaction operations.
If an ad valorem Federal coal lease is developed by in-situ or
surface gasification or liquefaction technology, the lessee shall
propose the value of coal for royalty purposes to MMS. MMS will review
the lessee's proposal and issue a value determination. The lessee may
use its proposed value until MMS issues a value determination.
[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999]
Sec. 206.464 Value enhancement of marketable coal.
If, prior to use, sale, or other disposition, the lessee enhances
the value of coal after the coal has been placed in marketable condition
in accordance 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
[[Page 145]]
seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.; 30 U.S.C. 1001 et
seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 3716 et seq.; 31 U.S.C. 9701; 43
U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C. 1801 et seq.
Source: 53 FR 1225, Jan. 15, 1988, unless otherwise noted.
Subpart A--General Provisions
Sec. 207.1 Required recordkeeping.
(a) The information collection and recordkeeping requirements
contained in this part have been approved by OMB under 44 U.S.C. 3501 et
seq. and assigned OMB Clearance Number 1010-0061. The information
collected will be used to determine a proper transportation allowance
for the cost of transporting royalty oil from the lease to a delivery
point remote from the lease. The information is required in order to
obtain a benefit and is collected in accordance with the Federal Oil and
Gas Royalty Management Act of 1982, 30 U.S.C. 1701 et seq.
(b) Public reporting burden is estimated to average 30 minutes per
year for each record keeper to maintain copies of sales contracts,
agreements, or other documents relevant to the valuation of production.
Send any comments regarding this burden estimate or any other aspect of
this requirement to the Information Collection Clearance Officer,
Minerals Management Service, 381 Elden Street, Herndon, VA 22070, and to
the Office of Information and Regulatory Affairs, Office of Management
and Budget, Paperwork Reduction Project 1010-0061, Washington, DC 20503.
[57 FR 41864, Sept. 14, 1992, as amended at 58 FR 64901, Dec. 10, 1994]
Sec. 207.2 Definitions.
The definitions in part 206 of this title are applicable to this
part.
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
[[Page 146]]
hours to authorized MMS, State or Indian representatives, other MMS or
BLM officials, auditors of the General Accounting Office, or other
persons authorized to receive such documents, or shall be submitted to
MMS within a reasonable period of time, as determined by MMS. Any oral
sales arrangement negotiated by the lessee must be placed in written
form and retained by the lessee. Records shall be retained in accordance
with 30 CFR part 212.
Subpart B--Oil, Gas, and OCS Sulfur, General [Reserved]
Subpart C--Federal and Indian Oil [Reserved]
Subpart D--Federal and Indian Gas [Reserved]
Subpart E--Solid Minerals, General [Reserved]
Subpart F--Coal [Reserved]
Subpart G--Other Solid Minerals [Reserved]
Subpart H--Geothermal Resources [Reserved]
Subpart I--OCS Sulfur [Reserved]
PART 208--SALE OF FEDERAL ROYALTY OIL--Table of Contents
Subpart A--General Provisons
Sec.
208.1 General.
208.2 Definitions.
208.3 Information collection.
208.4 Royalty oil sales to eligible refiners.
208.5 Notice of royalty oil sale.
208.6 General application procedures.
208.7 Determination of eligibility.
208.8 Transportation and delivery.
208.9 Agreements.
208.10 Notices.
208.11 Surety requirements.
208.12 Payment requirements.
208.13 Reporting requirements.
208.14 Civil and criminal penalties.
208.15 Audits.
208.16 How to appeal a contracting officer's decision that you receive.
208.17 Suspensions for national emergencies.
Authority: 5 U.S.C. 301 et seq.; 30 U.S.C. 181 et seq., 351 et seq.,
1701 et seq.; 31 U.S.C. 9701; 41 U.S.C. 601 et seq.; 43 U.S.C. 1301 et
seq., 1331 et seq., and 1801 et seq.
Source: 52 FR 41913, Oct. 30, 1987, unless otherwise noted.
Subpart A--General Provisions
Sec. 208.1 General.
The regulations in this part govern the sale of royalty oil by the
United States to eligible refiners. The regulations apply to royalty oil
from leases on Federal lands onshore and on the Outer Continental Shelf
(OCS).
Sec. 208.2 Definitions.
Allotment means the quantity of royalty oil that DOI determines is
available to each eligible refiner that has applied for a portion of the
total volume of royalty oil offered in a given royalty oil sale.
Application means the formal written request to DOI on Form MMS-4070
by an eligible refiner interested in purchasing a quantity of royalty
oil from the approximate volume announced by DOI in a given ``Notice of
Availability of Royalty Oil.''
Area or Region means the geographic territory having Federal oil and
gas leases over which MMS has jurisdiction, unless the context in which
those words are used indicates that a different meaning is intended.
Contracting officer means the Director, his or her delegate, or the
person designated under a royalty oil purchase contract.
Contracting officer's decision means an MMS order or decision that a
contracting officer issues under this part to a purchaser of oil under a
royalty oil purchase contract.
Delivery point means the point where the lessor, in accordance with
lease terms, directs the lessee to deliver royalty oil to a purchaser.
Title to the royalty oil, or to the quantity thereof in a commingled
stream, passes from the Federal Government to the purchaser at this
designated point, which is specified in the royalty oil contract. For
onshore leases, the delivery point
[[Page 147]]
will be on or adjacent to the lease, except as provided in Sec. 208.8(a)
of this part. In instances where an onshore delivery point is designated
for offshore royalty oil, such point generally will be the first onshore
point where the price of the oil, including transportation costs, can be
determined and where the purchaser can either exchange or take delivery
of the oil. The Government does not guarantee physical access to the oil
at such point.
Director means the Director of MMS, who is responsible for its
overall direction, or his or her delegate(s).
DOI means the Department of the Interior, including the Secretary or
his or her delegate(s).
Eligible refiner means a refiner of crude oil that meets the
following criteria for eligibility to purchase royalty oil:
(1) For the purchase of royalty oil from onshore leases, it means a
refiner that qualifies as a small and independent refiner as those terms
are defined in sections 3(3) and 3(4) of the Emergency Petroleum
Allocation Act, 15 U.S.C. 751 et seq., except that the time period for
determination contained in section 3(3)(A) would be the calendar quarter
immediately preceding the date of the applicable ``Notice of
Availability of Royalty Oil.'' A refiner that, together with all persons
controlled by, in control of, under common control with, or otherwise
affiliated with the refiner, inputs a volume of domestic crude oil from
its own production exceeding 30 percent of its total refinery input of
crude oil is ineligible to participate in royalty oil sales under this
part. Crude oil received in exchange for such refiner's own production
is considered to be that refiner's own production for purposes of this
section.
(2) For the purchase of royalty oil from leases on the OCS, it means
a refiner that qualifies as a small business enterprise under the rules
of the Small Business Administration (13 CFR part 121).
Entitlement means the volume of royalty oil from the Federal
Government's share of production from a Federal lease which a purchaser
is entitled to receive under a royalty oil contract.
Exchange agreement means a written agreement between the purchaser
and another person for the exchange of royalty oil purchased under this
part for other oil on a volume or equivalent value basis.
Fair market value means the value of oil--(1) Computed at a unit
price equivalent to the average unit price at which oil was sold
pursuant to a lease during the period for which any royalty or net
profit share is accrued or reserved to the United States pursuant to
such lease, or
(2) If there were no such sales, or if the Secretary finds that
there were an insufficient number of such sales to equitably determine
such value, computed at the average unit price at which oil was sold
pursuant to other leases in the same region of the OCS during such
period, or
(3) If there were no sales of oil from such region during such
period, or if the Secretary finds that there are an insufficient number
of such sales to equitably determine such value, at an appropriate price
determined by the Secretary.
Federal lease means a contractual agreement with the Federal
Government which authorizes the exploration, development, and production
of oil and gas on Federal lands onshore or on the OCS.
Interim sale means a sale conducted as a result of substantial
additional royalty oil becoming available in a specific area prior to
the scheduled expiration date of royalty oil contracts in effect for
that area.
Lessee means any person to whom the United States issues a lease, or
any person who has been assigned an obligation to make royalty or other
payments required by the lease.
MMS means the Minerals Management Service of the Department of the
Interior.
Notice of Availability of Royalty Oil means a notice published by
DOI in the Federal Register (and in other printed media when
appropriate, such as a newspaper or magazine of general or specialized
circulation) to advise interested parties of the availability of royalty
oil for purchase by eligible refiners and the approximate volume of
royalty oil available to the applicants.
[[Page 148]]
OCS means the Outer Continental Shelf, as defined in 43 U.S.C.
1331(a).
OCSLA means the Outer Continental Shelf Lands Act (43 U.S.C. 1331 et
seq., as amended by 43 U.S.C. 1801 et seq.).
Oil means a mixture of hydrocarbons that existed in the liquid phase
in natural underground reservoirs and remains liquid at atmospheric
pressure after passing through surface separating facilities and is
marketed or used as such. Condensate recovered in lease separators or
field facilities is considered to be oil.
Operator means any person, including a lessee, who has control of or
who manages operations on an oil and gas lease site on Federal onshore
lands or on the OCS.
Payor means any person responsible for reporting royalties from a
Federal lease or leases on Form MMS-2014.
Person means any individual, firm, corporation, association,
partnership, consortium, or joint venture.
Preference eligible refiner means an eligible refiner with at least
one operating refinery which is located within the area designated as
the preference eligible area in the ``Notice of Availability of Royalty
Oil.'' A refiner may be deemed to be a preference eligible refiner if it
owns a refinery located in the preference eligible area which is not
operational if the refiner meets the requirements of Sec. 208.7(g) of
this part.
Purchaser means anyone who acquires royalty oil sold by DOI under
the Federal Government's Royalty-in-Kind (RIK) Program and who has a
contractual obligation under an agreement to purchase royalty oil.
Reallocation means an offering of royalty oil previously allocated
in a specific sale but subsequently turned back to MMS. A reallocation
would only be made if substantial amounts of royalty oil are turned
back.
Refined petroleum product means gasoline, kerosene, distillates
(including Number 2 fuel oil), refined lubricating oils, or diesel fuel.
Royalty oil means that amount of oil that DOI takes in kind in
partial or full satisfaction of a lessee's royalty or net profit share
obligations as determined by whatever lease interest the lessee holds
under an applicable mineral leasing law.
Secretary means the Secretary of the Department of the Interior or
his/her delegate(s).
Section 6 lease means an oil and gas lease originally issued by any
State and currently maintained in effect pursuant to section 6 of the
OCSLA.
Section 8 lease means an oil and gas lease originally issued by the
United States pursuant to section 8 of the OCSLA.
[52 FR 41913, Oct. 30, 1987; 52 FR 45528, Nov. 30, 1987, as amended at
58 FR 64901, Dec. 10, 1993; 64 FR 26251, May 13, 1999]
Sec. 208.3 Information collection.
The information collection requirements contained in this part have
been approved by OMB under 44 U.S.C. 3501 et seq. The form, filing date,
and approved OMB clearance number are identified in 30 CFR 210.10.
[58 FR 64901, Dec. 10, 1993]
Sec. 208.4 Royalty oil sales to eligible refiners.
(a) Determination to take royalty oil in kind. The Secretary may
evaluate crude oil market conditions from time to time. The evaluation
will include, among other things, the availability of crude oil and the
crude oil requirements of the Federal Government, primarily those
requirements concerning matters of national interest and defense. The
Secretary will review these items and will determine whether eligible
refiners have access to adequate supplies of crude oil and whether such
oil is available to eligible refiners at equitable prices. Such
determinations may be made on a regional basis. The determination by the
Secretary shall be published in the Federal Register concurrent with or
included in the ``Notice of Availability of Royalty Oil'' required by 30
CFR 208.5.
(b) Sale to eligible refiners. (1) Upon a determination by the
Secretary under paragraph (a) of this section that eligible refiners do
not have access to adequate supplies of crude oil at equitable prices,
the Secretary, at his or her discretion, may elect to take in kind some
or all of the royalty oil accruing to the United States from oil and gas
leases on Federal lands onshore and on the OCS. The Secretary may
authorize
[[Page 149]]
MMS to offer royalty oil for sale to eligible refiners only for use in
their refineries and not for resale (other than under an exchange
agreement).
(2) All sales of royalty oil from onshore leases will be priced at
the royalty value that would have been determined for that oil pursuant
to 30 CFR part 206 had the royalties been paid in value rather than
taken in kind. All sales of royalty oil from OCS leases will be priced
at the fair market value of the oil including associated transportation
costs to the designated delivery point, if applicable.
(3) An eligible refiner must have a representative at a sale in
order to participate. The Secretary may, at his or her discretion,
establish purchase limitations and withhold any royalty oil from any
offering.
(c) Upon a determination by the Secretary under paragraph (a) of
this section that eligible refiners do have access to adequate supplies
of crude oil at equitable prices, MMS will not take royalties in kind
from oil and gas leases for exclusive sale to such refiners. Such
determinations may be made on a regional basis.
(d) Interim sales. The MMS generally will not conduct interim sales.
However, interim sales may be held at the discretion of the Secretary if
substantial addition royalty oil becomes available. The potentially
eligible refiners, individually or collectively, must submit
documentation demonstrating that adequate supplies of crude oil at
equitable prices are not available for purchase. Although sufficient
documentation must be submitted, it is not mandatory for each
potentially eligible refiner to participate in a submission of such
documentation to be determined eligible. The documentation must be
submitted to MMS for a determination as to whether an interim sale is
needed.
[52 FR 41913, Oct. 30, 1987, as amended at 66 FR 28657, May 24, 2001]
Sec. 208.5 Notice of royalty oil sale.
If the Secretary decides to take royalty oil in kind for sale to
eligible refiners, MMS will issue a ``Notice of Availability of Royalty
Oil'' specifying the manner in which the sale is to be effected, the
approximate quantity of royalty oil to be offered, information required
in applications, the closing date for the receipt of applications for
royalty oil, and other general administrative details concerning the
application, allocation, and contract award process for the royalty oil.
The Notice will describe generally the terms under which the royalty oil
contracts will be awarded and will specify which applicants will be
deemed preference eligible refiners in the sale proceedings. The Notice
will also contain guidelines for reallocation procedures in the event
substantial quantities of royalty oil sold in that specific sale are
subsequently turned back to MMS. Only those purchasers that hold ongoing
contracts from that specific sale will be allowed to participate in any
reallocation, which would be voluntary, and then only if they continue
to meet eligibility requirements as set forth in 30 CFR 208.2 and 208.7.
If a reallocation is held prior to the effective date of the contracts
as specified in the ``Notice of Availability of Royalty Oil'', all
eligible refiners that selected a lease or leases in that specific sale
would be allowed to participate, pursuant to the procedures in the
Notice.
Sec. 208.6 General application procedures.
(a) To apply for the purchase of royalty oil, an applicant must file
a Form MMS-4070 with MMS in accordance with instructions provided in the
``Notice of Availability of Royalty Oil'' and in accordance with any
instructions issued by MMS for completion of Form MMS-4070. The
applicant will be required to submit a letter of intent from a qualified
financial institution stating that it would be granted surety coverage
for the royalty oil for which it is applying, or other such proof of
surety coverage, as deemed acceptable by MMS. The letter of intent must
be submitted with a completed Form MMS-4070.
(b) In addition to any other application requirements specified in
the Notice, the following information is required on Form MMS-4070 at
the time of application:
(1) Name and address of the applicant, the location of the
applicant's refinery or refineries, and disclosure of
[[Page 150]]
the applicant's affiliation with any other persons.
(2) The capacity of the applicant's refineries in barrels of crude
oil throughput per calendar day and a tabulation for the past 12 months
of oil processed for each refinery, identified as to source (from own
production or from other sources).
(3) Identification of any Government royalty oil contracts under
which the applicant is currently receiving royalty oil.
(4) Identification of the locations (area/region and State) where
the applicant proposes to purchase royalty oil, the volume of oil
requested, and the specific refineries in which the oil will be refined.
(5) A certification from the applicant that it is an eligible
refiner for the purchase of Government royalty oil, as defined in
Sec. 208.2 of this part.
[52 FR 41913, Oct. 30, 1987, as amended at 58 FR 64901, Dec. 10, 1993]
Sec. 208.7 Determination of eligibility.
(a) The MMS will examine each application and may request additional
information if the information in the application is inadequate. An
application received after the close of the application period will be
rejected. If additional information is requested by MMS, it must be
received by the time specified or the application will be rejected.
(b) After the close of the application period and the receipt of any
additional requested information, MMS will determine which applicants
may participate in the royalty oil sale and the quantity of royalty oil
which each applicant is authorized to purchase.
(c) When applications are filed by two or more eligible refiners for
the same royalty oil, the oil will be allocated among such applicants on
an equitable basis as determined by MMS. Preference eligible refiners
will be given priority in the allocation procedures in sales and
subsequent reallocations of royalty oil.
(d) No eligible refiner shall be awarded contracts for volumes of
royalty oil that, when added to volumes of other Federal royalty oil
being received, are in excess of 60 percent of the combined refinery
capacity of that refiner.
(e) The MMS may exclude any section 6 lease from a royalty oil sale.
(f) If two or more eligible refiners are related through common
ownership or control or otherwise affiliated, only one of them shall be
entitled to an allotment of royalty oil from a specific sale.
(g) Any applicant whose refinery is not in operation during the 60-
day period prior to the date of the royalty oil sale shall not be
entitled to participate in the sale unless such applicant self-certifies
and demonstrates to the satisfaction of MMS that it will begin
operations by the first month in which oil becomes available under a
royalty oil contract. If operations do not begin by that month, MMS will
terminate the contract.
(h) Applicants or purchasers that have delinquent balances with MMS
as of the date of a royalty oil sale or subsequent reallocation will not
be allowed to participate in that sale or reallocation. If a person
which is controlled by, in control of, under common control with, or
otherwise affiliated with an applicant or purchaser has such delinquent
balances, the applicant or purchaser will not be allowed to participate
in a royalty oil sale or reallocation. To the extent a purchaser or
affiliated person has appealed a billing and posted a surety instrument
in accordance with the contract terms and applicable MMS regulations or
other law, the balance shall not be considered delinquent.
(i) A purchaser must meet the eligibility criteria on the date of
contract issuance. However, a change in a purchaser's eligibility status
during the term of the contract will not affect the purchaser's right to
continue that contract until its term expires, including any extensions
thereof.
[52 FR 41913, Oct. 30, 1987, as amended at 58 FR 64901, Dec. 10, 1993]
Sec. 208.8 Transportation and delivery.
(a) The lessee shall deliver royalty oil from onshore leases to the
purchaser at a point on or adjacent to the lease pursuant to the terms
of the lease. If the purchaser does not have access to its onshore
royalty oil entitlement at facilities on or adjacent to the lease, the
operator of the lease
[[Page 151]]
must designate an alternate delivery point at no additional cost to the
purchaser or the Government. The purchaser must have physical access to
the oil at the alternate delivery point and such point must be approved
by MMS.
(b) The lessee shall deliver royalty oil from section 8 offshore
leases issued after September 1969 at a delivery point to be designated
by MMS. The lessee shall deliver royalty oil from section 8 offshore
leases issued before October 1969 or from section 6 leases at a delivery
point to be designated by the lessee. If the delivery point is on or
immediately adjacent to the lease, the royalty oil will be delivered
without cost to the Federal Government as an undivided portion of
production in marketable condition at pipeline connections or other
facilities provided by the lessee, unless other arrangements are
approved by MMS. If the delivery point is not on or immediately adjacent
to the lease, MMS will reimburse the lessee for the reasonable cost of
transportation to such point in an amount not to exceed the
transportation allowance determined pursuant to 30 CFR part 206. The MMS
will include such transportation costs in the price charged for the oil
taken in kind to reflect the value of the oil at the delivery point.
Arrangements for delivery of the royalty oil from, or exchange of the
oil at, the delivery point, and related transportation costs, are the
responsibility of the purchaser of the royalty oil. In addition, quality
differentials between the royalty oil to which a purchaser is entitled
and the oil which is made available at the delivery point are matters to
be resolved between the purchaser and the operator.
(c) When the purchaser has physical access to the royalty oil at the
delivery point, the lessee shall deliver such oil in marketable
condition at pipeline connections or other facilities designated by MMS.
If the lessee is unable to provide the royalty portion of actual
production from the lease, the lessee must provide crude oil to the
purchaser which is equivalent in volume or value to the royalty oil to
which the purchaser is entitled. The lessee will deliver the royalty oil
to the purchaser during normal operating hours and in reasonable
quantities and intervals. The lessee will make available and the
purchaser will accept delivery of the royalty oil entitlement no later
than the last day of the calendar month immediately following the
calendar month in which the oil was produced. Failure to accept
deliveries shall constitute grounds for the termination of the contract.
(d) Upon termination of deliveries under a royalty oil contract, the
transportation allowance and delivery point designation authorized by
this section no longer will remain in effect.
Sec. 208.9 Agreements.
(a) A purchaser must submit to MMS two copies of any written third-
party agreements, or two copies of a full written explanation of any
oral third-party agreements, relating to the method and costs of
delivery of royalty oil, or crude oil exchanged for the royalty oil,
from the point of delivery under the contract to the purchaser's
refinery. In addition, the purchaser must submit copies of agreements
pertaining to quality differentials which may occur between leases and
delivery points.
(b) A purchaser may not sell royalty oil which it purchases pursuant
to this part except for purposes of an exchange for other crude oil on a
volume or equivalent value basis.
(c) Royalty oil purchased under this part, or crude oil received in
exchange for such royalty oil, must be processed into refined petroleum
products in the purchaser's refinery.
Sec. 208.10 Notices.
(a) The MMS shall notify each operator, by certified mail, of the
Secretary's decision to take royalty oil in kind. This notice shall be
mailed at least 45 days in advance of the effective date of delivery and
will specify delivery points for offshore oil for OCS leases issued
after September 1969.
(b) Deliveries of royalty oil may be partially terminated only with
the written approval of the Director, MMS.
[[Page 152]]
(c) Before terminating the delivery of royalty oil taken in kind,
MMS, if possible, will notify each operator by certified mail of the
change in requirements at least 30 days in advance of the effective
date.
(d) After MMS notification that royalty oil will be taken in kind,
the operator shall be responsible for notifying each working interest on
the Federal lease. As soon as practicable after the date of each royalty
oil sale, MMS will publish in the Federal Register a notice of the
leases from which royalty oil will be taken, the purchasers of the
royalty oil, and the leases from which royalty oil deliveries will be
discontinued on terminated contracts.
(e) A purchaser cannot transfer, assign, or sell its rights or
interest in a royalty oil contract without written approval of the
Director, MMS. If the purchaser changes ownership or its assets are sold
or liquidated for any reason, it cannot transfer, assign, or sell its
rights or interest in the royalty oil contract without written approval
of the Director, MMS. Without express written consent from MMS for a
change in ownership, the royalty oil contract shall be terminated. The
successor company must meet the definition of an eligible refiner in
Sec. 208.2 of this part for MMS to consider assignment of the royalty
oil contract.
Sec. 208.11 Surety requirements.
(a) The eligible purchaser, prior to execution of the contract,
shall furnish an ``MMS-specified surety instrument,'' in an amount equal
to the estimated value of royalty oil that could be taken by the
purchaser in a 99-day period, plus related administrative charges. The
MMS may require the purchaser to increase the amount of the surety
instrument when necessary to protect the Government's interest or may
allow the purchaser to decrease the amount of the surety instrument
where necessary to further the purposes of the Royalty-in-Kind Program.
(b) If a letter of credit is furnished as the surety instrument, it
must be effective for a 9-month period beginning the first day the
royalty oil contract is effective, with a clause providing for automatic
renewal monthly for a new 9-month period. The purchaser or its surety
company may elect not to renew the letter of credit at any monthly
anniversary date, but must notify MMS of its intent not to renew at
least 30 days prior to the anniversary date. The MMS may grant the
purchaser 45 days to obtain a new surety instrument. If no replacement
surety instrument is provided, MMS will terminate the contract effective
at least 6 months prior to the expiration date of the letter of credit.
Notwithstanding the above provisions, the letter of credit also may
contain a clause providing for automatic termination 6 months after the
royalty oil contract terminates. If a certificate of deposit is
furnished as the surety instrument, it must be effective for the life of
the contract plus 6 months after the royalty oil contract terminates.
(c) For the purposes of this section, an ``MMS-specified surety
instrument'' means either: an MMS-specified surety bond, an MMS-
specified irrevocable letter of credit, or a financial institution book-
entry certificate of deposit.
(d) The ``MMS-specified surety instrument'' shall be in a form
specified by MMS instructions or approved by MMS. A bond must be issued
by a qualified surety company that has been approved by the Department
of the Treasury. An irrevocable letter of credit or a certificate of
deposit must be from a financial institution acceptable to MMS. The MMS
will use a bank rating service to determine whether a financial
institution has an acceptable rating to provide a surety instrument
deemed adequate to indemnify the Government from loss or damage.
(e) All surety instruments must be in a form acceptable to MMS and
must include such other specific requirements as MMS may require
adequately to protect the Government's interests.
[58 FR 64901, Dec. 10, 1993]
Sec. 208.12 Payment requirements.
(a) All payments to MMS by a purchaser of royalty oil will be due on
the date and at the location specified in the contract, or, if there is
no contractual provision, as specified by MMS. The purchaser shall
tender all payments to MMS in accordance with 30 CFR 218.51. Payments
made by a payor
[[Page 153]]
pursuant to the requirements of paragraph (b) of this section and
Sec. 208.13 also shall be tendered in accordance with 30 CFR 218.51.
(b)(1) Payments from a purchaser of royalty oil not received by MMS
when due, or that portion of the payment less than the full amount due,
will be subject to a late payment charge equivalent to an interest
assessment on the amount past due for the number of days that the
payment is late at the underpayment rate applicable under section 6621
of the Internal Revenue Code of 1954.
(2) The MMS may assess interest to a payor for any underpayments
which are the result of the payor's late or underreporting, or for
adjustments reported by the payor, or made as a result of audit,
reconciliation, or other procedures. The interest for late payment and
underpayment will be assessed pursuant to 30 CFR 218.54.
(c) If payment for royalty oil is not received by the due date
specified in the contract, a notice of nonreceipt will be sent to the
purchaser by certified mail. If payment is not received by MMS within 15
days from the date of such notice, MMS may cancel the contract and
collect under the MMS-specified surety instrument. See Sec. 208.11.
(d) If the purchaser disagrees with the amount of payment due, it
must pay the amount due as computed by MMS, unless the purchaser appeals
the amount and posts an MMS-specified surety instrument pursuant to the
provisions of 30 CFR part 243. The MMS may, at its discretion, waive the
appeal surety requirements if it determines that the contract surety
instrument is sufficient protection for an amount under appeal.
[52 FR 41913, Oct. 30, 1987, as amended at 64901, Dec. 10, 1993]
Sec. 208.13 Reporting requirements.
If MMS underbills a purchaser under a royalty oil contract because
of a payor's underreporting or failure to report on Form MMS-2014
pursuant to 30 CFR 210.52, the payor will be liable for payment of such
underbilled amounts plus interest if they are unrecoverable from the
purchaser or the surety instrument related to the contract.
[58 FR 64902, Dec. 10, 1993]
Sec. 208.14 Civil and criminal penalties.
Failure to abide by the regulations in this part may result in civil
and criminal penalties being levied on that person as specified in
sections 109 and 110 of the Federal Oil and Gas Royalty Management Act
of 1982, 30 U.S.C. 1719-20, and regulations at 30 CFR part 241. Civil
penalties applicable under the OCSLA and the Mineral Leasing Act of 1920
may also be imposed.
Sec. 208.15 Audits.
Audits of the accounts and books of lessees, operators, payors, and/
or purchasers of royalty oil taken in kind may be made annually or at
such other times as may be directed by MMS. Such audits will be for the
purpose of determining compliance with applicable statutes, regulations,
and royalty oil contracts.
Sec. 208.16 How to appeal a contracting officer's decision that you receive.
If you receive a contracting officer's decision, you may:
(a) Appeal that decision to the Board of Contract Appeals in the
Office of Hearings and Appeals, Office of the Secretary, in accordance
with the procedures provided in 43 CFR part 4, subpart C; or
(b) File an action in the United States Court of Federal Claims.
[64 FR 26251, May 13, 1999]
Sec. 208.17 Suspensions for national emergencies.
The Secretary of the Department of the Interior, upon a
recommendation by the Secretary of Defense or the Secretary of Energy
and with the approval of the President, may suspend operations under
these regulations and suspend royalty oil contracts during a national
emergency declared by the Congress or the President.
[[Page 154]]
PART 210--FORMS AND REPORTS--Table of Contents
Subpart A--General Provisions
Sec.
210.10 Information collection.
210.20 When is electronic reporting required?
210.21 How do you report electronically?
210.22 What are the exceptions to the electronic reporting
requirements?
Subpart B--Oil, Gas, and OCS Sulfur--General
210.50 Required recordkeeping.
210.51 Payor information form.
210.52 Report of sales and royalty remittance.
210.53 Reporting instructions.
210.54 Definitions.
210.55 Special forms or reports.
Subpart C--Federal and Indian Oil [Reserved]
Subpart D--Federal and Indian Gas [Reserved]
Subpart E--Solid Minerals, General
210.200 What is the purpose of this subpart?
210.201 How do I submit Form MMS-4430, Solid Minerals Production and
Royalty Report?
210.202 How do I submit sales summaries?
210.203 How do I submit sales contracts?
210.204 How do I submit facility data?
210.205 Will I need to submit additional documents or evidence to MMS?
210.206 How will information submissions be kept confidential?
Subpart F--Coal [Reserved]
Subpart G--Other Solid Minerals [Reserved]
Subpart H--Geothermal Resources
210.350 Definitions.
210.351 Required recordkeeping.
210.352 Payor information forms.
210.353 Special forms and reports.
210.354 Monthly report of sales and royalty.
210.355 Reporting instructions.
Subpart I--OCS Sulfur [Reserved]
Authority: 5 U.S.C. 301 et seq.; 25 U.S.C. 396, 2107; 30 U.S.C. 189,
190, 359, 1023, 1751(a); 31 U.S.C. 3716, 9701; 43 U.S.C. 1334, 1801 et
seq.; and 44 U.S.C. 3506(a).
Subpart A--General Provisions
Sec. 210.10 Information collection.
(a) Forms--This section identifies required MMS Minerals Revenue
Management forms for reporting sales and royalties, production
information, claiming a processing or transportation allowance, or
claiming a reward for providing original information. The information
collection requirements associated with the forms identified in this
section have been approved by OMB under 44 U.S.C. 3501 et seq. The
forms, filing dates, and approved OMB clearance numbers are summarized
below:
------------------------------------------------------------------------
Form No., name, and filing date OMB No.
------------------------------------------------------------------------
MMS-2014--Report of Sales and Royalty Remittance--Due by the 1010-0022
end of first month following production month for royalty
payment and for rentals no later than anniversary date of
the lease..................................................
MMS-3160--Monthly Report of Operations--Due by the 15th day 1010-0040
of the second month following the production month.........
MMS-4025--Oil and Gas Payor Information Form--Due 30 days 1010-0033
after issuance of a new lease or change to an existing
lease......................................................
MMS-4051--Facility and Measurement Information Form and 1010-0040
Supplement--Due at the request of MMS during the initial
conversion of the facility and measurement device operators
MMS-4053--First Purchaser Report--Due at the request of MMS. 1010-0040
MMS-4054--Oil and Gas Operations Report--Due by the 15th day 1010-0040
of the second month following the production month.........
MMS-4055--Gas Analysis Report--Due by the 15th day of the 1010-0040
second month following the production month................
MMS-4056--Gas Plant Operations Report--Due by the 15th day 1010-0040
of the second month following the production month.........
MMS-4058--Production Allocation Schedule Report--Due by the 1010-0040
15th day of the second month following the production month
MMS-4070--Application of the Purchase of Royalty Oil--Due 1010-0042
prior to the date of sale in accordance with the
instructions in the Notice of Availability of Royalty Oil..
MMS-4109--Gas Processing Allowance Summary Report--Initial 1010-0075
report due within 3 months following the last day of the
month for which an allowance is first claimed, unless a
longer period is approved by MMS...........................
MMS-4110--Oil Transportation Allowance Report--Initial 1010-0061
report due within 3 months following the last day of the
month for which an allowance is first claimed, unless a
longer period is approved by MMS...........................
MMS-4280--Application for Reward for Original Information-- 1010-0076
Due when a reward is claimed for information provided which
may lead to the recovery of royalty or other payments owed
to the United States.......................................
[[Page 155]]
MMS-4292--Coal Washing Allowance Report--Due prior to or at 1010-0074
the same time that the allowance is first reported on Form
MMS-4430 and annually thereafter if the allowance does not
change.....................................................
MMS-4293--Coal Transportation Allowance Report--Due prior to 1010-0074
or at the same time that the allowance is first reported on
Form MMS-4430 and annually thereafter if the allowance does
not change.................................................
MMS-4295--Gas Transportation Allowance Report--Initial 1010-0075
report due within 3 months following the last day of month
for which an allowance is first claimed unless a longer
period is approved by MMS..................................
MMS-4377--Stripper Royalty Rate Reduction Notification--Due 1010-0090
for each 12-month qualifying period that a reduced royalty
rate is granted by the Bureau of Land Management...........
MMS-4430--Solid Minerals Production and Royalty Report--Due 1010-0120
by the end of the month following the month of production
or sale and for other lease financial obligations no later
than the payment date specified in your lease..............
Facility Data--Due monthly or as requested for specific 1010-0120
solid mineral products and lease types; see Sec. 210.204..
Sales Contracts--Due semi-annually or as requested on 1010-0120
certain solid mineral products and lease types; see Sec.
210.203....................................................
Sales Summaries--Due monthly or as requested for specific 1010-0120
solid mineral products and lease types; see Sec. 210.202..
------------------------------------------------------------------------
The information required on the forms identified in the table above is
being collected by the Department of the Interior to meet its
congressionally mandated accounting and auditing responsibilities
relating to Federal and Indian mineral royalty management. The purpose
of the forms and the estimated public reporting burden associated with
each form are described in paragraph (c) of this section. With the
exception of Forms MMS-4109, MMS-4110, MMS-4280, MMS-4292, MMS-4293, and
MMS-4295, the forms are mandatory. Information on Forms MMS-4109, MMS-
4110, MMS-4292, MMS-4293, and MMS-4295 is required to receive a benefit.
Information required on Form MMS-4280 must be provided voluntarily to
claim a reward. Information collected relative to production, royalties,
and other payments due the Government from activities on leased Federal
or Indian land is authorized by the Federal Oil and Gas Royalty
Management Act of 1982, 30 U.S.C. 1701 et seq. for oil and gas
production, and by 30 U.S.C. 189, 30 U.S.C. 359, and 30 U.S.C. 396d for
solid mineral production.
(b) MMS mailing addresses--This paragraph identifies the MMS
address(es) to be used for requesting forms and/or for mailing completed
forms to MMS.
(1) Requests for Forms MMS-2014 or MMS-4070 should be addressed to
the Minerals Management Service, Minerals Revenue Management, P.O. Box
5760, Denver, Colorado 80217-5760. The completed Form MMS-2014 should be
mailed to the Minerals Management Service, Minerals Revenue Management,
P.O. Box 5810, Denver, Colorado 80217-5810. The address to which a
completed Form MMS-4070 should be mailed will be identified in a Federal
Register Notice of Availability of Royalty Oil. (See 30 CFR 208.5.)
(2) Requests for Forms MMS-4025 should be addressed to the Minerals
Management Service, Minerals Revenue Management, P.O. Box 5760, Denver,
Colorado 80217-5760. The completed forms should be mailed to the same
address.
(3) Requests for Forms MMS-3160, MMS-4051, MMS-4052, MMS-4053, MMS-
4054, MMS-4055, MMS-4056, MMS-4057, MMS-4058, or MMS-4061 should be
addressed to the Minerals Management Service, Minerals Revenue
Management, P.O. Box 17110, Denver, Colorado 80217-0110. The completed
forms should be mailed to the same address.
(4) Requests for processing or transportation allowance forms (Forms
MMS-4109, MMS-4110, MMS-4292, MMS-4293, or MMS-4295) should be addressed
to the Minerals Management Service, Minerals Revenue Management, P.O.
Box 25165, Denver, Colorado 80225-0165. The completed allowance forms
should be mailed to the Minerals Management Service, Minerals Revenue
Management, P.O. Box 5200, Denver, Colorado 80217-5200.
(5) Requests for Form MMS-4280 should be addressed to the Minerals
Management Service, Minerals Revenue Management, P.O. Box 25165, Denver,
Colorado 80225-0165. The completed form should be mailed to the same
address. (See 30 CFR 218.57(b)).
(6) If you are not reporting Form MMS-4430 electronically, you may
request blank copies of the form by calling 1-888-201-6416. You must
submit completed Forms MMS-4430 to the address given in Sec. 210.201(c).
[[Page 156]]
(7) If you are not reporting solid minerals sales contracts, sales
summaries, and facility data electronically, you must submit paper
copies to the address given in Sec. 210.202(c).
(8) Reports for oil, gas, and geothermal leases sent by special
courier or overnight mail (excluding U.S. Postal Service Express Mail)
should be addressed to: Minerals Management Service, Minerals Revenue
Management, Building 85, Room A-614, Denver Federal Center, Denver,
Colorado 80225.
(c) Purpose of forms and estimated public reporting burden--This
paragraph describes the purpose of the information being collected and
the estimated public reporting burden associated with the OMB approved
forms identified in paragraph (a) of this section.
(1) MMS-2014--Used monthly to report lease-related transactions
essential for royalty management to determine the correct royalty amount
due, reconcile or audit data, and distribute payments to appropriate
accounts. Public reporting burden for paper submission is estimated to
average 7 minutes to complete each line item on the form, including the
time necessary to assemble data, calculate value and royalty, and enter
data on the form. Companies reporting electronically may average 2
minutes to complete each line item on the form. Comments submitted
relative to this information collection should reference the information
collection titled Report of Sales and Royalty Remittance, OMB Control
Number 1010-0022.
(2) MMS-3160--Used by onshore oil and gas lease operators to report
monthly oil and gas production to MMS. Public reporting burden for paper
submission is estimated to average 15 minutes per form, including the
time necessary to assemble data, ensure that production and disposition
numbers are accurate, and enter data on the form. Companies reporting
electronically may average 7.5 minutes per month to complete the form.
Comments submitted relative to this information collection should
reference the information collection titled PAAS Oil and Gas Reports,
OMB Control Number 1010-0040.
(3) MMS-4025--This form is used to establish a data base of payor
accounts for oil and gas leases on Federal or Indian lands, reporting
changes in payor accounts, and notifying MMS of the products on which
royalties will be paid. Public reporting burden is estimated to average
30 minutes per form, including time spent reading instructions,
completing, and mailing the form. Comments submitted relative to this
information collection should reference Paperwork Reduction Project
1010-0033.
(4) MMS-4051--Used to establish a reference data base identifying
the facilities where oil and gas production is stored or processed and
the metering points where production is measured for sale or transfer.
Public reporting burden is estimated to average 30 minutes per form for
facility operators to review and update the data base. Comments
submitted relative to this information collection should reference
Paperwork Reduction Project 1010-0040.
(5) MMS-4053--Designed as an audit tool to be used to confirm sales
data. Public reporting burden is estimated to average 30 minutes per
form, including time spent reading instructions, completing, and mailing
the form. Comments submitted relative to this information collection
should reference Paperwork Reduction Project 1010-0040.
(6) MMS-4054--This three-part form identifies all oil and gas lease
production from Federal and Indian lands. MMS uses information from this
form to track oil and gas from the point of production to the point of
first sale or other disposition. Respondents will generally not use all
three parts of the form. Public reporting burden for paper submission is
estimated to average 30 minutes per month, including the time necessary
to assemble data, ensure that production and disposition numbers are
accurate, and enter data on the form. Companies reporting electronically
may average 15 minutes per month to complete the form. Comments
submitted relative to this information collection should reference the
information collection titled PAAS Oil and Gas Reports, OMB Control
Number 1010-0040.
(7) MMS-4055--This report identifies the separate components of
natural gas production. It is submitted quarterly or semiannually by
lease operators
[[Page 157]]
when gas production is processed before royalty value has been
determined. Public reporting burden is estimated to average 15 minutes
per form including time required gathering data, completing, and mailing
the form. Comments submitted relative to this information collection
should reference Paperwork Reduction Project 1010-0040.
(8) MMS-4056--Submitted monthly by gas plant operators to identify
components and disposition of natural gas from Federal and Indian
leases. Public reporting burden is estimated to average 30 minutes per
form, including time required gathering data, completing, and mailing
the form. Comments submitted relative to this information collection
should reference Paperwork Reduction Project 1010-0040.
(9) MMS-4058--Submitted monthly by operators of the facilities and
measurement points where production from a Federal or Indian lease is
commingled with production from other sources before it is measured for
royalty determination. The data reported is used to determine whether
sales reported by lessees are reasonable. Public reporting burden is
estimated to average 15 minutes per form, including time required
gathering data, completing, and mailing the form. Comments submitted
relative to this information collection should reference Paperwork
Reduction Project 1010-0040.
(10) MMS-4070--After publication in the Federal Register of a Notice
of Availability of Royalty Oil, refiners interested in the purchase of
royalty oil should submit their applications using this form. The
information collected is used by MMS to determine if the applicant meets
eligibility requirements to contract to purchase the oil. Public
reporting burden is estimated to average 1 hour per form, including time
required gathering data, completing, and mailing the form. Comments
submitted relative to this information collection should reference
Paperwork Reduction Project 1010-0042.
(11) MMS-4109--Used to claim an allowance for the reasonable, actual
costs of removing hydrocarbon and nonhydrocarbon elements or compounds
from the gas streams. Public reporting burden varies depending on the
type of contract involved. Under an arm's-length contract, burden is
estimated to average 1 hour for the submission of page 1 and schedule 1
of the form requiring the lessee's name and address, payor code, plant
name, accounting identification number, product code, and selling
arrangement. Nonarm's-length contract claims require completion of all
pages of the form including calculations of allowable operating and
maintenance costs, overhead, depreciation, and return on undepreciated
capital investment. Public reporting burden is estimated to average 10
hours to complete the entire form. Comments submitted relative to this
information collection should reference Paperwork Reduction Project
1010-0075.
(12) MMS-4110--Used to claim an allowance for expenses incurred by a
lessee in transporting oil from the lease site to a point remote from
the lease where value is determined. Public reporting burden varies
depending on the type of contract involved. Under an arm's-length
contract, burden is estimated to average 2 hours for the submission of
page 1 and schedule 1 of the form requiring the lessee's name and
address, payor code, accounting identification number, product code, and
selling arrangement. Nonarm's-length contract claims require completion
of all pages of the form including calculations of allowable operating
and maintenance costs, overhead, depreciation, and return on
undepreciated capital investment. Public reporting burden is estimated
to average 5 hours to complete the entire form. Comments submitted
relative to this information collection should reference Paperwork
Reduction Project 1010-0061.
(13) MMS-4280--This form is used to claim a reward for information
leading to the recovery of payments owed to the United States from oil
and gas leases on Federal land or the Outer Continental Shelf. Claimants
must provide name, address, Social Security number, and a brief
description of the violation being reported. Public reporting burden is
estimated to average 30 minutes to complete this form. Comments
submitted relative to this information collection should reference
Paperwork Reduction Project 1010-0076.
[[Page 158]]
(14) MMS-4292--This form is used to claim an allowance for the
reasonable, actual costs incurred to wash coal. Public reporting burden
varies depending on the type of contract involved. Under an arm's-length
contract, burden is estimated to average 1 hour for the submission of
page 1 of the form requiring the lessee's name and address, payor code,
accounting identification number, product code, and selling arrangement.
Nonarm's-length contract claims require completion of all pages of the
form including calculations of allowable operating and maintenance
costs, overhead, depreciation, and return on undepreciated capital
investment. Public reporting burden is estimated to average 40 hours to
complete the entire form. Comments submitted relative to this
information collection should reference Paperwork Reduction Project
1010-0074.
(15) MMS-4293--Used to claim an allowance for the reasonable, actual
costs of transporting coal to a sales point or a washing facility remote
from the mine or lease. Public reporting burden varies depending on the
type of contract involved. Under an arm's-length contract, burden is
estimated to average 1 hour for the submission of page 1 of the form
requiring the lessee's name and address, payor code, accounting
identification number, product code, and selling arrangement. Nonarm's-
length contract claims require completion of all pages of the form
including calculations of allowable operating and maintenance costs,
overhead, depreciation, and return on undepreciated capital investment.
Public reporting burden is estimated to average 40 hours to complete the
entire form. Comments submitted relative to this information collection
should reference Paperwork Reduction Project 1010-0074.
(16) MMS-4295-- This form is used to claim an allowance for the
reasonable, actual costs of transporting gas from the lease to the point
of first sale. Public reporting burden varies depending on the type of
contract involved. Under an arm's-length contract, burden is estimated
to average 1 hour for the submission of page 1 and schedule 1 of the
form requiring the lessee's name and address, payor code, accounting
identification number, product code, and selling arrangement. Nonarm's-
length contract claims require completion of all pages of the form
including calculations of allowable operating and maintenance costs,
overhead, depreciation, and return on undepreciated capital investment.
Public reporting burden is estimated to average 3 hours to complete the
entire form. Comments submitted relative to this information collection
should reference Paperwork Reduction Project 1010-0075.
(17) MMS-4377-- This form must be submitted by operators of stripper
oil properties to notify MMS of reduced royalty rates granted by the
Bureau of Land Management under 43 CFR 3103.4-1 for each 12-month
qualifying period. Reporting burden is estimated to require an average
of 30 minutes per form to supply the operator name, lease and agreement
numbers, calculated and current royalty rate, and the period covered.
Comments submitted relative to this information collection should
reference Paperwork Reduction Project 1010-0090.
(18) MMS-4430--Submitted monthly to report production from and
royalty due on all Federal and Indian solid minerals leases (see
Sec. 210.201). MMS uses the data to distribute payments to appropriate
recipients and to determine if lessees properly paid lease obligations.
Public reporting burden is estimated to be 20 minutes per month per
reporter. Comments relating to this information collection should
reference OMB Control Number 1010-0120.
(19) Facility data--Submitted monthly by operators of wash plant,
refining, ore concentration, or other processing facilities for specific
solid minerals produced from specific Federal and Indian lease types or
when otherwise requested by MMS (see Sec. 210.204). MMS uses the data to
assure that Federal or Indian lease processed production (the output of
process plants) is consistent with the input of raw production. Public
reporting burden is estimated to be approximately 15 minutes per
reporter per month to compile in-house formatted information and submit
that information electronically. Comments relating to this information
collection should reference OMB Control Number 1010-0120.
[[Page 159]]
(20) Sales contracts--Submitted semi-annually by producers of
specific solid mineral products on specific Federal and Indian lease
types or when otherwise requested by MMS (see Sec. 210.203). MMS uses
contracts, agreements and contract amendments for compliance purposes
including, but not limited to, identifying valuation issues and
establishing selling arrangement relationships. Public reporting burden
is estimated to be 2 hours per reporter per year to compile and submit
contracts and contract amendments. Comments relating to this information
collection should reference OMB Control Number 1010-0120.
(21) Sales summaries--Submitted monthly by producers of specific
solid minerals from specific Federal and Indian lease types or when
otherwise requested by MMS (see Sec. 210.202). The MMS uses these data
for compliance purposes including, but not limited to, assuring that
sales volumes and values are properly attributed or allocated to Federal
or Indian leases. Public reporting burden is estimated to be 15 minutes
per month for each reporter to compile in-house formatted sales
information and submit that information electronically. Comments
relating to this information collection should reference OMB Control
Number 1010-0120.
(d) Comments on burden estimates. Send comments on the accuracy of
this burden estimate or suggestions on reducing this burden to the
Minerals Management Service, Attention: Information Collection Clearance
Officer, (OMB Control Number 1010-0120 (insert appropriate OMB Control
Number), Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240. An
agency may not conduct or sponsor, and a person is not required to
respond to, a collection of information unless it displays a currently
valid OMB Control Number.
[57 FR 41864, Sept. 14, 1992, as amended at 64 FR 38122, July 15, 1999;
66 FR 45769, Aug. 30, 2001]
Sec. 210.20 When is electronic reporting required?
(a) You must submit Forms MMS-2014 and MMS-4054 to MMS
electronically. You must begin reporting electronically according to the
following timetable unless you qualify for the exceptions to electronic
reporting listed in Sec. 210.22:
------------------------------------------------------------------------
Then, you must submit that
If you report the following number of form electronically
lines each month on a required form . . . beginning . . .
------------------------------------------------------------------------
(1) 6 or more............................. November 1, 1999.
(2) 4-5................................... November 1, 2000.
(3) 1-3................................... November 1, 2001.
------------------------------------------------------------------------
(b) See Sec. 218.40(c) for the definition of a royalty report line
on Form MMS-2014 and Sec. 216.40(c) for the definition of a production
report line on Form MMS-4054; and
(c) For purposes of this part, multiple submissions of the same form
in one month equals one form.
[64 FR 38122, July 15, 1999]
Sec. 210.21 How do you report electronically?
(a) You may use any of the following electronic media types, unless
MMS instructs you differently:
(1) Electronic Data Interchange (EDI) 1--The inter-
organizational, computer-to-computer exchange of structured information
in a standard, machine-processable format;
---------------------------------------------------------------------------
\1\ MMS has developed security measures, authentication procedures,
and automated acknowledgments for this electronic media type.
---------------------------------------------------------------------------
(2) Electronic Mail (e-mail) 1--Any communication service
used to electronically transmit and store messages and attach files. MMS
has three electronic file options:
(i) Template--MMS-provided software that generates blank forms on a
personal computer to assist companies in preparing MMS regulatory
reports (this option is not available for Form MMS-4054);
(ii) Comma Separated Values (CSV)--A file format where attribute
fields are separated by commas; and
(iii) American Standard Code for Information Interchange (ASCII)--A
file format of fixed-length records with fixed-length attribute fields;
(3) Reporter-Prepared Diskette (3\1/2\ inch)--A data storage medium
used to transmit report data using one of the following file formats:
(i) Template;
(ii) CSV; and
(iii) ASCII;
[[Page 160]]
(4) Magnetic or Cartridge Tape--A data storage medium used to
transmit report data in an ASCII file format.
(b) MMS prefers that you use the media types in the order presented
in paragraph (a) of this section to the extent it is cost effective and
practical. As technology changes, MMS will consider other media types
and the order of MMS preference may change. Refer to our electronic
commerce brochure for the most current reporting options. You can
receive a copy of our brochure by calling your MMS representative or by
accessing our Internet site at www.rmp.mms.gov.
(c) Before you may begin reporting electronically:
(1) You must submit an electronic sample of your report for MMS
approval using the MMS-supplied electronic reporting guidelines;
(2) MMS must notify you that your sample report has been approved;
(3) MMS must assign you a sender identification number and security
code for any EDI transmissions; and
(4) MMS must assign you an originating address and compression
software password for any e-mail transmissions.
[64 FR 38123, July 15, 1999]
Sec. 210.22 What are the exceptions to the electronic reporting requirements?
MMS will allow the following grace periods and exceptions to the
electronic reporting requirements in Sec. 210.20:
(a) If you become a new MMS reporter after any of the dates you are
required to submit electronic reports under Sec. 210.20(a), you have 3
months from the day your first report is due to begin reporting
electronically;
(b) If you exceed the maximum number of lines you are allowed to
report on paper under Sec. 210.20(a), you have 3 months from the last
day of the month in which you exceeded the line limit to begin reporting
electronically;
(c) You are not required to report electronically if you report only
rent, minimum royalty, or other annual obligations on the Form MMS-2014;
and
(d) You are not required to report electronically if you are a small
business as defined by the U.S. Small Business Administration, and you
have no computer, no resources to purchase a computer or contract with
an electronic reporting service, nor access to a computer at a local
library or other public facility.
[64 FR 38123, July 15, 1999]
Subpart B--Oil, Gas, and OCS Sulfur--General
Authority: The Federal Oil and Gas Royalty Management Act of 1982
(30 U.S.C. 1701 et seq.).
Source: 49 FR 37345, Sept. 21, 1984, unless otherwise noted.
Sec. 210.50 Required recordkeeping.
Information required by the MMS shall be filed using the forms
prescribed in this subpart, which are available from MMS. Records may be
maintained in microfilm, microfiche, or other recorded media that is
easily reproducible and readable.
Sec. 210.51 Payor information form.
The Payor Information Form (Form MMS-4025) must be filed for each
Federal or Indian lease on which royalties are paid. Where specifically
determined by MMS, Form MMS-4025 is also required for all Federal leases
on which rent is due. The completed form must be filed by the party who
is making the rent or royalty payment (payor) for each revenue source.
Form MMS-4025 must be filed no later than 30 days after issuance of a
new lease or a modification to an existing lease which changes the
paying responsibility on the lease.
Sec. 210.52 Report of sales and royalty remittance.
(a) You must submit a completed Form MMS-2014 (Report of Sales and
Royalty Remittance) to MMS with:
(1) All royalty payments; and,
(2) Rents on nonproducing leases, where specified.
(b) When you submit Form MMS-2014 data electronically, you must not
submit the form itself.
(c) Completed Forms MMS-2014 for royalty payments are due by the end
of the month following the production month.
[[Page 161]]
(d) Where applicable, completed Forms MMS-2014 for rental payments
are due no later than the anniversary date of the lease.
(e) This section does not prohibit you from making early payments
voluntarily.
[64 FR 38123, July 15, 1999]
Sec. 210.53 Reporting instructions.
(a) Specific guidance on how to prepare and submit required
information collection reports and forms to MMS is contained in an MMS
``Oil and Gas Payor Handbook,'' a ``Production Accounting and Auditing
System Reporter Handbook,'' and a ``PAAS Onshore Oil and Gas Reporter
Handbook.'' The Payor Handbook is available from the Minerals Management
Service, Royalty Management Program, P.O. Box 5760, Denver, Colorado
80217-5760. The Reporter Handbooks are available from the Minerals
Management Service, Royalty Management Program, P.O. Box 17110, Denver,
Colorado 80217-0110.
(b) Royalty payors or production reporters should refer to these
handbooks for specific guidance with respect to oil and gas reporting
requirements. If additional information is required, the payor or
reporter should contact the MMS at the above address. The appropriate
telephone numbers are listed in the handbooks.
[51 FR 45882, Dec. 23, 1986, as amended at 53 FR 16412, May 9, 1988; 57
FR 41867, Sept. 14, 1992; 58 FR 64902, Dec. 10, 1993]
Sec. 210.54 Definitions.
Terms used in this subpart shall have the same meaning as in 30
U.S.C. 1702.
[49 FR 37345, Sept. 21, 1984. Redesignated at 51 FR 45882, Dec. 23,
1986]
Sec. 210.55 Special forms or reports.
(a) MMS may require you to submit additional information, forms, or
reports other than those specifically referred to in this subpart. MMS
will give you instructions for providing such information or filing such
reports or forms. MMS will make requests for additional information,
forms, or reports under this section in conformity with the Paperwork
Reduction Act of 1995, 44 U.S.C. 3501, and other applicable laws.
(b) If you file a Form MMS-4025, Payor Information Form (PIF) under
Sec. 210.51, you must provide the following information to MMS upon
request for each PIF:
(1) The AID number for the lease;
(2) The name, address, Taxpayer Identification Number (TIN), and
phone number of the person for whom you are reporting and paying
royalties or making other payments under the PIF;
(3) Whether the person you named in paragraph (b)(2) of this section
with respect to the lease for which you filed the PIF is a:
(i) Lessee of record (record title owner);
(ii) Operating rights owner (working interest owner); or
(iii) Operator;
(4) The name, address, and phone number of the individual to contact
for the person you named in paragraph (b)(2) of this section;
(5) Your TIN; and
(6) Whether you are the Designee of the person you named in
paragraph (b)(2) of this section under 30 U.S.C. 1712(a), and, if so:
(i) The date your designation became effective; and
(ii) The date your designation terminates, if applicable; and
(iii) A copy of the written designation;
(c) If you have been identified under paragraph (b)(2) of this
section, you must provide the following information to MMS upon request:
(1) Confirmation that you are the person identified under paragraph
(b)(2) of this section;
(2) Confirmation that the person identified in paragraph (b)(6) of
this section is your designee; and
(3) A designation under Sec. 218.52 of this title if the person
identified in paragraph (b)(6) of this section is not your Designee, and
if you are not reporting and paying royalties and making other payments
to MMS.
[62 FR 42066, Aug. 5, 1997]
Subpart C--Federal and Indian Oil [Reserved]
[[Page 162]]
Subpart D--Federal and Indian Gas [Reserved]
Subpart E--Solid Minerals, General
Source: 66 FR 45771, Aug. 30, 2001, unless otherwise noted.
Sec. 210.200 What is the purpose of this subpart?
This subpart explains your reporting requirements if you produce
coal or other solid minerals from Federal or Indian leases. Included are
your requirements for reporting production, sales, and royalties.
Sec. 210.201 How do I submit Form MMS-4430, Solid Minerals Production
and Royalty Report?
(a) What to submit. (1) You must submit a completed Form MMS-4430
for--
(i) Production of all coal and other solid minerals from any Federal
or Indian lease;
(ii) Sale of any such mineral;
(iii) Any such mineral held in stockpile or inventory; and
(iv) Payment of rents (other than those for which you receive from
MMS a Courtesy Notice as defined in Sec. 218.51(a) of this chapter),
minimum royalty, deferred bonus, advance royalty, minimum royalty
payable in advance, settlements, recoupments, and other financial
obligations.
(2) You must submit a completed Form MMS-4430 for any product you
sell from a remote storage site. If you sell from five or fewer remote
storage sites, you must report sales from each site on separate Forms
MMS-4430. If you sell from more than five remote storage sites, you must
total the data from all sites and report the summarized data on one Form
MMS-4430.
(3) Instructions for completing and submitting Form MMS-4430 are
available on our Internet reporting web site or you may contact us toll
free at 1-888-201-6416.
(b) When to submit. (1) Unless your lease terms specify a different
frequency for royalty payments, you must submit your Form MMS-4430 on or
before the end of the month following the month in which you produce any
solid mineral, sell any solid mineral, or hold any solid mineral
production in stockpile or inventory. However, if the last day of the
month falls on a weekend or holiday, your Form MMS-4430 is due on the
next business day.
(2) If your lease terms specify a different frequency for royalty
payment, then you must submit your Form MMS-4430 on or before the date
on which you must pay royalty under the terms of the lease.
(3) You must submit your Form MMS-4430 for payment of rents (other
than those for which you receive from MMS a Courtesy Notice as defined
in Sec. 218.51(a) of this chapter), minimum royalty, deferred bonus,
advance royalty, minimum royalty payable in advance, settlements,
recoupments, and other financial obligations on or before the date on
which you must pay those obligations under the terms of the lease.
(4) If the information on a previously reported Form MMS-4430 is no
longer correct, you must submit a revised Form MMS-4430 by the last day
of the month in which you learn that the previously reported information
is no longer correct, except when the last day of the month falls on a
weekend or holiday. If the last day of the month falls on a weekend or
holiday, your revised Form MMS-4430 is due on the first business day of
the following month.
(c) How to submit. (1) You must submit Form MMS-4430 electronically
using our Internet reporting web site unless you meet the conditions in
paragraph (c)(2). We will provide written instructions and a valid login
and password before you begin reporting.
(2) You are not required to report electronically if you are a small
business as defined by the U.S. Small Business Administration (13 CFR
121.201) and you have no computer, no plans to purchase a computer, and
no contract with an electronic reporting service.
(3) If you do not report electronically, you must submit the
completed Form MMS-4430 to us at one of the following addresses, unless
MMS publishes notice in the Federal Register giving a different address:
(i) For U.S. Postal Service regular mail or Express Mail: Minerals
Management
[[Page 163]]
Service, Minerals Revenue Management, P.O. Box 5810, Denver, Colorado
80217-5810; or
(ii) For courier service or overnight mail (excluding Express Mail):
Minerals Management Service, Minerals Revenue Management, Building 85,
Denver Federal Center, Room A-614, Denver, Colorado 80225.
[66 FR 45771, Aug. 30, 2001; 66 FR 50827, Oct. 5, 2001]
Sec. 210.202 How do I submit sales summaries?
(a) What to submit. (1) You must submit sales summaries for all coal
and other solid minerals produced from Federal and Indian leases and for
any remote storage site from which you sell Federal or Indian solid
minerals. You do not have to submit a sales summary for those months in
which you do not sell any Federal or Indian production.
(2) If you sell from five or fewer remote storage sites, you must
submit a sales summary for each site. If you sell from more than five
remote storage sites, you may total the data from all sites and submit
the summarized data as one sales summary. The details you report on the
sales summary are for the same sales reported on Form MMS-4430.
(3) Use the following table to determine the time frames for
submitting sales summaries and the data elements you must include. Your
submitted sales summaries must include the following data but may be
internally generated documents from your own records. You do not need to
re-format them before submitting them to us:
--------------------------------------------------------------------------------------------------------------------------------------------------------
All other leases All other leases
Data element Coal Sodium/potassium Western phosphate Metals with ad valorem with no ad valorem
royalty terms royalty terms
--------------------------------------------------------------------------------------------------------------------------------------------------------
(i) Purchaser Name or Unique Monthly........... Monthly........... Monthly........... Monthly........... Monthly........... As Requested.
Identification.
(ii) Sales Units................ Monthly........... Monthly........... Monthly........... Monthly........... Monthly........... Monthly.
(iii) Gross Proceeds............ Monthly........... Monthly........... Not Required...... Monthly........... Monthly........... Not Required.
(iv) Processing or washing costs Monthly........... Monthly........... Not Required...... Monthly........... Monthly........... Not Required.
(v) Transportation costs........ Monthly........... Monthly........... Not Required...... Monthly........... Monthly........... Not Required.
(vi) Name of product type sold.. Not Required...... Monthly........... Not Required...... Monthly........... Monthly........... As Requested.
(vii) Btu/lb.................... Monthly........... Not Required...... Not Required...... Not Required...... Not Required...... Not Required.
(viii) Ash %.................... Monthly........... Not Required...... Not Required...... Not Required...... Not Required...... Not Required.
(ix) Sulfur %................... Monthly........... Not Required...... Not Required...... Not Required...... Not Required...... Not Required.
(x) lbs SO2..................... Monthly........... Not Required...... Not Required...... Not Required...... Not Required...... Not Required.
(xi) Moisture %................. Monthly........... Not Required...... Monthly........... Not Required...... Not Required...... Not Required.
(xii) By-product Units.......... Not Required...... As Requested...... Monthly........... As Requested...... As Requested...... Not Required.
(xiii) P2O5 %................... Not Required...... Not Required...... Monthly........... Not Required...... Not Required...... Not Required.
(xiv) Size...................... Not Required...... Not Required...... Not Required...... Not Required...... As Requested...... Not Required.
(xv) Net Smelter Return data.... Not Required...... Not Required...... Not Required...... Monthly........... Not Required...... Not Required.
(xvi) Other Data e.g., Royalty As Requested...... Monthly........... As Requested...... As Requested...... As Requested...... As Requested.
Calculation Worksheet.
--------------------------------------------------------------------------------------------------------------------------------------------------------
(b) When to submit. (1) For leases with ad valorem royalty terms
(that is, leases for which royalty is a percentage of the value of
production), you must submit your sales summaries monthly at the same
time you submit Form MMS-4430. You do not have to submit a sales summary
for any month in which you did not sell Federal or Indian production.
(2) For leases with no ad valorem royalty terms (that is, leases in
which the royalty due is not a function of the value of production, such
as cents-per-ton or dollars-per-unit), you must submit monthly sales
summaries only if we specifically request you to do so.
[[Page 164]]
(c) How to submit. (1) You should provide the sales summary data via
electronic mail where possible. We will provide instructions and the
proper email address for these submissions.
(2) If you submit sales summaries by paper copy, mail them to one of
the following addresses, unless MMS publishes notice in the Federal
Register giving a different address:
(i) For U.S. Postal Service regular mail or Express Mail: Minerals
Management Service, Minerals Revenue Management, Solid Minerals and
Geothermal Compliance and Asset Management, P.O. Box 25165, MS 390G1,
Denver, Colorado 80225-0165.
(ii) For courier service or overnight mail (excluding Express Mail):
Minerals Management Service, Solid Minerals and Geothermal Compliance
and Asset Management, 12600 West Colfax Avenue, Suite C-100, Lakewood,
Colorado 80215.
Sec. 210.203 How do I submit sales contracts?
(a) What to submit. You must submit sales contracts, agreements, and
contract amendments for the sale of all coal and other solid minerals
produced from Federal and Indian leases with ad valorem royalty terms.
(b) When to submit. (1) For coal and metal production, you must
submit the required documents semi-annually, no later than March 30 and
September 30 of each year.
(2) For sodium, potassium, and phosphate production, and production
from any other lease with ad valorem royalty terms, you must submit the
required documents only if you are specifically requested to do so.
(c) How to submit. You must submit complete copies of the sales
contracts and amendments to us at the applicable address given in
Sec. 210.202(c)(2), unless MMS publishes notice in the Federal Register
giving a different address.
Sec. 210.204 How do I submit facility data?
(a) What to submit. (1) You must submit facility data if you operate
a wash plant, refining, ore concentration, or other processing facility
for any coal, sodium, potassium, metals, or other solid minerals
produced from Federal or Indian leases with ad valorem royalty terms,
regardless of whether the facility is located on or off the lease.
(2) You do not have to submit facility data for those months in
which you do not process solid minerals produced from Federal or Indian
leases and do not have any such minerals in stockpile inventory.
(3) You must include in your facility data all production processed
in the facility from all properties, not just production from Federal
and Indian leases.
(4) Facility data submissions must include the following minimum
information:
(i) Identification of your facility;
(ii) Mines served;
(iii) Input quantity;
(iv) Input quality or ore grade (except for coal);
(v) Output quantity; and
(vi) Output quality or product grades.
(5) Your submitted facility data may be internally generated
documents from your own records. You do not need to re-format them
before submitting them to us.
(b) When to submit. You must submit your facility data monthly at
the same time you submit your Form MMS-4430.
(c) How to submit. (1) You should provide the facility data via
electronic mail where possible. We will provide instructions and the
proper email address for these submissions before you begin reporting.
(2) If you submit facility data by paper copy, send it to the
applicable address given in Sec. 210.202(c)(2).
Sec. 210.205 Will I need to submit additional documents or evidence to MMS?
(a) Federal and Indian lease terms allow us to request detailed
statements, documents, or other evidence necessary to verify compliance
with lease terms and conditions and applicable rules.
(b) We will request this additional information as we need it, not
as a regular submission.
Sec. 210.206 How will information submissions be kept confidential?
Information submitted under this part that constitutes trade secrets
or
[[Page 165]]
commercial and financial information that is identified as privileged or
confidential, or that is exempt from disclosure under the Freedom of
Information Act, 5 U.S.C. 552, shall not be available for public
inspection or made public or disclosed without the consent of the
lessee, except as otherwise provided by law or regulation.
Subpart F--Coal [Reserved]
Subpart G--Other Solid Minerals [Reserved]
Subpart H--Geothermal Resources
Source: 56 FR 57286, Nov. 8, 1991, unless otherwise noted.