30 CFR Part 1206

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Title 30: Mineral Resources
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PART 1206—PRODUCT VALUATION

Section Contents

Subpart A—General Provisions
§ 1206.10 Information collection.
Subpart B—Indian Oil
§ 1206.50 What is the purpose of this subpart?
§ 1206.51 What definitions apply to this subpart?
§ 1206.52 How do I calculate royalty value for oil that I or my affiliate sell(s) or exchange(s)
under an arm's-length contract?
§ 1206.53 How do I determine value for oil that I or my affiliate do(es) not sell under an
arm's-length contract?
§ 1206.54 How do I fulfill the lease provision regarding valuing production on the basis of the
major portion of like-quality oil?
§ 1206.55 What are my responsibilities to place production into marketable condition and to
market the production?
§ 1206.56 Transportation allowances—general.
§ 1206.57 Determination of transportation allowances.
§ 1206.58 What must I do if ONRR finds that I have not properly determined value?
§ 1206.59 May I ask ONRR for valuation guidance?
§ 1206.60 What are the quantity and quality bases for royalty settlement?
§ 1206.61 What records must I keep and produce?
§ 1206.62 Does ONRR protect information I provide?
Subpart C—Federal Oil
§ 1206.100 What is the purpose of this subpart?
§ 1206.101 What definitions apply to this subpart?
§ 1206.102 How do I calculate royalty value for oil that I or my affiliate sell(s) under an arm'slength contract?
§ 1206.103 How do I value oil that is not sold under an arm's-length contract?
§ 1206.104 What publications are acceptable to ONRR?
§ 1206.105 What records must I keep to support my calculations of value under this
subpart?
§ 1206.106 What are my responsibilities to place production into marketable condition and to
market production?
§ 1206.107 How do I request a value determination?

§ 1206.108 Does ONRR protect information I provide?
§ 1206.109 When may I take a transportation allowance in determining value?
§ 1206.110 How do I determine a transportation allowance under an arm's-length
transportation contract?
§ 1206.111 How do I determine a transportation allowance if I do not have an arm's-length
transportation contract or arm's-length tariff?
§ 1206.112 What adjustments and transportation allowances apply when I value oil
production from my lease using NYMEX prices or ANS spot prices?
§ 1206.113 How will ONRR identify market centers?
§ 1206.114 What are my reporting requirements under an arm's-length transportation
contract?
§ 1206.115 What are my reporting requirements under a non-arm's-length transportation
arrangement?
§ 1206.116 What interest applies if I improperly report a transportation allowance?
§ 1206.117 What reporting adjustments must I make for transportation allowances?
§ 1206.119 How are royalty quantity and quality determined?
§ 1206.120 How are operating allowances determined?
Subpart D—Federal Gas
§ 1206.150
§ 1206.151
§ 1206.152
§ 1206.153
§ 1206.154
§ 1206.155
§ 1206.156
§ 1206.157
§ 1206.158
§ 1206.159
§ 1206.160

Purpose and scope.
Definitions.
Valuation standards—unprocessed gas.
Valuation standards—processed gas.
Determination of quantities and qualities for computing royalties.
Accounting for comparison.
Transportation allowances—general.
Determination of transportation allowances.
Processing allowances—general.
Determination of processing allowances.
Operating allowances.
Subpart E—Indian Gas

§ 1206.170
§ 1206.171
§ 1206.172
§ 1206.173
§ 1206.174
§ 1206.175
royalties?
§ 1206.176

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

Transportation Allowances
§ 1206.177 What general requirements regarding transportation allowances apply to me?
§ 1206.178 How do I determine a transportation allowance?
Processing Allowances
§ 1206.179 What general requirements regarding processing allowances apply to me?
§ 1206.180 How do I determine an actual processing allowance?
§ 1206.181 How do I establish processing costs for dual accounting purposes when I do not
process the gas?
Subpart F—Federal Coal
§ 1206.250
§ 1206.251
§ 1206.252
§ 1206.253
§ 1206.254
§ 1206.255

Purpose and scope.
Definitions.
Information collection.
Coal subject to royalties—general provisions.
Quality and quantity measurement standards for reporting and paying royalties.
Point of royalty determination.

§ 1206.256
§ 1206.257
§ 1206.258
§ 1206.259
§ 1206.260
§ 1206.261
§ 1206.262
§ 1206.263
§ 1206.264
§ 1206.265

Valuation standards for cents-per-ton leases.
Valuation standards for ad valorem leases.
Washing allowances—general.
Determination of washing allowances.
Allocation of washed coal.
Transportation allowances—general.
Determination of transportation allowances.
[Reserved]
In-situ and surface gasification and liquefaction operations.
Value enhancement of marketable coal.
Subpart G—Other Solid Minerals

§ 1206.301 Value basis for royalty computation.
Subpart H—Geothermal Resources
§ 1206.350 What is the purpose of this subpart?
§ 1206.351 What definitions apply to this subpart?
§ 1206.352 How do I calculate the royalty due on geothermal resources used for commercial
production or generation of electricity?
§ 1206.353 How do I determine transmission deductions?
§ 1206.354 How do I determine generating deductions?
§ 1206.355 How do I calculate royalty due on geothermal resources I sell at arm's length to a
purchaser for direct use?
§ 1206.356 How do I calculate royalty or fees due on geothermal resources I use for direct
use purposes?
§ 1206.357 How do I calculate royalty due on byproducts?
§ 1206.358 What are byproduct transportation allowances?
§ 1206.359 How do I determine byproduct transportation allowances?
§ 1206.360 What records must I keep to support my calculations of royalty or fees under this
subpart?
§ 1206.361 How will ONRR determine whether my royalty or direct use fee payments are
correct?
§ 1206.362 What are my responsibilities to place production into marketable condition and to
market production?
§ 1206.363 When is an ONRR audit, review, reconciliation, monitoring, or other like process
considered final?
§ 1206.364 How do I request a value or gross proceeds determination?
§ 1206.365 Does ONRR protect information I provide?
§ 1206.366 What is the nominal fee that a State, tribal, or local government lessee must pay
for the use of geothermal resources?
Subpart I—OCS Sulfur [Reserved]
Subpart J—Indian Coal
§ 1206.450
§ 1206.451
§ 1206.452
§ 1206.453
§ 1206.454
§ 1206.455
§ 1206.456
§ 1206.457
§ 1206.458
§ 1206.459
§ 1206.460
§ 1206.461
§ 1206.462

Purpose and scope.
Definitions.
Coal subject to royalties—general provisions.
Quality and quantity measurement standards for reporting and paying royalties.
Point of royalty determination.
Valuation standards for cents-per-ton leases.
Valuation standards for ad valorem leases.
Washing allowances—general.
Determination of washing allowances.
Allocation of washed coal.
Transportation allowances—general.
Determination of transportation allowances.
[Reserved]

§ 1206.463 In-situ and surface gasification and liquefaction operations.
§ 1206.464 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.

Source: 48 FR 35641, Aug. 5, 1983, unless otherwise noted. Redesignated at 75 FR 61069,
Oct. 4, 2010.
Subpart A—General Provisions
top

§ 1206.10 Information collection.
top
The information collection requirements contained in this part have been approved by the Office of
Management and Budget (OMB) under 44 U.S.C. 3501 et seq. The forms, filing date, and approved
OMB clearance numbers are identified in §1210.10.
[57 FR 41863, Sept. 14, 1992]

Subpart B—Indian Oil
top

Source: 61 FR 5455, Feb. 12, 1996, unless otherwise noted.
§ 1206.50 What is the purpose of this subpart?
top
(a) This subpart applies to all oil produced from Indian (tribal and allotted) oil and gas leases (except
leases on the Osage Indian Reservation, Osage County, Oklahoma). This subpart does not apply to
Federal leases, including Federal leases for which revenues are shared with Alaska Native
Corporations. This subpart:
(1) Establishes the value of production for royalty purposes consistent with the Indian mineral leasing
laws, other applicable laws, and lease terms;
(2) Explains how you as a lessee must calculate the value of production for royalty purposes consistent
with applicable statutes and lease terms; and
(3) Is intended to ensure that the United States discharges its trust responsibilities for administering
Indian oil and gas leases under the governing Indian mineral leasing laws, treaties, and lease terms.
(b) If the regulations in this subpart are inconsistent with a Federal statute, a settlement agreement or
written agreement as these terms are defined in this paragraph, or an express provision of an oil and
gas lease subject to this subpart, then the statute, settlement agreement, written agreement, or lease

provision will govern to the extent of the inconsistency. For purposes of this paragraph:
(1) Settlement agreement means a settlement agreement that is between the United States and a
lessee, or between an individual Indian mineral owner and a lessee and is approved by the United
States, resulting from administrative or judicial litigation; and
(2) Written agreement means a written agreement between the lessee and the ONRR Director (and
approved by the tribal lessor for tribal leases) establishing a method to determine the value of production
from any lease that ONRR expects at least would approximate the value established under this subpart.
(c) The ONRR or Indian tribes may audit, or perform other compliance reviews, and require a lessee to
adjust royalty payments and reports.
[72 FR 71241, Dec. 17, 2007]

§ 1206.51 What definitions apply to this subpart?
top
For purposes of this subpart:
Affiliate means a person who controls, is controlled by, or is under common control with another person.
(1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of
ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10
percent constitutes a presumption of noncontrol that ONRR may rebut.
(2) If there is ownership or common ownership of 10 through 50 percent of the voting securities or
instruments of ownership, or other forms of ownership, of another person, ONRR will consider the
following factors in determining whether there is control in a particular case:
(i) The extent to which there are common officers or directors;
(ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership:
(A) The percentage of ownership or common ownership;
(B) The relative percentage of ownership or common ownership compared to the percentage(s) of
ownership by other persons;
(C) Whether a person is the greatest single owner; and
(D) Whether there is an opposing voting bloc of greater ownership;
(iii) Operation of a lease, plant, or other facility;
(iv) The extent of participation by other owners in operations and day-to-day management of a lease,
plant, or other facility; and
(v) Other evidence of power to exercise control over or common control with another person.
(3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or
marriage, are affiliates.
Area means a geographic region at least as large as the defined limits of an oil and/or gas field in which
oil and/or gas lease products have similar quality, economic, and legal characteristics.

Arm's-length contract means a contract or agreement between independent persons who are not
affiliates and who have opposing economic interests regarding that contract. To be considered arm's
length for any production month, a contract must satisfy this definition for that month, as well as when
the contract was executed.
Audit means a review, conducted in accordance with generally accepted accounting and auditing
standards, of royalty payment compliance activities of lessees or other interest holders who pay
royalties, rents, or bonuses on Indian leases.
BLM means the Bureau of Land Management of the Department of the Interior.
Condensate means liquid hydrocarbons (generally exceeding 40 degrees of API gravity) recovered at
the surface without resorting to processing. Condensate is the mixture of liquid hydrocarbons that results
from condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground
reservoir.
Contract means any oral or written agreement, including amendments or revisions thereto, between two
or more persons and enforceable by law that with due consideration creates an obligation.
Exchange agreement means an agreement where one person agrees to deliver oil to another person at
a specified location in exchange for oil deliveries at another location, and other consideration. Exchange
agreements:
(1) May or may not specify prices for the oil involved;
(2) Frequently specify dollar amounts reflecting location, quality, or other differentials;
(3) Include buy/sell agreements, which specify prices to be paid at each exchange point and may appear
to be two separate sales within the same agreement, or in separate agreements; and
(4) May include, but are not limited to, exchanges of produced oil for specific types of oil (e.g., WTI);
exchanges of produced oil for other oil at other locations (location trades); exchanges of produced oil for
other grades of oil (grade trades); and multi-party exchanges.
Field means a geographic region situated over one or more subsurface oil and gas reservoirs
encompassing at least the outermost boundaries of all oil and gas accumulations known to be within
those reservoirs vertically projected to the land surface. Onshore fields usually are given names, and
their official boundaries are often designated by oil and gas regulatory agencies in the respective states
in which the fields are located.
Gathering means the movement of lease production to a central accumulation or treatment point on the
lease, unit, or communitized area, or to a central accumulation or treatment point off the lease, unit, or
communitized area as approved by BLM operations personnel.
Gross proceeds means the total monies and other consideration accruing for the disposition of oil
produced. Gross proceeds also include, but are not limited to, the following examples:
(1) Payments for services, such as dehydration, marketing, measurement, or gathering that the lessee
must perform at no cost to the lessor in order to put the production into marketable condition;
(2) The value of services to put the production into marketable condition, such as salt water disposal,
that the lessee normally performs but that the buyer performs on the lessee's behalf;
(3) Reimbursements for harboring or terminaling fees;
(4) Tax reimbursements, even though the Indian royalty interest may be exempt from taxation;
(5) Payments made to reduce or buy down the purchase price of oil to be produced in later periods, by
allocating those payments over the production whose price the payment reduces and including the
allocated amounts as proceeds for the production as it occurs; and

(6) Monies and all other consideration to which a seller is contractually or legally entitled, but does not
seek to collect through reasonable efforts.
Indian tribe means any Indian tribe, band, nation, pueblo, community, rancheria, colony, or other group
of Indians for which any minerals or interest in minerals is held in trust by the United States or that is
subject to Federal restriction against alienation.
Individual Indian mineral owner means any Indian for whom minerals or an interest in minerals is held in
trust by the United States or who holds title subject to Federal restriction against alienation.
Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or
approved by the United States under an Indian mineral leasing law that authorizes exploration for,
development or extraction of, or removal of lease products. Depending on the context, lease may also
refer to the land area covered by that authorization.
Lease products means any leased minerals attributable to, originating from, or allocated to Indian
leases.
Lessee means any person to whom the United States, a tribe, or individual Indian mineral owner issues
a lease, and any person who has been assigned an obligation to make royalty or other payments
required by the lease. Lessee includes:
(1) Any person who has an interest in a lease (including operating rights owners); and
(2) An operator, purchaser, or other person with no lease interest who makes royalty payments to ONRR
or the lessor on the lessee's behalf
Lessor means an Indian tribe or individual Indian mineral owner who has entered into a lease.
Like-quality oil means oil that has similar chemical and physical characteristics.
Location differential means an amount paid or received (whether in money or in barrels of oil) under an
exchange agreement that results from differences in location between oil delivered in exchange and oil
received in the exchange. A location differential may represent all or part of the difference between the
price received for oil delivered and the price paid for oil received under a buy/sell exchange agreement.
Marketable condition means lease products that are sufficiently free from impurities and otherwise in a
condition that they will be accepted by a purchaser under a sales contract typical for the field or area.
Net means to reduce the reported sales value to account for transportation instead of reporting a
transportation allowance as a separate entry on Form MMS–2014.
NYMEX price means the average of the New York Mercantile Exchange (NYMEX) settlement prices for
light sweet oil delivered at Cushing, Oklahoma, calculated as follows:
(1) Sum the prices published for each day during the calendar month of production (excluding weekends
and holidays) for oil to be delivered in the nearest month of delivery for which NYMEX futures prices are
published corresponding to each such day; and
(2) Divide the sum by the number of days on which those prices are published (excluding weekends and
holidays).
Oil means a mixture of hydrocarbons that existed in the liquid phase in natural underground reservoirs
and remains liquid at atmospheric pressure after passing through surface separating facilities and is
marketed or used as such. Condensate recovered in lease separators or field facilities is considered to
be oil.
ONRR means the Office of Natural Resources Revenue of the Department of the Interior.
Operating rights owner, also known as a working interest owner, means any person who owns operating

rights in a lease subject to this subpart. A record title owner is the owner of operating rights under a
lease until the operating rights have been transferred from record title (see Bureau of Land Management
regulations at 43 CFR 3100.0–5(d)).
Person means any individual, firm, corporation, association, partnership, consortium, or joint venture
(when established as a separate entity).
Processing means any process designed to remove elements or compounds (hydrocarbon and
nonhydrocarbon) from gas, including absorption, adsorption, or refrigeration. Field processes that
normally take place on or near the lease, such as natural pressure reduction, mechanical separation,
heating, cooling, dehydration, and compression, are not considered processing. The changing of
pressures and/or temperatures in a reservoir is not considered processing.
Quality differential means an amount paid or received under an exchange agreement (whether in money
or in barrels of oil) that results from differences in API gravity, sulfur content, viscosity, metals content,
and other quality factors between oil delivered and oil received in the exchange. A quality differential
may represent all or part of the difference between the price received for oil delivered and the price paid
for oil received under a buy/sell agreement.
Sale means a contract between two persons where:
(1) The seller unconditionally transfers title to the oil to the buyer and does not retain any related rights
such as the right to buy back similar quantities of oil from the buyer elsewhere;
(2) The buyer pays money or other consideration for the oil; and
(3) The parties' intent is for a sale of the oil to occur.
Sales type code means the contract type or general disposition (e.g., arm's-length or non-arm's-length)
of production from the lease. The sales type code applies to the sales contract, or other disposition, and
not to the arm's-length or non-arm's-length nature of a transportation allowance.
Transportation allowance means a deduction in determining royalty value for the reasonable, actual
costs of moving oil to a point of sale or delivery off the lease, unit area, or communitized area. The
transportation allowance does not include gathering costs.
WTI means West Texas Intermediate.
You means a lessee, operator, or other person who pays royalties under this subpart.
[72 FR 71241, Dec. 17, 2007, as amended at 73 FR 15890, Mar. 26, 2008]

§ 1206.52 How do I calculate royalty value for oil that I or my affiliate sell(s) or
exchange(s) under an arm's-length contract?
top
(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 §§1206.56 and 1206.57. If the arm's-length sales
contract does not reflect the total consideration actually transferred either directly or indirectly from the
buyer to the seller, you must value the oil sold as the total consideration accruing to the seller. Use this
section to value oil that:
(1) You sell under an arm's-length sales contract; or
(2) You sell or transfer to your affiliate or another person under a non-arm's-length contract and that
affiliate or person, or another affiliate of either of them, then sells the oil under an arm's-length contract.
(b) If you have multiple arm's-length contracts to sell oil produced from a lease that is valued under

paragraph (a) of this section, the value of the oil is the volume-weighted average of the total
consideration established under this section for all contracts for the sale of oil produced from that lease.
(c) If ONRR determines that the value under paragraph (a) of this section does not reflect the
reasonable value of the production due to either:
(1) Misconduct by or between the parties to the arm's-length contract; or
(2) Breach of your duty to market the oil for the mutual benefit of yourself and the lessor, ONRR will
establish a value based on other relevant matters.
(i) The ONRR will not use this provision to simply substitute its judgment of the market value of the oil for
the proceeds received by the seller under an arm's-length sales contract.
(ii) The fact that the price received by the seller under an arm's-length contract is less than other
measures of market price is insufficient to establish breach of the duty to market unless ONRR finds
additional evidence that the seller acted unreasonably or in bad faith in the sale of oil produced from the
lease.
(d) You must base value on the highest price that the seller can receive through legally enforceable
claims under the oil sales contract. If the seller fails to take proper or timely action to receive prices or
benefits to which it is entitled, you must base value on that obtainable price or benefit.
(1) In some cases the seller may apply timely for a price increase or benefit allowed under the oil sales
contract, but the purchaser refuses the seller's request. If this occurs, and the seller takes reasonable
documented measures to force purchaser compliance, you will owe no additional royalties unless or until
the seller receives monies or consideration resulting from the price increase or additional benefits. This
paragraph (d)(1) does not permit you to avoid your royalty payment obligation if a purchaser fails to pay,
pays only in part, or pays late.
(2) Any contract revisions or amendments that reduce prices or benefits to which the seller is entitled
must be in writing and signed by all parties to the arm's-length contract.
(e) If you or your affiliate enter(s) into an arm's-length exchange agreement, or multiple sequential arm'slength exchange agreements, then you must value your oil under this paragraph.
(1) If you or your affiliate exchange(s) oil at arm's length for WTI or equivalent oil at Cushing, Oklahoma,
you must value the oil using the NYMEX price, adjusted for applicable location and quality differentials
under paragraph (e)(3) of this section and any transportation costs under paragraph (e)(4) of this section
and §§1206.56 and 1206.57.
(2) If you do not exchange oil for WTI or equivalent oil at Cushing, but exchange it at arm's length for oil
at another location and following the arm's-length exchange(s) you or your affiliate sell(s) the oil received
in the exchange(s) under an arm's-length contract, then you must use the gross proceeds under your or
your affiliate's arm's-length sales contract after the exchange(s) occur(s), adjusted for applicable location
and quality differentials under paragraph (e)(3) of this section and any transportation costs under
paragraph (e)(4) of this section and §§1206.56 and 1206.57.
(3) You must adjust your gross proceeds for any location or quality differential, or other adjustments, you
received or paid under the arm's-length exchange agreement(s). If ONRR determines that any exchange
agreement does not reflect reasonable location or quality differentials, ONRR may adjust the differentials
you used based on relevant information. You may not otherwise use the price or differential specified in
an arm's-length exchange agreement to value your production.
(4) If you value oil under this paragraph, ONRR will allow a deduction, under §§1206.56 and 1206.57,
for the reasonable, actual costs to transport the oil:
(i) From the lease to a point where oil is given in exchange; and
(ii) If oil is not exchanged to Cushing, Oklahoma, from the point where oil is received in exchange to the
point where the oil received in exchange is sold.

(5) If you or your affiliate exchange(s) your oil at arm's length, and neither paragraph (e)(1) nor (e)(2) of
this section applies, ONRR will establish a value for the oil based on relevant matters. After ONRR
establishes the value, you must report and pay royalties and any late payment interest owed based on
that value.
(f) You may not deduct any costs of gathering as part of a transportation deduction or allowance.
(g) You must also comply with §1206.54.
[72 FR 71241, Dec. 17, 2007]

§ 1206.53 How do I determine value for oil that I or my affiliate do(es) not sell under an
arm's-length contract?
top
(a) The unit value of your oil not sold under an arm's-length contract is the volume-weighted average of
the gross proceeds paid or received by you or your affiliate, including your refining affiliate, for
purchases or sales under arm's-length contracts.
(1) When calculating that unit value, use only purchases or sales of other like-quality oil produced from
the field (or the same area if you do not have sufficient arm's-length purchases or sales of oil produced
from the field) during the production month.
(2) You may adjust the gross proceeds determined under paragraph (a) of this section for transportation
costs under paragraph (c) of this section and §§1206.56 and 1206.57 before including those proceeds in
the volume-weighted average calculation.
(3) If you have purchases away from the field(s) and cannot calculate a price in the field because you
cannot determine the seller's cost of transportation that would be allowed under paragraph (c) of this
section and §§1206.56 and 1206.57, you must not include those purchases in your weighted-average
calculation.
(b) Before calculating the volume-weighted average, you must normalize the quality of the oil in your or
your affiliate's arm's-length purchases or sales to the same gravity as that of the oil produced from the
lease. Use applicable gravity adjustment tables for the field (or the same general area for like-quality oil
if you do not have gravity adjustment tables for the specific field) to normalize for gravity.

Example to paragraph (b): 1. Assume that a lessee, who owns a refinery and refines the oil
produced from the lease at that refinery, purchases like-quality oil from other producers in the
same field at arm's length for use as feedstock in its refinery. Further assume that the oil
produced from the lease that is being valued under this section is Wyoming general sour with
an API gravity of 23.5°. Assume that the refinery purchases at arm's length oil (all of which
must be Wyoming general sour) in the following volumes of the API gravities stated at the
prices and locations indicated:

10,000 24.5° $34.70/bbl Purchased in the field.
bbl
8,000 24.0° 34.00/bbl Purchased at the refinery after the third-party
bbl
producer transported it to the refinery, and the
lessee does not know the transportation costs.
9,000 23.0° 33.25/bbl Purchased in the field.
bbl
4,000 22.0° 33.00/bbl Purchased in the field.
bbl
2. Because the lessee does not know the costs that the seller of the 8,000 bbl incurred to
transport that volume to the refinery, that volume will not be included in the volume-weighted

average price calculation. Further assume that the gravity adjustment scale provides for a
deduction of $0.02 per1/10degree API gravity below 34°. Normalized to 23.5° (the gravity of
the oil being valued under this section), the prices of each of the volumes that the refiner
purchased that are included in the volume-weighted average calculation are as follows:

10,000 bbl 24.5° $34.50 (1.0° difference over 23.5° = $0.20 deducted).
9,000 bbl 23.0° 33.35 (0.5° difference under 23.5° = $0.10 added).
4,000 bbl 22.0° 33.30 (1.5° difference under 23.5° = $0.30 added).
3. The volume-weighted average price is ((10,000 bbl × $34.50/bbl) + (9,000 bbl ×
$33.35/bbl) + (4,000 bbl × $33.30/bbl)) / 23,000 bbl = $33.84/bbl. That price will be the value
of the oil produced from the lease and refined prior to an arm's-length sale, under this section.
(c) If you value oil under this section, ONRR will allow a deduction, under §§1206.56 and 1206.57, for
the reasonable, actual costs:
(1) That you incur to transport oil that you or your affiliate sell(s), which is included in the weightedaverage price calculation, from the lease to the point where the oil is sold; and
(2) That the seller incurs to transport oil that you or your affiliate purchase(s), which is included in the
weighted-average cost calculation, from the property where it is produced to the point where you or your
affiliate purchase(s) it. You may not deduct any costs of gathering as part of a transportation deduction
or allowance.
(d) If paragraphs (a) and (b) of this section result in an unreasonable value for your production as a
result of circumstances regarding that production, the ONRR Director may establish an alternative
valuation method.
(e) You must also comply with §1206.54.
[72 FR 71241, Dec. 17, 2007]

§ 1206.54 How do I fulfill the lease provision regarding valuing production on the
basis of the major portion of like-quality oil?
top
(a) For any Indian leases that provide that the Secretary may consider the highest price paid or offered
for a major portion of production (major portion) in determining value for royalty purposes, if data are
available to compute a major portion, ONRR will, where practicable, compare the value determined in
accordance with this section with the major portion. The value to be used in determining the value of
production, for royalty purposes, will be the higher of those two values.
(b) For purposes of this paragraph, major portion means the highest price paid or offered at the time of
production for the major portion of oil production from the same field. The major portion will be calculated
using like-quality oil sold under arm's-length contracts from the same field (or, if necessary to obtain a
reasonable sample, from the same area) for each month. All such oil production will be arrayed from
highest price to lowest price (at the bottom). The major portion is that price at which 50 percent by
volume plus one barrel of oil (starting from the bottom) is sold.
[72 FR 71241, Dec. 17, 2007]

§ 1206.55 What are my responsibilities to place production into marketable condition
and to market the production?
top
You must place oil in marketable condition and market the oil for the mutual benefit of yourself and the
Indian lessor at no cost to the lessor, unless the lease agreement provides otherwise. If, in the process

of marketing the oil or placing it in marketable condition, your gross proceeds are reduced because
services are performed on your behalf that would be your responsibility, and if you valued the oil using
your or your affiliate's gross proceeds (or gross proceeds received in the sale of oil received in
exchange) under §1206.52, you must increase value to the extent that your gross proceeds are
reduced.
[72 FR 71241, Dec. 17, 2007]

§ 1206.56 Transportation allowances—general.
top
(a) Where the value of oil has been determined under §1206.52 or §1206.53 of this subpart at a point
(e.g., sales point or point of value determination) off the lease, ONRR shall allow a deduction for the
reasonable, actual costs incurred by the lessee to transport oil to a point off the lease; provided,
however, that no transportation allowance will be granted for transporting oil taken as Royalty-In-Kind
(RIK); or
(b)(1) Except as provided in paragraph (b)(2) of this section, the transportation allowance deduction on
the basis of a sales type code may not exceed 50 percent of the value of the oil at the point of sale as
determined under §1206.52 of this subpart. Transportation costs cannot be transferred between sales
type codes or to other products.
(2) Upon request of a lessee, ONRR may approve a transportation allowance deduction in excess of the
limitation prescribed by paragraph (b)(1) of this section. The lessee must demonstrate that the
transportation costs incurred in excess of the limitation prescribed in paragraph (b)(1) of this section
were reasonable, actual, and necessary. An application for exception (using Form MMS–4393, Request
to Exceed Regulatory Allowance Limitation) must contain all relevant and supporting documentation
necessary for ONRR to make a determination. Under no circumstances may the value, for royalty
purposes, under any sales type code, be reduced to zero.
(c) Transportation costs must be allocated among all products produced and transported as provided in
§1206.57. Transportation allowances for oil shall be expressed as dollars per barrel.
(d) If, after a review or audit, ONRR determines that a lessee has improperly determined a transportation
allowance authorized by this subpart, then the lessee will pay any additional royalties, plus interest
determined in accordance with §1218.54 of this chapter, or will be entitled to a credit without interest.
[61 FR 5455, Feb. 12, 1996. Redesignated and amended at 72 FR 71241, Dec. 17, 2007; 73 FR 15890,
Mar. 26, 2008]

§ 1206.57 Determination of transportation allowances.
top
(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
ONRR, unless ONRR approves a longer period upon a showing of good cause by the lessee.
(ii) In conducting reviews and audits, ONRR 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 ONRR may require that the
transportation allowance be determined in accordance with paragraph (b) of this section.

(iii) If ONRR 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 ONRR shall require that the
transportation allowance be determined in accordance with paragraph (b) of this section. When ONRR
determines that the value of the transportation may be unreasonable, ONRR will notify the lessee and
give the lessee an opportunity to provide written information justifying the lessee's transportation costs.
(2)(i) If an arm's-length transportation contract includes more than one liquid product, and the
transportation costs attributable to each product cannot be determined from the contract, then the total
transportation costs shall be allocated in a consistent and equitable manner to each of the liquid
products transported in the same proportion as the ratio of the volume of each product (excluding waste
products which have no value) to the volume of all liquid products (excluding waste products which have
no value). Except as provided in this paragraph, no allowance may be taken for the costs of transporting
lease production which is not royalty-bearing without ONRR approval.
(ii) Notwithstanding the requirements of paragraph (i), the lessee may propose to ONRR a cost
allocation method on the basis of the values of the products transported. ONRR 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 ONRR. The lessee may use the oil transportation allowance
determined in accordance with its proposed allocation procedure until ONRR 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 ONRR
approves a longer period). ONRR shall then determine the oil transportation allowance based upon the
lessee's proposal and any additional information ONRR deems necessary.
(4) Where the lessee's payments for transportation under an arm's-length contract are not on a dollarper-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, ONRR 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 ONRR 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 ONRR, unless ONRR
approves a longer period upon a showing of good cause by the lessee. ONRR will monitor the allowance
deductions to determine whether lessees are taking deductions that are reasonable and allowable.
When necessary or appropriate, ONRR may direct a lessee to modify its actual transportation allowance
deduction.
(2) The transportation allowance for non-arms-length or no-contract situations shall be based upon the
lessee's actual costs for transportation during the reporting period, including operating and maintenance
expenses, overhead, and either depreciation and a return on undepreciated capital investment in
accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the initial capital investment in
the transportation system multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this
section. Allowable capital costs are generally those for depreciable fixed assets (including costs of
delivery and installation of capital equipment) which are an integral part of the transportation system.
(i) Allowable operating expenses include: Operations supervision and engineering; operations labor;
fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and
attributable operating expense which the lessee can document.

(ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of
equipment; maintenance labor; and other directly allocable and attributable maintenance expenses
which the lessee can document.
(iii) Overhead directly attributable and allocable to the operation and maintenance of the transportation
system is an allowable expense. State and Federal income taxes and severance taxes and other fees,
including royalties, are not allowable expenses.
(iv) A lessee may use either depreciation or a return on depreciable capital investment. After a lessee
has elected to use either method for a transportation system, the lessee may not later elect to change to
the other alternative without approval of ONRR.
(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
ONRR 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) ONRR 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
ONRR approval.
(ii) Notwithstanding the requirements of paragraph (i), the lessee may propose to ONRR a cost
allocation method on the basis of the values of the products transported. ONRR 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 ONRR. The lessee may use the oil transportation
allowance determined in accordance with its proposed allocation procedure until ONRR 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 ONRR approves a longer period). ONRR shall then determine the oil transportation allowance
on the basis of the lessee's proposal and any additional information ONRR deems necessary.
(5) A lessee may apply to ONRR for an exception from the requirement that it compute actual costs in
accordance with paragraphs (b)(1) through (b)(4) of this section. ONRR 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. ONRR 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, ONRR shall deny the exception request if:
(i) No FERC cost analysis exists and the FERC has declined to investigate under ONRR 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 ONRR
approves a longer period (during which period the lessee shall continue to use the allowance from the
previous reporting period).
(iv) ONRR 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 ONRR.
(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 ONRR in writing shall
qualify as being in effect at the time these regulations become effective.
(vi) ONRR 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'slength contract or no-contract situation is reported on Form MMS–2014. A Form MMS–4110 received by
the end of the month that the Form MMS–2014 is due shall be considered to be timely received. The
initial report may be based upon estimated costs.
(ii) The initial Form MMS–4110 shall be effective for a reporting period beginning the month that the
lessee first is authorized to deduct a transportation allowance and shall continue until the end of the
calendar year, or until transportation under the non-arm's-length contract or the no-contract situation
terminates, whichever is earlier.
(iii) For calendar-year reporting periods succeeding the initial reporting period, the lessee shall submit a
completed Form MMS–4110 containing the actual costs for the previous reporting period. If oil
transportation is continuing, the lessee shall include on Form MMS–4110 its estimated costs for the next
calendar year. The estimated oil transportation allowance shall be based on the actual costs for the
previous reporting period plus or minus any adjustments which are based on the lessee's knowledge of
decreases or increases that will affect the allowance. ONRR must receive the Form MMS–4110 within 3
months after the end of the previous reporting period, unless ONRR 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 ONRR in writing shall
qualify as being in effect at the time these regulations become effective.

(vi) Upon request by ONRR, 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 ONRR.
(vii) ONRR 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) may establish reporting dates for individual lessees different from those specified in this subpart in
order to provide more effective administration. Lessees will be notified of any change in their reporting
period.
(4) Transportation allowances must be reported as a separate entry on Form MMS–2014, unless ONRR
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 §1218.54 of this
chapter.
(e) Adjustments. (1) If the actual transportation allowance is less than the amount the lessee has taken
on Form MMS–2014 for each month during the allowance form reporting period, the lessee must pay
additional royalties due plus interest computed under §1218.54 of this chapter, retroactive to the first day
of the first month the lessee is authorized to deduct a transportation allowance. If the actual
transportation allowance is greater than the amount the lessee has taken on Form MMS–2014 for each
month during the allowance form reporting period, the lessee will be entitled to a credit without interest.
(2) For lessees transporting production from Indian leases, the lessee must submit a corrected Form
MMS–2014 to reflect actual costs, together with any payment, in accordance with instructions provided
by ONRR.
(f) Actual or theoretical losses. Notwithstanding any other provisions of this subpart, for other than arm'slength contracts, no cost shall be allowed for oil transportation which results from payments (either
volumetric or for value) for actual or theoretical losses. This section does not apply when the
transportation allowance is based upon a FERC or State regulatory agency approved tariff.
(g) Other transportation cost determinations. The provisions of this section shall apply to determine
transportation costs when establishing value using a netback valuation procedure or any other
procedure that requires deduction of transportation costs.
[61 FR 5455, Feb. 12, 1996. Redesignated at 72 FR 71241, Dec. 17, 2007, as amended at 73 FR
15890, Mar. 26, 2008]

§ 1206.58 What must I do if ONRR finds that I have not properly determined value?
top
(a) If ONRR finds that you have not properly determined value, you must:
(1) Pay the difference, if any, between the royalty payments you made and those that are due, based
upon the value ONRR establishes; and

(2) Pay interest on the difference computed under §1218.54 of this chapter.
(b) If you are entitled to a credit due to overpayment on Indian leases, see §1218.53 of this chapter. The
credit will be without interest.
[72 FR 71244, Dec. 17, 2007]

§ 1206.59 May I ask ONRR for valuation guidance?
top
You may ask ONRR for guidance in determining value. You may propose a value method to ONRR.
Submit all available data related to your proposal and any additional information ONRR deems
necessary. We will promptly review your proposal and provide you with non-binding guidance.
[72 FR 71244, Dec. 17, 2007]

§ 1206.60 What are the quantity and quality bases for royalty settlement?
top
(a) You must compute royalties on the quantity and quality of oil as measured at the point of settlement
approved by BLM for the lease.
(b) If you determine the value of oil under §1206.52, §1206.53, or §1206.54 of this subpart based on a
quantity or quality different from the quantity or quality at the point of royalty settlement approved by
BLM for the lease, you must adjust the value for those quantity or quality differences.
(c) You may not deduct from the royalty volume or royalty value actual or theoretical losses incurred
before the royalty settlement point unless BLM determines that any actual loss was unavoidable.
[72 FR 71244, Dec. 17, 2007]

§ 1206.61 What records must I keep and produce?
top
(a) On request, you must make available sales, volume, and transportation data for production you sold,
purchased, or obtained from the field or area. You must make this data available to ONRR, Indian
representatives, or other authorized persons.
(b) You must retain all data relevant to the determination of royalty value. Document retention and
recordkeeping requirements are found at §§1207.5, 1212.50, and 1212.51 of this chapter. The ONRR,
Indian representatives, or other authorized persons may review and audit such data you possess, and
ONRR will direct you to use a different value if it determines that the reported value is inconsistent with
the requirements of this subpart or the lease.
[72 FR 71244, Dec. 17, 2007]

§ 1206.62 Does ONRR protect information I provide?
top
The ONRR will keep confidential, to the extent allowed under applicable laws and regulations, any data
or other information you submit that is privileged, confidential, or otherwise exempt from disclosure. All
requests for information must be submitted under the Freedom of Information Act regulations of the

Department of the Interior, 43 CFR part 2.
[72 FR 71244, Dec. 17, 2007]

Subpart C—Federal Oil
top

Source: 65 FR 14088, Mar. 15, 2000, unless otherwise noted.
§ 1206.100 What is the purpose of this subpart?
top
(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 ONRR Director establishing a method to determine
the value of production from any lease that ONRR 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) ONRR may audit and adjust all royalty payments.

§ 1206.101 What definitions apply to this subpart?
top
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 ONRR may rebut.

(2) If there is ownership or common ownership of 10 through 50 percent of the voting securities or
instruments of ownership, or other forms of ownership, of another person, ONRR will consider the
following factors in determining whether there is control under the circumstances of a particular case:
(i) The extent to which there are common officers or directors;
(ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership: the
percentage of ownership or common ownership, the relative percentage of ownership or common
ownership compared to the percentage(s) of ownership by other persons, whether a person is the
greatest single owner, or whether there is an opposing voting bloc of greater ownership;
(iii) Operation of a lease, plant, or other facility;
(iv) The extent of participation by other owners in operations and day-to-day management of a lease,
plant, or other facility; and
(v) Other evidence of power to exercise control over or common control with another person.
(3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or
marriage, are affiliates.
ANS means Alaska North Slope (ANS).
Area means a geographic region at least as large as the limits of an oil field, in which oil has similar
quality, economic, and legal characteristics.
Arm's-length contract means a contract or agreement between independent persons who are not
affiliates and who have opposing economic interests regarding that contract. To be considered arm's
length for any production month, a contract must satisfy this definition for that month, as well as when
the contract was executed.
Audit means a review, conducted under generally accepted accounting and auditing standards, of
royalty payment compliance activities of lessees, designees or other persons who pay royalties, rents, or
bonuses on Federal leases.
BLM means the Bureau of Land Management of the Department of the Interior.
Condensate means liquid hydrocarbons (normally exceeding 40 degrees of API gravity) recovered at the
surface without processing. Condensate is the mixture of liquid hydrocarbons resulting from
condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground
reservoir.
Contract means any oral or written agreement, including amendments or revisions, between two or more
persons, that is enforceable by law and that with due consideration creates an obligation.
Designee means the person the lessee designates to report and pay the lessee's royalties for a lease.
Exchange agreement means an agreement where one person agrees to deliver oil to another person at
a specified location in exchange for oil deliveries at another location. Exchange agreements may or may
not specify prices for the oil involved. They frequently specify dollar amounts reflecting location, quality,
or other differentials. Exchange agreements include buy/sell agreements, which specify prices to be paid
at each exchange point and may appear to be two separate sales within the same agreement. Examples
of other types of exchange agreements include, but are not limited to, exchanges of produced oil for
specific types of crude oil (e.g., West Texas Intermediate); exchanges of produced oil for other crude oil
at other 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. ONRR 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 ONRR approves for onshore and offshore leases, respectively.
Gross proceeds means the total monies and other consideration accruing for the disposition of oil
produced. Gross proceeds also include, but are not limited to, the following examples:
(1) Payments for services such as dehydration, marketing, measurement, or gathering which the lessee
must perform at no cost to the Federal Government;
(2) The value of services, such as salt water disposal, that the producer normally performs but that the
buyer performs on the producer's behalf;
(3) Reimbursements for harboring or terminaling fees;
(4) Tax reimbursements, even though the Federal royalty interest may be exempt from taxation;
(5) Payments made to reduce or buy down the purchase price of oil to be produced in later periods, by
allocating such payments over the production whose price the payment reduces and including the
allocated amounts as proceeds for the production as it occurs; and
(6) Monies and all other consideration to which a seller is contractually or legally entitled, but does not
seek to collect through reasonable efforts.
Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or
approved by the United States under a mineral leasing law that authorizes exploration for, development
or extraction of, or removal of oil or gas—or the land area covered by that authorization, whichever the
context requires.
Lessee means any person to whom the United States issues an oil and gas lease, an assignee of all or
a part of the record title interest, or any person to whom operating rights in a lease have been assigned.
Location differential means an amount paid or received (whether in money or in barrels of oil) under an
exchange agreement that results from differences in location between oil delivered in exchange and oil
received in the exchange. A location differential may represent all or part of the difference between the
price received for oil delivered and the price paid for oil received under a buy/sell exchange agreement.
Market center means a major point ONRR recognizes for oil sales, refining, or transshipment. Market
centers generally are locations where ONRR-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.
Netting means reducing the reported sales value to account for transportation instead of reporting a
transportation allowance as a separate entry on Form MMS–2014.
NYMEX price means the average of the New York Mercantile Exchange (NYMEX) settlement prices for
light sweet crude oil delivered at Cushing, Oklahoma, calculated as follows:
(1) Sum the prices published for each day during the calendar month of production (excluding weekends
and holidays) for oil to be delivered in the prompt month corresponding to each such day; and
(2) Divide the sum by the number of days on which those prices are published (excluding weekends and
holidays).
Oil means a mixture of hydrocarbons that existed in the liquid phase in natural underground reservoirs,
remains liquid at atmospheric pressure after passing through surface separating facilities, and is
marketed or used as a liquid. Condensate recovered in lease separators or field facilities is oil.

ONRR-approved publication means a publication ONRR approves for determining ANS spot prices or
WTI differentials.
Outer Continental Shelf (OCS) means all submerged lands lying seaward and outside of the area of
lands beneath navigable waters as defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301)
and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and
control.
Person means any individual, firm, corporation, association, partnership, consortium, or joint venture
(when established as a separate entity).
Prompt month means the nearest month of delivery for which NYMEX futures prices are published
during the trading month.
Quality differential means an amount paid or received under an exchange agreement (whether in money
or in barrels of oil) that results from differences in API gravity, sulfur content, viscosity, metals content,
and other quality factors between oil delivered and oil received in the exchange. A quality differential
may represent all or part of the difference between the price received for oil delivered and the price paid
for oil received under a buy/sell agreement.
Rocky Mountain Region means the States of Colorado, Montana, North Dakota, South Dakota, Utah,
and Wyoming, except for those portions of the San Juan Basin and other oil-producing fields in the “Four
Corners” area that lie within Colorado and Utah.
Roll means an adjustment to the NYMEX price that is calculated as follows:
Roll = .6667 × (P0−P1) + .3333 × (P0−P2), where: P0= the average of the daily NYMEX settlement prices
for deliveries during the prompt month that is the same as the month of production, as published for
each day during the trading month for which the month of production is the prompt month; P1= the
average of the daily NYMEX settlement prices for deliveries during the month following the month of
production, published for each day during the trading month for which the month of production is the
prompt month; and P2= the average of the daily NYMEX settlement prices for deliveries during the
second month following the month of production, as published for each day during the trading month for
which the month of production is the prompt month. Calculate the average of the daily NYMEX
settlement prices using only the days on which such prices are published (excluding weekends and
holidays).
(1) Example 1. Prices in Out Months are Lower Going Forward: The month of production for which you
must determine royalty value is March. March was the prompt month (for year 2003) from January 22
through February 20. April was the first month following the month of production, and May was the
second month following the month of production. P0therefore is the average of the daily NYMEX
settlement prices for deliveries during March published for each business day between January 22 and
February 20. P1is the average of the daily NYMEX settlement prices for deliveries during April published
for each business day between January 22 and February 20. P2is the average of the daily NYMEX
settlement prices for deliveries during May published for each business day between January 22 and
February 20. In this example, assume that P0= $28.00 per bbl, P1= $27.70 per bbl, and P2= $27.10 per
bbl. In this example (a declining market), Roll = .6667 × ($28.00−$27.70) + .3333 × ($28.00−$27.10) =
$.20 + $.30 = $.50. You add this number to the NYMEX price.
(2) Example 2. Prices in Out Months are Higher Going Forward: The month of production for which you
must determine royalty value is July. July 2003 was the prompt month from May 21 through June 20.
August was the first month following the month of production, and September was the second month
following the month of production. P0therefore is the average of the daily NYMEX settlement prices for
deliveries during July published for each business day between May 21 and June 20. P1is the average
of the daily NYMEX settlement prices for deliveries during August published for each business day
between May 21 and June 20. P2is the average of the daily NYMEX settlement prices for deliveries
during September published for each business day between May 21 and June 20. In this example,
assume that P0= $28.00 per bbl, P1= $28.90 per bbl, and P2= $29.50 per bbl. In this example (a rising
market), Roll = .6667 × ($28.00−$28.90) + .3333 × ($28.00−$29.50) = (−$.60) + (−$.50) = −$1.10. You
add this negative number to the NYMEX price (effectively a subtraction from the NYMEX price).

Sale means a contract between two persons where:
(1) The seller unconditionally transfers title to the oil to the buyer and does not retain any related rights
such as the right to buy back similar quantities of oil from the buyer elsewhere;
(2) The buyer pays money or other consideration for the oil; and
(3) The parties' intent is for a sale of the oil to occur.
Spot price means the price under a spot sales contract where:
(1) A seller agrees to sell to a buyer a specified amount of oil at a specified price over a specified period
of short duration;
(2) No cancellation notice is required to terminate the sales agreement; and
(3) There is no obligation or implied intent to continue to sell in subsequent periods.
Tendering program means a producer's offer of a portion of its crude oil produced from a field or area for
competitive bidding, regardless of whether the production is offered or sold at or near the lease or unit or
away from the lease or unit.
Trading month means the period extending from the second business day before the 25th day of the
second calendar month preceding the delivery month (or, if the 25th day of that month is a non-business
day, the second business day before the last business day preceding the 25th day of that month)
through the third business day before the 25th day of the calendar month preceding the delivery month
(or, if the 25th day of that month is a non-business day, the third business day before the last business
day preceding the 25th day of that month), unless the NYMEX publishes a different definition or different
dates on its official Web site, www.nymex.com, in which case the NYMEX definition will apply.
Transportation allowance means a deduction in determining royalty value for the reasonable, actual
costs of moving oil to a point of sale or delivery off the lease, unit area, or communitized area. The
transportation allowance does not include gathering costs.
WTI differential means the average of the daily mean differentials for location and quality between a
grade of crude oil at a market center and West Texas Intermediate (WTI) crude oil at Cushing published
for each day for which price publications perform surveys for deliveries during the production month,
calculated over the number of days on which those differentials are published (excluding weekends and
holidays). Calculate the daily mean differentials by averaging the daily high and low differentials for the
month in the selected publication. Use only the days and corresponding differentials for which such
differentials are published.
(1) Example. Assume the production month was March 2003. Industry trade publications performed their
price surveys and determined differentials during January 26 through February 25 for oil delivered in
March. The WTI differential (for example, the West Texas Sour crude at Midland, Texas, spread versus
WTI) applicable to valuing oil produced in the March 2003 production month would be determined using
all the business days for which differentials were published during the period January 26 through
February 25 excluding weekends and holidays (22 days). To calculate the WTI differential, add together
all of the daily mean differentials published for January 26 through February 25 and divide that sum by
22.
(2) [Reserved]
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24975, May 5, 2004]

§ 1206.102 How do I calculate royalty value for oil that I or my affiliate sell(s) under an
arm's-length contract?
top

(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 §1206.110 or §1206.111. 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 ONRR 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,
ONRR may require that you value the oil sold under that contract either under §1206.103 or at the total
consideration received.
(2) You must value the oil under §1206.103 if ONRR 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) ONRR 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 ONRR 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 §1206.102(a) or §1206.103 to
value your production for royalty purposes.
(i) If you use §1206.102(a), your gross proceeds are the gross proceeds under your or your affiliate's
arm's-length sales contract after the exchange(s) occur(s). You must adjust your gross proceeds for any
location or quality differential, or other adjustments, you received or paid under the arm's-length
exchange agreement(s). If ONRR determines that any arm's-length exchange agreement does not
reflect reasonable location or quality differentials, ONRR may require you to value the oil under
§1206.103. 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 §1206.102(d)(1) to use §1206.102(a) or §1206.103, 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'slength 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 §1206.102(a) or §1206.103 to value your
production for royalty purposes.

(ii) When you elect under §1206.102(d)(2)(i) to use §1206.102(a) or §1206.103, 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) ONRR 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'slength contract.

§ 1206.103 How do I value oil that is not sold under an arm's-length contract?
top
This section explains how to value oil that you may not value under §1206.102 or that you elect under
§1206.102(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 ONRR
approval.
(a) Production from leases in California or Alaska. Value is the average of the daily mean ANS spot
prices published in any ONRR-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 ONRR-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 §1206.112.
(4) After you select an ONRR-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 ONRR revokes
its approval of the publication. If you are required to change publications, you must begin a new 2-year
period.
(b) Production from leases in the Rocky Mountain Region. This paragraph provides methods and options
for valuing your production under different factual situations. You must consistently apply paragraph (b)

(1), (b)(2), or (b)(3) of this section to value all of your production from the same unit, communitization
agreement, or lease (if the lease or a portion of the lease is not part of a unit or communitization
agreement) that you cannot value under §1206.102 or that you elect under §1206.102(d) to value under
this section.
(1) If you have an ONRR-approved tendering program, you must value oil produced from leases in the
area the tendering program covers at the highest winning bid price for tendered volumes.
(i) The minimum requirements for ONRR to approve your tendering program are:
(A) You must offer and sell at least 30 percent of your or your affiliates' production from both Federal
and non-Federal leases in the area under your tendering program; and
(B) You must receive at least three bids for the tendered volumes from bidders who do not have their
own tendering programs that cover some or all of the same area.
(ii) If you do not have an ONRR-approved tendering program, you may elect to value your oil under
either paragraph (b)(2) or (b)(3) of this section. After you select either paragraph (b)(2) or (b)(3) of this
section, you may not change to the other method more often than once every 2 years, unless the
method you have been using is no longer applicable and you must apply the other paragraph. If you
change methods, you must begin a new 2-year period.
(2) Value is the volume-weighted average of the gross proceeds accruing to the seller under your or
your affiliates' arm's-length contracts for the purchase or sale of production from the field or area during
the production month.
(i) The total volume purchased or sold under those contracts must exceed 50 percent of your and your
affiliates' production from both Federal and non-Federal leases in the same field or area during that
month.
(ii) Before calculating the volume-weighted average, you must normalize the quality of the oil in your or
your affiliates' arm's-length purchases or sales to the same gravity as that of the oil produced from the
lease.
(3) Value is the NYMEX price (without the roll), adjusted for applicable location and quality differentials
and transportation costs under §1206.112.
(4) If you demonstrate to ONRR's satisfaction that paragraphs (b)(1) through (b)(3) of this section result
in an unreasonable value for your production as a result of circumstances regarding that production, the
ONRR Director may establish an alternative valuation method.
(c) Production from leases not located in California, Alaska, or the Rocky Mountain Region. (1) Value is
the NYMEX price, plus the roll, adjusted for applicable location and quality differentials and
transportation costs under §1206.112.
(2) If the ONRR Director determines that use of the roll no longer reflects prevailing industry practice in
crude oil sales contracts or that the most common formula used by industry to calculate the roll changes,
ONRR may terminate or modify use of the roll under paragraph (c)(1) of this section at the end of each
2-year period following July 6, 2004, through notice published in the Federal Register not later than 60
days before the end of the 2-year period. ONRR will explain the rationale for terminating or modifying the
use of the roll in this notice.
(d) Unreasonable value. If ONRR determines that the NYMEX price or ANS spot price does not
represent a reasonable royalty value in any particular case, ONRR may establish reasonable royalty
value based on other relevant matters.
(e) Production delivered to your refinery and the NYMEX price or ANS spot price is an unreasonable
value. (1) Instead of valuing your production under paragraph (a), (b), or (c) of this section, you may
apply to the ONRR Director to establish a value representing the market at the refinery if:
(i) You transport your oil directly to your or your affiliate's refinery, or exchange your oil for oil delivered

to your or your affiliate's refinery; and
(ii) You must value your oil under this section at the NYMEX price or ANS spot price; and
(iii) You believe that use of the NYMEX price or ANS spot price results in an unreasonable royalty value.
(2) You must provide adequate documentation and evidence demonstrating the market value at the
refinery. That evidence may include, but is not limited to:
(i) Costs of acquiring other crude oil at or for the refinery;
(ii) How adjustments for quality, location, and transportation were factored into the price paid for other
oil;
(iii) Volumes acquired for and refined at the refinery; and
(iv) Any other appropriate evidence or documentation that ONRR requires.
(3) If the ONRR Director establishes a value representing market value at the refinery, you may not take
an allowance against that value under §1206.112(b) unless it is included in the Director's approval.
[65 FR 14088, Mar. 15, 2002, as amended at 67 FR 19111, Apr. 18, 2002; 69 FR 24976, May 5, 2004]

§ 1206.104 What publications are acceptable to ONRR?
top
(a) ONRR periodically will publish in the Federal Register a list of acceptable publications for the
NYMEX price and ANS spot price based on certain criteria, including, but not limited to:
(1) Publications buyers and sellers frequently use;
(2) Publications frequently mentioned in purchase or sales contracts;
(3) Publications that use adequate survey techniques, including development of estimates based on
daily surveys of buyers and sellers of crude oil, and, for ANS spot prices, buyers and sellers of ANS
crude oil; and
(4) Publications independent from ONRR, other lessors, and lessees.
(b) Any publication may petition ONRR to be added to the list of acceptable publications.
(c) ONRR will specify the tables you must use in the acceptable publications.
(d) ONRR may revoke its approval of a particular publication if it determines that the prices or
differentials published in the publication do not accurately represent NYMEX prices or differentials or
ANS spot market prices or differentials.
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24976, May 5, 2004]

§ 1206.105 What records must I keep to support my calculations of value under this
subpart?
top
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 1207 of this chapter.
(c) ONRR may review and audit your data, and ONRR will direct you to use a different value if it
determines that the reported value is inconsistent with the requirements of this subpart.

§ 1206.106 What are my responsibilities to place production into marketable condition
and to market production?
top
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.

§ 1206.107 How do I request a value determination?
top
(a) You may request a value determination from ONRR 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 ONRR 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) ONRR will reply to requests expeditiously. ONRR may either:
(1) Issue a value determination signed by the Assistant Secretary,Policy, Management and Budget; or
(2) Issue a value determination by ONRR; or
(3) Inform you in writing that ONRR will not provide a value determination. Situations in which ONRR
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, Policy, Management and Budget, is
binding on both you and ONRR 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 §1218.54 of this chapter.
(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 ONRR is binding on ONRR and delegated States with respect to the
specific situation addressed in the determination unless the ONRR (for ONRR-issued value
determinations) or the Assistant Secretary modifies or rescinds it.
(1) A value determination by ONRR is not an appealable decision or order under 30 CFR part 1290.
(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 1290.
(e) In making a value determination, ONRR or the Assistant Secretary may use any of the applicable
valuation criteria in this subpart.
(f) A change in an applicable statute or regulation on which any value determination is based takes
precedence over the value determination, regardless of whether the ONRR or the Assistant Secretary
modifies or rescinds the value determination.
(g) The ONRR 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) ONRR may make requests and replies under this section available to the public, subject to the
confidentiality requirements under §1206.108.

§ 1206.108 Does ONRR protect information I provide?
top
Certain information you submit to ONRR regarding valuation of oil, including transportation allowances,
may be exempt from disclosure. To the extent applicable laws and regulations permit, ONRR 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.

§ 1206.109 When may I take a transportation allowance in determining value?
top
(a) Transportation allowances permitted when value is based on gross proceeds. ONRR will allow a
deduction for the reasonable, actual costs to transport oil from the lease to the point off the lease under
§1206.110 or §1206.111, as applicable. This paragraph applies when:
(1) You value oil under §1206.102 based on gross proceeds from a sale at a point off the lease, unit, or

communitized area where the oil is produced, and
(2) The movement to the sales point is not gathering.
(b) Transportation allowances and other adjustments that apply when value is based on NYMEX prices
or ANS spot prices. If you value oil using NYMEX prices or ANS spot prices under §1206.103, ONRR
will allow an adjustment for certain location and quality differentials and certain costs associated with
transporting oil as provided under §1206.112.
(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
§1206.102 or §1206.103 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 ONRR 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 ONRR 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 §§1206.110 and 1206.111. You must express transportation
allowances for oil as dollars per barrel.
(e) Liability for additional payments. If ONRR determines that you took an excessive transportation
allowance, then you must pay any additional royalties due, plus interest under §1218.54 of this chapter.
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, ONRR may assess you an amount under §1206.116.
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24976, May 5, 2004]

§ 1206.110 How do I determine a transportation allowance under an arm's-length
transportation contract?
top
(a) If you or your affiliate incur transportation costs under an arm's-length transportation contract, you
may claim a transportation allowance for the reasonable, actual costs incurred as more fully explained in
paragraph (b) of this section, except as provided in paragraphs (a)(1) and (a)(2) of this section and
subject to the limitation in §1206.109(c). You must be able to demonstrate that your or your affiliate's
contract is at arm's length. You do not need ONRR approval before reporting a transportation allowance
for costs incurred under an arm's-length transportation contract.
(1) If ONRR 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, ONRR may require
that you calculate the transportation allowance under §1206.111.
(2) You must calculate the transportation allowance under §1206.111 if ONRR 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) ONRR 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 ONRR finds additional evidence that you or your affiliate
acted unreasonably or in bad faith in transporting oil from the lease.
(b) You may deduct any of the following actual costs you (including your affiliates) incur for transporting
oil. You may not use as a deduction any cost that duplicates all or part of any other cost that you use
under this paragraph.
(1) The amount that you pay under your arm's-length transportation contract or tariff.
(2) Fees paid (either in volume or in value) for actual or theoretical line losses.
(3) Fees paid for administration of a quality bank.
(4) The cost of carrying on your books as inventory a volume of oil that the pipeline operator requires
you to maintain, and that you do maintain, in the line as line fill. You must calculate this cost as follows:
(i) Multiply the volume that the pipeline requires you to maintain, and that you do maintain, in the pipeline
by the value of that volume for the current month calculated under §1206.102 or §1206.103, as
applicable; and
(ii) Multiply the value calculated under paragraph (b)(4)(i) of this section by the monthly rate of return,
calculated by dividing the rate of return specified in §1206.111(i)(2) by 12.
(5) Fees paid to a terminal operator for loading and unloading of crude oil into or from a vessel, vehicle,
pipeline, or other conveyance.
(6) Fees paid for short-term storage (30 days or less) incidental to transportation as required by a
transporter.
(7) Fees paid to pump oil to another carrier's system or vehicles as required under a tariff.
(8) Transfer fees paid to a hub operator associated with physical movement of crude oil through the hub
when you do not sell the oil at the hub. These fees do not include title transfer fees.
(9) Payments for a volumetric deduction to cover shrinkage when high-gravity petroleum (generally in
excess of 51 degrees API) is mixed with lower-gravity crude oil for transportation.
(10) Costs of securing a letter of credit, or other surety, that the pipeline requires you as a shipper to
maintain.
(c) You may not deduct any costs that are not actual costs of transporting oil, including but not limited to
the following:
(1) Fees paid for long-term storage (more than 30 days).
(2) Administrative, handling, and accounting fees associated with terminalling.
(3) Title and terminal transfer fees.
(4) Fees paid to track and match receipts and deliveries at a market center or to avoid paying title
transfer fees.
(5) Fees paid to brokers.
(6) Fees paid to a scheduling service provider.
(7) Internal costs, including salaries and related costs, rent/space costs, office equipment costs, legal

fees, and other costs to schedule, nominate, and account for sale or movement of production.
(8) Gauging fees.
(d) If your arm's-length transportation contract includes more than one liquid product, and the
transportation costs attributable to each product cannot be determined from the contract, then you must
allocate the total transportation costs to each of the liquid products transported.
(1) Your allocation must use the same proportion as the ratio of the volume of each product (excluding
waste products with no value) to the volume of all liquid products (excluding waste products with no
value).
(2) You may not claim an allowance for the costs of transporting lease production that is not royaltybearing.
(3) You may propose to ONRR a cost allocation method on the basis of the values of the products
transported. ONRR will approve the method unless it is not consistent with the purposes of the
regulations in this subpart.
(e) If your arm's-length transportation contract includes both gaseous and liquid products, and the
transportation costs attributable to each product cannot be determined from the contract, then you must
propose an allocation procedure to ONRR.
(1) You may use your proposed procedure to calculate a transportation allowance until ONRR accepts
or rejects your cost allocation. If ONRR rejects your cost allocation, you must amend your Form MMS–
2014 for the months that you used the rejected method and pay any additional royalty and interest due.
(2) You must submit your initial proposal, including all available data, within 3 months after first claiming
the allocated deductions on Form MMS–2014.
(f) If your payments for transportation under an arm's-length contract are not on a dollar-per-unit basis,
you must convert whatever consideration is paid to a dollar-value equivalent.
(g) If your arm's-length sales contract includes a provision reducing the contract price by a transportation
factor, do not separately report the transportation factor as a transportation allowance on Form MMS–
2014.
(1) You may use the transportation factor in determining your gross proceeds for the sale of the product.
(2) You must obtain ONRR approval before claiming a transportation factor in excess of 50 percent of
the base price of the product.
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24976, May 5, 2004]

§ 1206.111 How do I determine a transportation allowance if I do not have an arm'slength transportation contract or arm's-length tariff?
top
(a) This section applies if you or your affiliate do not have an arm's-length transportation contract,
including situations where you or your affiliate provide your own transportation services. Calculate your
transportation allowance based on your or your affiliate's reasonable, actual costs for transportation
during the reporting period using the procedures prescribed in this section.
(b) Your or your affiliate's actual costs include the following:
(1) Operating and maintenance expenses under paragraphs (d) and (e) of this section;
(2) Overhead under paragraph (f) of this section;

(3) Depreciation under paragraphs (g) and (h) of this section;
(4) A return on undepreciated capital investment under paragraph (i) of this section; and
(5) Once the transportation system has been depreciated below ten percent of total capital investment, a
return on ten percent of total capital investment under paragraph (j) of this section.
(6) To the extent not included in costs identified in paragraphs (d) through (j) of this section, you may
also deduct the following actual costs. You may not use any cost as a deduction that duplicates all or
part of any other cost that you use under this section:
(i) Volumetric adjustments for actual (not theoretical) line losses.
(ii) The cost of carrying on your books as inventory a volume of oil that the pipeline operator requires you
as a shipper to maintain, and that you do maintain, in the line as line fill. You must calculate this cost as
follows:
(A) Multiply the volume that the pipeline requires you to maintain, and that you do maintain, in the
pipeline by the value of that volume for the current month calculated under §1206.102 or §1206.103, as
applicable; and
(B) Multiply the value calculated under paragraph (b)(6)(ii)(A) of this section by the monthly rate of
return, calculated by dividing the rate of return specified in §1206.111(i)(2) by 12.
(iii) Fees paid to a non-affiliated terminal operator for loading and unloading of crude oil into or from a
vessel, vehicle, pipeline, or other conveyance.
(iv) Transfer fees paid to a hub operator associated with physical movement of crude oil through the hub
when you do not sell the oil at the hub. These fees do not include title transfer fees.
(v) A volumetric deduction to cover shrinkage when high-gravity petroleum (generally in excess of 51
degrees API) is mixed with lower-gravity crude oil for transportation.
(vi) Fees paid to a non-affiliated quality bank administrator for administration of a quality bank.
(7) You may not deduct any costs that are not actual costs of transporting oil, including but not limited to
the following:
(i) Fees paid for long-term storage (more than 30 days).
(ii) Administrative, handling, and accounting fees associated with terminalling.
(iii) Title and terminal transfer fees.
(iv) Fees paid to track and match receipts and deliveries at a market center or to avoid paying title
transfer fees.
(v) Fees paid to brokers.
(vi) Fees paid to a scheduling service provider.
(vii) Internal costs, including salaries and related costs, rent/space costs, office equipment costs, legal
fees, and other costs to schedule, nominate, and account for sale or movement of production.
(viii) Theoretical line losses.
(ix) Gauging fees.

(c) Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery
and installation of capital equipment) which are an integral part of the transportation system.
(d) Allowable operating expenses include:
(i) Operations supervision and engineering;
(ii) Operations labor;
(iii) Fuel;
(iv) Utilities;
(v) Materials;
(vi) Ad valorem property taxes;
(vii) Rent;
(viii) Supplies; and
(ix) Any other directly allocable and attributable operating expense which you can document.
(e) Allowable maintenance expenses include:
(i) Maintenance of the transportation system;
(ii) Maintenance of equipment;
(iii) Maintenance labor; and
(iv) Other directly allocable and attributable maintenance expenses which you can document.
(f) Overhead directly attributable and allocable to the operation and maintenance of the transportation
system is an allowable expense. State and Federal income taxes and severance taxes and other fees,
including royalties, are not allowable expenses.
(g) To compute depreciation, you may elect to use either a straight-line depreciation method based on
the life of equipment or on the life of the reserves which the transportation system services, or a unit-ofproduction method. After you make an election, you may not change methods without ONRR approval.
You may not depreciate equipment below a reasonable salvage value.
(h) This paragraph describes the basis for your depreciation schedule.
(1) If you or your affiliate own a transportation system on June 1, 2000, you must base your depreciation
schedule used in calculating actual transportation costs for production after June 1, 2000, on your total
capital investment in the system (including your original purchase price or construction cost and
subsequent reinvestment).
(2) If you or your affiliate purchased the transportation system at arm's length before June 1, 2000, you
must incorporate depreciation on the schedule based on your purchase price (and subsequent
reinvestment) into your transportation allowance calculations for production after June 1, 2000,
beginning at the point on the depreciation schedule corresponding to that date. You must prorate your
depreciation for calendar year 2000 by claiming part-year depreciation for the period from June 1, 2000
until December 31, 2000. You may not adjust your transportation costs for production before June 1,
2000, using the depreciation schedule based on your purchase price.
(3) If you are the original owner of the transportation system on June 1, 2000, or if you purchased your
transportation system before March 1, 1988, you must continue to use your existing depreciation

schedule in calculating actual transportation costs for production in periods after June 1, 2000.
(4) If you or your affiliate purchase a transportation system at arm's length from the original owner after
June 1, 2000, you must base your depreciation schedule used in calculating actual transportation costs
on your total capital investment in the system (including your original purchase price and subsequent
reinvestment). You must prorate your depreciation for the year in which you or your affiliate purchased
the system to reflect the portion of that year for which you or your affiliate own the system.
(5) If you or your affiliate purchase a transportation system at arm's length after June 1, 2000, from
anyone other than the original owner, you must assume the depreciation schedule of the person from
whom you bought the system. Include in the depreciation schedule any subsequent reinvestment.
(i)(1) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated
capital balance as of the beginning of the period for which you are calculating the transportation
allowance by the rate of return provided in paragraph (i)(2) of this section.
(2) The rate of return is 1.3 times the industrial bond yield index for Standard & Poor's BBB bond rating.
Use the monthly average rate published in “Standard & Poor's Bond Guide” for the first month of the
reporting period for which the allowance applies. Calculate the rate at the beginning of each subsequent
transportation allowance reporting period.
(j)(1) After a transportation system has been depreciated at or below a value equal to ten percent of your
total capital investment, you may continue to include in the allowance calculation a cost equal to ten
percent of your total capital investment in the transportation system multiplied by a rate of return under
paragraph (i)(2) of this section.
(2) You may apply this paragraph to a transportation system that before June 1, 2000, was depreciated
at or below a value equal to ten percent of your total capital investment.
(k) Calculate the deduction for transportation costs based on your or your affiliate's cost of transporting
each product through each individual transportation system. Where more than one liquid product is
transported, allocate costs consistently and equitably to each of the liquid products transported. Your
allocation must use the same proportion as the ratio of the volume of each liquid product (excluding
waste products with no value) to the volume of all liquid products (excluding waste products with no
value).
(1) You may not take an allowance for transporting lease production that is not royalty-bearing.
(2) You may propose to ONRR a cost allocation method on the basis of the values of the products
transported. ONRR 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 ONRR.
(2) You may use your proposed procedure to calculate a transportation allowance until ONRR accepts
or rejects your cost allocation. If ONRR rejects your cost allocation, you must amend your Form MMS–
2014 for the months that you used the rejected method and pay any additional royalty and interest due.
(3) You must submit your initial proposal, including all available data, within 3 months after first claiming
the allocated deductions on Form MMS–2014.
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24977, May 5, 2004]

§ 1206.112 What adjustments and transportation allowances apply when I value oil
production from my lease using NYMEX prices or ANS spot prices?
top
This section applies when you use NYMEX prices or ANS spot prices to calculate the value of

production under §1206.103. As specified in this section, adjust the NYMEX price to reflect the
difference in value between your lease and Cushing, Oklahoma, or adjust the ANS spot price to reflect
the difference in value between your lease and the appropriate ONRR-recognized market center at
which the ANS spot price is published (for example, Long Beach, California, or San Francisco,
California). Paragraph (a) of this section explains how you adjust the value between the lease and the
market center, and paragraph (b) of this section explains how you adjust the value between the market
center and Cushing when you use NYMEX prices. Paragraph (c) of this section explains how
adjustments may be made for quality differentials that are not accounted for through exchange
agreements. Paragraph (d) of this section gives some examples. References in this section to “you”
include your affiliates as applicable.
(a) To adjust the value between the lease and the market center:
(1)(i) For oil that you exchange at arm's length between your lease and the market center (or between
any intermediate points between those locations), you must calculate a lease-to-market center
differential by the applicable location and quality differentials derived from your arm's-length exchange
agreement applicable to production during the production month.
(ii) For oil that you exchange between your lease and the market center (or between any intermediate
points between those locations) under an exchange agreement that is not at arm's length, you must
obtain approval from ONRR for a location and quality differential. Until you obtain such approval, you
may use the location and quality differential derived from that exchange agreement applicable to
production during the production month. If ONRR prescribes a different differential, you must apply
ONRR's differential to all periods for which you used your proposed differential. You must pay any
additional royalties owed resulting from using ONRR's differential plus late payment interest from the
original royalty due date, or you may report a credit for any overpaid royalties plus interest under 30
U.S.C. 1721(h).
(2) For oil that you transport between your lease and the market center (or between any intermediate
points between those locations), you may take an allowance for the cost of transporting that oil between
the relevant points as determined under §1206.110 or §1206.111, as applicable.
(3) If you transport or exchange at arm's length (or both transport and exchange) at least 20 percent, but
not all, of your oil produced from the lease to a market center, determine the adjustment between the
lease and the market center for the oil that is not transported or exchanged (or both transported and
exchanged) to or through a market center as follows:
(i) Determine the volume-weighted average of the lease-to-market center adjustment calculated under
paragraphs (a)(1) and (a)(2) of this section for the oil that you do transport or exchange (or both
transport and exchange) from your lease to a market center.
(ii) Use that volume-weighted average lease-to-market center adjustment as the adjustment for the oil
that you do not transport or exchange (or both transport and exchange) from your lease to a market
center.
(4) If you transport or exchange (or both transport and exchange) less than 20 percent of the crude oil
produced from your lease between the lease and a market center, you must propose to ONRR an
adjustment between the lease and the market center for the portion of the oil that you do not transport or
exchange (or both transport and exchange) to a market center. Until you obtain such approval, you may
use your proposed adjustment. If ONRR prescribes a different adjustment, you must apply ONRR's
adjustment to all periods for which you used your proposed adjustment. You must pay any additional
royalties owed resulting from using ONRR's adjustment plus late payment interest from the original
royalty due date, or you may report a credit for any overpaid royalties plus interest under 30 U.S.C. 1721
(h).
(5) You may not both take a transportation allowance and use a location and quality adjustment or
exchange differential for the same oil between the same points.
(b) For oil that you value using NYMEX prices, adjust the value between the market center and Cushing,
Oklahoma, as follows:
(1) If you have arm's-length exchange agreements between the market center and Cushing under which
you exchange to Cushing at least 20 percent of all the oil you own at the market center during the

production month, you must use the volume-weighted average of the location and quality differentials
from those agreements as the adjustment between the market center and Cushing for all the oil that you
produce from the leases during that production month for which that market center is used.
(2) If paragraph (b)(1) of this section does not apply, you must use the WTI differential published in an
ONRR-approved publication for the market center nearest your lease, for crude oil most similar in quality
to your production, as the adjustment between the market center and Cushing. (For example, for light
sweet crude oil produced offshore of Louisiana, use the WTI differential for Light Louisiana Sweet crude
oil at St. James, Louisiana.) After you select an ONRR-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 ONRR revokes its approval of the publication. If you are required to change publications,
you must begin a new 2-year period.
(3) If neither paragraph (b)(1) nor (b)(2) of this section applies, you may propose an alternative
differential to ONRR. Until you obtain such approval, you may use your proposed differential. If ONRR
prescribes a different differential, you must apply ONRR's differential to all periods for which you used
your proposed differential. You must pay any additional royalties owed resulting from using ONRR's
differential plus late payment interest from the original royalty due date, or you may report a credit for
any overpaid royalties plus interest under 30 U.S.C. 1721(h).
(c)(1) If you adjust for location and quality differentials or for transportation costs under paragraphs (a)
and (b) of this section, also adjust the NYMEX price or ANS spot price for quality based on premiums or
penalties determined by pipeline quality bank specifications at intermediate commingling points or at the
market center if those points are downstream of the royalty measurement point approved by BOEMRE
or BLM, as applicable. Make this adjustment only if and to the extent that such adjustments were not
already included in the location and quality differentials determined from your arm's-length exchange
agreements.
(2) If the quality of your oil as adjusted is still different from the quality of the representative crude oil at
the market center after making the quality adjustments described in paragraphs (a), (b) and (c)(1) of this
section, you may make further gravity adjustments using posted price gravity tables. If quality bank
adjustments do not incorporate or provide for adjustments for sulfur content, you may make sulfur
adjustments, based on the quality of the representative crude oil at the market center, of 5.0 cents per
one-tenth percent difference in sulfur content, unless ONRR approves a higher adjustment.
(d) The examples in this paragraph illustrate how to apply the requirement of this section.
(1) Example. Assume that a Federal lessee produces crude oil from a lease near Artesia, New Mexico.
Further, assume that the lessee transports the oil to Roswell, New Mexico, and then exchanges the oil to
Midland, Texas. Assume the lessee refines the oil received in exchange at Midland. Assume that the
NYMEX price is $30.00/bbl, adjusted for the roll; that the WTI differential (Cushing to Midland) is
−$.10/bbl; that the lessee's exchange agreement between Roswell and Midland results in a location and
quality differential of −$.08/bbl; and that the lessee's actual cost of transporting the oil from Artesia to
Roswell is $.40/bbl. In this example, the royalty value of the oil is $30.00−$.10−$.08—$.40 = $29.42/bbl.
(2) Example. Assume the same facts as in the example in paragraph (1), except that the lessee
transports and exchanges to Midland 40 percent of the production from the lease near Artesia, and
transports the remaining 60 percent directly to its own refinery in Ohio. In this example, the 40 percent of
the production would be valued at $29.42/bbl, as explained in the previous example. In this example, the
other 60 percent also would be valued at $29.42/bbl.
(3) Example. Assume that a Federal lessee produces crude oil from a lease near Bakersfield, California.
Further, assume that the lessee transports the oil to Hynes Station, and then exchanges the oil to
Cushing which it further exchanges with oil it refines. Assume that the ANS spot price is $20.00/bbl, and
that the lessee's actual cost of transporting the oil from Bakersfield to Hynes Station is $.28/bbl. The
lessee must request approval from ONRR for a location and quality adjustment between Hynes Station
and Long Beach. For example, the lessee likely would propose using the tariff on Line 63 from Hynes
Station to Long Beach as the adjustment between those points. Assume that adjustment to be $.72,
including the sulfur and gravity bank adjustments, and that ONRR approves the lessee's request. In this
example, the preliminary (because the location and quality adjustment is subject to ONRR review)
royalty value of the oil is $20.00−$.72−$.28 = $19.00/bbl. The fact that oil was exchanged to Cushing
does not change use of ANS spot prices for royalty valuation.
[69 FR 24978, May 5, 2004]

§ 1206.113 How will ONRR identify market centers?
top
ONRR periodically will publish in the Federal Register a list of market centers. ONRR will monitor
market activity and, if necessary, add to or modify the list of market centers and will publish such
modifications in theFederal Register.ONRR will consider the following factors and conditions in
specifying market centers:
(a) Points where ONRR-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.

§ 1206.114 What are my reporting requirements under an arm's-length transportation
contract?
top
You or your affiliate must use a separate entry on Form MMS–2014 to notify ONRR of an allowance
based on transportation costs you or your affiliate incur. ONRR 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 1207 of this chapter.

§ 1206.115 What are my reporting requirements under a non-arm's-length
transportation arrangement?
top
(a) You or your affiliate must use a separate entry on Form MMS–2014 to notify ONRR 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 1206.117 will apply when you amend your report based on your
actual costs.
(c) ONRR may require you or your affiliate to submit all data used to calculate the allowance deduction.
Recordkeeping requirements are found at part 1207 of this chapter.

§ 1206.116 What interest applies if I improperly report a transportation allowance?
top
(a) If you or your affiliate deducts a transportation allowance on Form MMS–2014 that exceeds 50
percent of the value of the oil transported without obtaining ONRR's prior approval under §1206.109,
you must pay interest on the excess allowance amount taken from the date that amount is taken to the
date you or your affiliate files an exception request that ONRR approves. If you do not file an exception
request, or if ONRR does not approve your request, you must pay interest on the excess allowance
amount taken from the date that amount is taken until the date you pay the additional royalties owed.

(b) If you or your affiliate takes a deduction for transportation on Form MMS–2014 by improperly netting
an allowance against the oil instead of reporting the allowance as a separate entry, ONRR may assess a
civil penalty under 30 CFR part 1241.
[73 FR 15890, Mar. 26, 2008]

§ 1206.117 What reporting adjustments must I make for transportation allowances?
top
(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 §218.54 of this chapter 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.

§ 1206.119 How are royalty quantity and quality determined?
top
(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 BOEMRE 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
BOEMRE for offshore leases, adjust the value for those differences in quantity or quality.
(c) Any actual loss that you may incur before the royalty settlement metering or measurement point is
not subject to royalty if BLM orBOEMRE, as appropriate, determines that the loss is unavoidable.
(d) Except as provided in paragraph (b) of this section, royalties are due on 100 percent of the volume
measured at the approved point of royalty settlement. You may not claim a reduction in that measured
volume for actual losses beyond the approved point of royalty settlement or for theoretical losses that
are claimed to have taken place either before or after the approved point of royalty settlement.
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24979, May 5, 2004]

§ 1206.120 How are operating allowances determined?
top
BOEMRE may use an operating allowance for the purpose of computing payment obligations when
specified in the notice of sale and the lease. BOEMRE will specify the allowance amount or formula in
the notice of sale and in the lease agreement.

Subpart D—Federal Gas
top

Source: 53 FR 1272, Jan. 15, 1988, unless otherwise noted.
§ 1206.150 Purpose and scope.

top
(a) This subpart is applicable to all gas production from Federal oil and gas leases. The purpose of this
subpart is to establish the value of production for royalty purposes consistent with the mineral leasing
laws, other applicable laws and lease terms.
(b) If the regulations in this subpart are inconsistent with:
(1) A Federal statute;
(2) A settlement agreement between the United States and a lessee resulting from administrative or
judicial litigation;
(3) A written agreement between the lessee and the ONRR Director establishing a method to determine
the value of production from any lease that ONRR expects at least would approximate the value
established under this subpart; or
(4) An express provision of an oil and gas lease subject to this subpart; then the statute, settlement
agreement, written agreement, or lease provision will govern to the extent of the inconsistency.
(c) All royalty payments made to ONRR are subject to audit and adjustment.
(d) The regulations in this subpart are intended to ensure that the administration of oil and gas leases is
discharged in accordance with the requirements of the governing mineral leasing laws and lease terms.
[61 FR 5464, Feb. 12, 1996, as amended at 70 FR 11877, Mar. 10, 2005]

§ 1206.151 Definitions.
top
For purposes of this subpart:
Affiliate means a person who controls, is controlled by, or is under common control with another person.
For purposes of this subpart:
(1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of
ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10
percent constitutes a presumption of noncontrol that ONRR may rebut.
(2) If there is ownership or common ownership of 10 through 50 percent of the voting securities or
instruments of ownership, or other forms of ownership, of another person, ONRR will consider the
following factors in determining whether there is control under the circumstances of a particular case:
(i) The extent to which there are common officers or directors;
(ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership: The
percentage of ownership or common ownership, the relative percentage of ownership or common
ownership compared to the percentage(s) of ownership by other persons, whether a person is the
greatest single owner, or whether there is an opposing voting bloc of greater ownership;
(iii) Operation of a lease, plant, pipeline, or other facility;
(iv) The extent of participation by other owners in operations and day-to-day management of a lease,
plant, pipeline, or other facility; and
(v) Other evidence of power to exercise control over or common control with another person.

(3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or
marriage, are affiliates.
Allowance means a deduction in determining value for royalty purposes. Processing allowance means
an allowance for the reasonable, actual costs of processing gas determined under this subpart.
Transportation allowance means an allowance for the reasonable, actual costs of moving unprocessed
gas, residue gas, or gas plant products to a point of sale or delivery off the lease, unit area, or
communitized area, or away from a processing plant. The transportation allowance does not include
gathering costs.
Area means a geographic region at least as large as the defined limits of an oil and/or gas field, in which
oil and/or gas lease products have similar quality, economic, and legal characteristics.
Arm's-length contract means a contract or agreement between independent persons who are not
affiliates and who have opposing economic interests regarding that contract. To be considered arm's
length for any production month, a contract must satisfy this definition for that month, as well as when
the contract was executed.
Audit means a review, conducted in accordance with generally accepted accounting and auditing
standards, of royalty payment compliance activities of lessees or other interest holders who pay
royalties, rents, or bonuses on Federal leases.
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 byBOEMRE.
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 BOEMRE OCS operations personnel for onshore and OCS
leases, respectively.
Gross proceeds (for royalty payment purposes) means the total monies and other consideration
accruing to an oil and gas lessee for the disposition of the gas, residue gas, and gas plant products
produced. Gross proceeds includes, but is not limited to, payments to the lessee for certain services
such as dehydration, measurement, and/or gathering to the extent that the lessee is obligated to perform
them at no cost to the Federal Government. Tax reimbursements are part of the gross proceeds
accruing to a lessee even though the Federal royalty interest may be exempt from taxation. Monies and
other consideration, including the forms of consideration identified in this paragraph, to which a lessee is
contractually or legally entitled but which it does not seek to collect through reasonable efforts are also

part of gross proceeds.
Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or
approved by the United States under a mineral leasing law that authorizes exploration for, development
or extraction of, or removal of lease products—or the land area covered by that authorization, whichever
is required by the context.
Lease products means any leased minerals attributable to, originating from, or allocated to Outer
Continental Shelf or onshore Federal leases.
Lessee means any person to whom the United States issues a lease, and any person who has been
assigned an obligation to make royalty or other payments required by the lease. This includes any
person who has an interest in a lease as well as an operator or payor who has no interest in the lease
but who has assumed the royalty payment responsibility.
Like-quality lease products means lease products which have similar chemical, physical, and legal
characteristics.
Marketable condition means lease products which are sufficiently free from impurities and otherwise in a
condition that they will be accepted by a purchaser under a sales contract typical for the field or area.
Marketing affiliate means an affiliate of the lessee whose function is to acquire only the lessee's
production and to market that production.
Minimum royalty means that minimum amount of annual royalty that the lessee must pay as specified in
the lease or in applicable leasing regulations.
Net-back method (or work-back method) means a method for calculating market value of gas at the
lease. Under this method, costs of transportation, processing, or manufacturing are deducted from the
proceeds received for the gas, residue gas or gas plant products, and any extracted, processed, or
manufactured products, or from the value of the gas, residue gas or gas plant products, and any
extracted, processed, or manufactured products, at the first point at which reasonable values for any
such products may be determined by a sale pursuant to an arm's-length contract or comparison to other
sales of such products, to ascertain value at the lease.
Net output means the quantity of residue gas and each gas plant product that a processing plant
produces.
Net profit share (for applicable Federal leases) means the specified share of the net profit from
production of oil and gas as provided in the agreement.
Netting means the deduction of an allowance from the sales value by reporting a net sales value,
instead of correctly reporting the deduction as a separate entry on Form MMS–2014.
Outer Continental Shelf (OCS) means all submerged lands lying seaward and outside of the area of land
beneath navigable waters as defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of
which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and
control.
Person means any individual, firm, corporation, association, partnership, consortium, or joint venture
(when established as a separate entity).
Posted price means the price, net of all adjustments for quality and location, specified in publicly
available price bulletins or other price notices available as part of normal business operations for
quantities of unprocessed gas, residue gas, or gas plant products in marketable condition.
Processing means any process designed to remove elements or compounds (hydrocarbon and
nonhydrocarbon) from gas, including absorption, adsorption, or refrigeration. Field processes which
normally take place on or near the lease, such as natural pressure reduction, mechanical separation,
heating, cooling, dehydration, and compression, are not considered processing. The changing of
pressures and/or temperatures in a reservoir is not considered processing.

Residue gas means that hydrocarbon gas consisting principally of methane resulting from processing
gas.
Sales type code means the contract type or general disposition (e.g., arm's-length or non-arm's-length)
of production from the lease. The sales type code applies to the sales contract, or other disposition, and
not to the arm's-length or non-arm's-length nature of a transportation or processing allowance.
Section 6 lease means an OCS lease subject to section 6 of the Outer Continental Shelf Lands Act, as
amended, 43 U.S.C. 1335.
Spot sales agreement means a contract wherein a seller agrees to sell to a buyer a specified amount of
unprocessed gas, residue gas, or gas plant products at a specified price over a fixed period, usually of
short duration, which does not normally require a cancellation notice to terminate, and which does not
contain an obligation, nor imply an intent, to continue in subsequent periods.
Warranty contract means a long-term contract entered into prior to 1970, including any amendments
thereto, for the sale of gas wherein the producer agrees to sell a specific amount of gas and the gas
delivered in satisfaction of this obligation may come from fields or sources outside of the designated
fields.
[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45084, Nov. 8, 1988; 61 FR 5464, Feb. 12, 1996; 64
FR 43288, Aug. 10, 1999; 70 FR 11878, Mar. 10, 2005; 73 FR 15890, Mar. 26, 2008]

§ 1206.152 Valuation standards—unprocessed gas.
top
(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 §1206.155 of this part. Where the lessee's contract
includes a reservation of the right to process the gas and the lessee exercises that right, §1206.153 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, ONRR 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 ONRR 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 ONRR 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 ONRR 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 ONRR determines that the value may be
unreasonable, ONRR 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 ONRR determines that the price specified in the
transportation contract for over-delivered volumes is unreasonably low, the lessee must value all overdelivered volumes under paragraph (c)(2) or (c)(3) of this section.
(2) Notwithstanding the provisions of paragraph (b)(1) of this section, the value of gas sold pursuant to a
warranty contract shall be determined by ONRR, 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 ONRR.
(3) ONRR 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 ONRR 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
ONRR 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 ONRR 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 ONRR if it has determined value pursuant to paragraph (c)(2) or (c)(3) of this
section. The notification shall be by letter to the ONRR Director for Office of Natural Resources Revenue
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 ONRR 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 ONRR. The lessee shall also pay interest
on that difference computed pursuant to §1218.54 of this chapter. If the lessee is entitled to a credit,
ONRR will provide instructions for the taking of that credit.
(g) The lessee may request a value determination from ONRR. In that event, the lessee shall propose to
ONRR a value determination method, and may use that method in determining value for royalty
purposes until ONRR issues its decision. The lessee shall submit all available data relevant to its
proposal. The ONRR shall expeditiously determine the value based upon the lessee's proposal and any
additional information ONRR deems necessary. In making a value determination ONRR may use any of
the valuation criteria authorized by this subpart. That determination shall remain effective for the period
stated therein. After ONRR 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 ONRR 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 ONRR to support valuation proposals, including transportation 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 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]

§ 1206.153 Valuation standards—processed gas.

top
(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 §1206.152
of this part. This section applies where the lessee's contract includes a reservation of the right to
process the gas and the lessee exercises that right.
(2) The value of production, for royalty purposes, of gas subject to this section shall be the combined
value of the residue gas and all gas plant products determined pursuant to this section, plus the value of
any condensate recovered downstream of the point of royalty settlement without resorting to processing
determined pursuant to §1206.102 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, ONRR 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 ONRR
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 ONRR 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
ONRR 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 ONRR determines that the value may be unreasonable, ONRR 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 ONRR determines that the price specified in the
transportation contract for over-delivered volumes is unreasonably low, the lessee must value all overdelivered 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 ONRR, 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 ONRR.
(3) ONRR may require a lessee to certify that its arm's-length contract provisions include all of the
consideration to be paid by the buyer, either directly or indirectly, for the residue gas or gas plant
product.
(c) The value of residue gas or any gas plant product which is not sold pursuant to an arm's-length
contract shall be the reasonable value determined in accordance with the first applicable of the following
methods:
(1) The gross proceeds accruing to the lessee pursuant to a sale under its non-arm's-length contract (or
other disposition other than by an arm's-length contract), provided that those gross proceeds are

equivalent to the gross proceeds derived from, or paid under, comparable arm's-length contracts for
purchases, sales, or other dispositions of like quality residue gas or gas plant products from the same
processing plant (or, if necessary to obtain a reasonable sample, from nearby plants). In evaluating the
comparability of arm's-length contracts for the purposes of these regulations, the following factors shall
be considered: price, time of execution, duration, market or markets served, terms, quality of residue gas
or gas plant products, volume, and such other factors as may be appropriate to reflect the value of the
residue gas or gas plant products;
(2) A value determined by consideration of other information relevant in valuing like-quality residue gas
or gas plant products, including gross proceeds under arm's-length contracts for like-quality residue gas
or gas plant products from the same gas plant or other nearby processing plants, posted prices for
residue gas or gas plant products, prices received in spot sales of residue gas or gas plant products,
other reliable public sources of price or market information, and other information as to the particular
lease operation or the saleability of such residue gas or gas plant products; or
(3) A net-back method or any other reasonable method to determine value.
(d)(1) Notwithstanding any other provisions of this section, except paragraph (h) of this section, if the
maximum price permitted by Federal law at which any residue gas or gas plant products may be sold is
less than the value determined pursuant to this section, then ONRR 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
ONRR 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 ONRR 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 ONRR 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 ONRR Director for Office of Natural Resources 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 ONRR 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 ONRR. The lessee shall also pay interest
computed on that difference pursuant to §1218.54 of this chapter. If the lessee is entitled to a credit,
ONRR will provide instructions for the taking of that credit.
(g) The lessee may request a value determination from ONRR. In that event, the lessee shall propose to
ONRR a value determination method, and may use that method in determining value for royalty
purposes until ONRR issues its decision. The lessee shall submit all available data relevant to its
proposal. The ONRR shall expeditiously determine the value based upon the lessee's proposal and any
additional information ONRR deems necessary. In making a value determination, ONRR may use any of
the valuation criteria authorized by this subpart. That determination shall remain effective for the period
stated therein. After ONRR 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 ONRR 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 ONRR 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]

§ 1206.154 Determination of quantities and qualities for computing royalties.
top
(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 BOEMRE for onshore and OCS leases, respectively.
(2) If the value of gas determined pursuant to §1206.152 of this subpart is based upon a quantity and/or
quality that is different from the quantity and/or quality at the point of royalty settlement, as approved by
BLM orBOEMRE, 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 §1206.153 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 ONRR 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 orBOEMRE, as appropriate.
(2) Except as provided in paragraph (d)(1) of this section and §1202.151(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]

§ 1206.155 Accounting for comparison.
top
(a) Except as provided in paragraph (b) of this section, where the lessee (or a person to whom the
lessee has transferred gas pursuant to a non-arm's-length contract or without a contract) processes the
lessee's gas and after processing the gas the residue gas is not sold pursuant to an arm's-length
contract, the value, for royalty purposes, shall be the greater of (1) the combined value, for royalty
purposes, of the residue gas and gas plant products resulting from processing the gas determined
pursuant to §1206.153 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
§1206.102 of this subpart; or (2) the value, for royalty purposes, of the gas prior to processing
determined in accordance with §1206.152 of this subpart.
(b) The requirement for accounting for comparison contained in the terms of leases will govern as
provided in §1206.150(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]

§ 1206.156 Transportation allowances—general.
top
(a) Where the value of gas has been determined pursuant to §1206.152 or §1206.153 of this subpart at
a point (e.g., sales point or point of value determination) off the lease, ONRR 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
§1206.157.
(c)(1) Except as provided in paragraph (c)(3) of this section, for unprocessed gas valued in accordance
with §1206.152 of this subpart, the transportation allowance deduction on the basis of a sales type code
may not exceed 50 percent of the value of the unprocessed gas determined under §1206.152 of this
subpart.
(2) Except as provided in paragraph (c)(3) of this section, for gas production valued in accordance with
§1206.153 of this subpart, the transportation allowance deduction on the basis of a sales type code may
not exceed 50 percent of the value of the residue gas or gas plant product determined under §1206.153
of this subpart. For purposes of this section, natural gas liquids will be considered one product.
(3) Upon request of a lessee, ONRR may approve a transportation allowance deduction in excess of the
limitations prescribed by paragraphs (c)(1) and (c)(2) of this section. The lessee must demonstrate that
the transportation costs incurred in excess of the limitations prescribed in paragraphs (c)(1) and (c)(2) of
this section were reasonable, actual, and necessary. An application for exception (using Form MMS–
4393, Request to Exceed Regulatory Allowance Limitation) must contain all relevant and supporting
documentation necessary for ONRR to make a determination. Under no circumstances may the value
for royalty purposes under any sales type code be reduced to zero.
(d) If, after a review or audit, ONRR determines that a lessee has improperly determined a transportation
allowance authorized by this subpart, then the lessee must pay any additional royalties, plus interest,
determined in accordance with §1218.54 of this chapter, or will be entitled to a credit, with interest. If the
lessee takes a deduction for transportation on Form MMS–2014 by improperly netting the allowance
against the sales value of the unprocessed gas, residue gas, and gas plant products instead of reporting
the allowance as a separate entry, ONRR may assess a civil penalty under 30 CFR part 1241.
[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5465, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999;
73 FR 15890, Mar. 26, 2008]

§ 1206.157 Determination of transportation allowances.
top
(a) Arm's-length transportation contracts. (1)(i) For transportation costs incurred by a lessee under an
arm's-length contract, the transportation allowance shall be the reasonable, actual costs incurred by the
lessee for transporting the unprocessed gas, residue gas and/or gas plant products under that contract,
except as provided in paragraphs (a)(1)(ii) and (a)(1)(iii) of this section, subject to monitoring, review,
audit, and adjustment. The lessee shall have the burden of demonstrating that its contract is arm'slength. ONRR' prior approval is not required before a lessee may deduct costs incurred under an arm'slength contract. Such allowances shall be subject to the provisions of paragraph (f) of this section. The
lessee must claim a transportation allowance by reporting it as a separate entry on the Form MMS–
2014.
(ii) In conducting reviews and audits, ONRR 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 ONRR may require that
the transportation allowance be determined in accordance with paragraph (b) of this section.

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

payment by the lessee to the pipeline.
(iii) If during any production month there are no prices paid under the tariff by third parties to transport
gas on the system under arm's-length transportation contracts, you may use the volume-weighted
average of the rates paid by third parties under arm's-length transportation contracts in the most recent
preceding production month in which the tariff remains in effect and third parties paid such rates, for up
to five successive production months. You must use the non-arm's-length payment by the lessee to the
pipeline if it is less than the volume-weighted average of the rates paid by third parties under arm'slength contracts.
(c) Reporting requirements —(1) Arm's-length contracts. (i) You must use a separate entry on Form
MMS–2014 to notify ONRR of a transportation allowance.
(ii) ONRR may require you to submit arm's-length transportation contracts, production agreements,
operating agreements, and related documents. Recordkeeping requirements are found at part 1207 of
this chapter.
(iii) You may not use a transportation allowance that was in effect before March 1, 1988. You must use
the provisions of this subpart to determine your transportation allowance.
(2) Non-arm's-length or no contract. (i) You must use a separate entry on Form MMS–2014 to notify
ONRR of a transportation allowance.
(ii) For new transportation facilities or arrangements, base your initial deduction on estimates of
allowable gas transportation costs for the applicable period. Use the most recently available operations
data for the transportation system or, if such data are not available, use estimates based on data for
similar transportation systems. Paragraph (e) of this section will apply when you amend your report
based on your actual costs.
(iii) ONRR may require you to submit all data used to calculate the allowance deduction. Recordkeeping
requirements are found at part 1207 of this chapter.
(iv) If you are authorized under paragraph (b)(5) of this section to use an exception to the requirement to
calculate your actual transportation costs, you must follow the reporting requirements of paragraph (c)(1)
of this section.
(v) You may not use a transportation allowance that was in effect before March 1, 1988. You must use
the provisions of this subpart to determine your transportation allowance.
(d) Interest and assessments. (1) If a lessee 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 ONRR
under §1206.156, the lessee shall pay interest on the excess allowance amount taken from the date
such amount is taken to the date the lessee files an exception request with ONRR.
(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 §1218.54 of this
chapter.
(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 §1218.54 of this chapter from the allowance
reporting period when the lessee took the deduction to the date the lessee repays the difference to
ONRR. 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 ONRR.

(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 ONRR. If the lessee's estimated transportation allowance is less than the
allowance based on actual costs, the refund procedure will be specified by ONRR.
(f) Allowable costs in determining transportation allowances. You may include, but are not limited to
(subject to the requirements of paragraph (g) of this section), the following costs in determining the
arm's-length transportation allowance under paragraph (a) of this section or the non-arm's-length
transportation allowance under paragraph (b) of this section. You may not use any cost as a deduction
that duplicates all or part of any other cost that you use under this paragraph.
(1) Firm demand charges paid to pipelines. You may deduct firm demand charges or capacity
reservation fees paid to a pipeline, including charges or fees for unused firm capacity that you have not
sold before you report your allowance. If you receive a payment from any party for release or sale of firm
capacity after reporting a transportation allowance that included the cost of that unused firm capacity, or
if you receive a payment or credit from the pipeline for penalty refunds, rate case refunds, or other
reasons, you must reduce the firm demand charge claimed on the Form MMS–2014 by the amount of
that payment. You must modify the Form MMS–2014 by the amount received or credited for the affected
reporting period, and pay any resulting royalty and late payment interest due;
(2) Gas supply realignment (GSR) costs. The GSR costs result from a pipeline reforming or terminating
supply contracts with producers to implement the restructuring requirements of FERC Orders in 18 CFR
part 284;
(3) Commodity charges. The commodity charge allows the pipeline to recover the costs of providing
service;
(4) Wheeling costs. Hub operators charge a wheeling cost for transporting gas from one pipeline to
either the same or another pipeline through a market center or hub. A hub is a connected manifold of
pipelines through which a series of incoming pipelines are interconnected to a series of outgoing
pipelines;
(5) Gas Research Institute (GRI) fees. The GRI conducts research, development, and commercialization
programs on natural gas related topics for the benefit of the U.S. gas industry and gas customers. GRI
fees are allowable provided such fees are mandatory in FERC-approved tariffs;
(6) Annual Charge Adjustment (ACA) fees. FERC charges these fees to pipelines to pay for its operating
expenses;
(7) Payments (either volumetric or in value) for actual or theoretical losses. However, theoretical losses
are not deductible in non-arm's-length transportation arrangements unless the transportation allowance
is based on arm's-length transportation rates charged under a FERC- or state regulatory-approved tariff
under paragraph (b)(5) of this section. If you receive volumes or credit for line gain, you must reduce
your transportation allowance accordingly and pay any resulting royalties and late payment interest due;
(8) Temporary storage services. This includes short duration storage services offered by market centers
or hubs (commonly referred to as “parking” or “banking”), or other temporary storage services provided
by pipeline transporters, whether actual or provided as a matter of accounting. Temporary storage is
limited to 30 days or less; and
(9) Supplemental costs for compression, dehydration, and treatment of gas. ONRR allows these costs
only if such services are required for transportation and exceed the services necessary to place
production into marketable condition required under §§1206.152(i) and 1206.153(i) of this part.
(10) Costs of surety. You may deduct the costs of securing a letter of credit, or other surety, that the
pipeline requires you as a shipper to maintain under an arm's-length transportation contract.
(g) Nonallowable costs in determining transportation allowances. Lessees may not include the following
costs in determining the arm's-length transportation allowance under paragraph (a) of this section or the
non-arm's-length transportation allowance under paragraph (b) of this section:

(1) Fees or costs incurred for storage. This includes storing production in a storage facility, whether on
or off the lease, for more than 30 days;
(2) Aggregator/marketer fees. This includes fees you pay to another person (including your affiliates) to
market your gas, including purchasing and reselling the gas, or finding or maintaining a market for the
gas production;
(3) Penalties you incur as shipper. These penalties include, but are not limited to:
(i) Over-delivery cash-out penalties. This includes the difference between the price the pipeline pays you
for over-delivered volumes outside the tolerances and the price you receive for over-delivered volumes
within the tolerances;
(ii) Scheduling penalties. This includes penalties you incur for differences between daily volumes
delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point;
(iii) Imbalance penalties. This includes penalties you incur (generally on a monthly basis) for differences
between volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or
delivery point; and
(iv) Operational penalties. This includes fees you incur for violation of the pipeline's curtailment or
operational orders issued to protect the operational integrity of the pipeline;
(4) Intra-hub transfer fees. These are fees you pay to hub operators for administrative services (e.g., title
transfer tracking) necessary to account for the sale of gas within a hub;
(5) Fees paid to brokers. This includes fees paid to parties who arrange marketing or transportation, if
such fees are separately identified from aggregator/marketer fees;
(6) Fees paid to scheduling service providers. This includes fees paid to parties who provide scheduling
services, if such fees are separately identified from aggregator/marketer fees;
(7) Internal costs. This includes salaries and related costs, rent/space costs, office equipment costs,
legal fees, and other costs to schedule, nominate, and account for sale or movement of production; and
(8) Other nonallowable costs. Any cost you incur for services you are required to provide at no cost to
the lessor.
(h) Other transportation cost determinations. Use this section when calculating transportation costs to
establish value using a netback procedure or any other procedure that requires deduction of
transportation costs.
[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45762, Nov. 14, 1988; 61 FR 5465, Feb. 12, 1996;
62 FR 65762, Dec. 16, 1997; 70 FR 11878, Mar. 10, 2005; 73 FR 15891, Mar. 26, 2008]

§ 1206.158 Processing allowances—general.
top
(a) Where the value of gas is determined pursuant to §1206.153 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 ONRR 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 662/3percent of the value of each gas plant product
determined in accordance with §1206.153 of this subpart (such value to be reduced first for any
transportation allowances related to postprocessing transportation authorized by §1206.156 of this
subpart).
(3) Upon request of a lessee, ONRR may approve a processing allowance in excess of the limitation
prescribed by paragraph (c)(2) of this section. The lessee must demonstrate that the processing costs
incurred in excess of the limitation prescribed in paragraph (c)(2) of this section were reasonable, actual,
and necessary. An application for exception (using Form MMS–4393, Request to Exceed Regulatory
Allowance Limitation) shall contain all relevant and supporting documentation for ONRR 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, ONRR 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 ONRR 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 ONRR 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 ONRR
in a form and manner prescribed by ONRR.
(e) If ONRR determines that a lessee has improperly determined a processing allowance authorized by
this subpart, then the lessee must pay any additional royalties, plus interest determined under §1218.54
of this chapter, or will be entitled to a credit with interest. If the lessee takes a deduction for processing
on Form MMS–2014 by improperly netting the allowance against the sales value of the gas plant
products instead of reporting the allowance as a separate entry, ONRR may assess a civil penalty under
30 CFR part 1241.
[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5466, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999;
73 FR 15891, Mar. 26, 2008]

§ 1206.159 Determination of processing allowances.
top
(a) Arm's-length processing contracts. (1)(i) For processing costs incurred by a lessee under an arm'slength 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. ONRR' prior approval is not required before a lessee may
deduct costs incurred under an arm's-length contract. The lessee must claim a processing allowance by
reporting it as a separate entry on the Form MMS–2014.
(ii) In conducting reviews and audits, ONRR 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 ONRR may require that
the processing allowance be determined in accordance with paragraph (b) of this section.
(iii) If ONRR 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 ONRR shall require that the processing
allowance be determined in accordance with paragraph (b) of this section. When ONRR determines that
the value of the processing may be unreasonable, ONRR will notify the lessee and give the lessee an
opportunity to provide written information justifying the lessee's processing costs.
(2) If an arm's-length processing contract includes more than one gas plant product and the processing
costs attributable to each product can be determined from the contract, then the processing costs for
each gas plant product shall be determined in accordance with the contract. No allowance may be taken
for the costs of processing lease production which is not royalty-bearing.
(3) If an arm's-length processing contract includes more than one gas plant product and the processing
costs attributable to each product cannot be determined from the contract, the lessee shall propose an
allocation procedure to ONRR. The lessee may use its proposed allocation procedure until ONRR
issues its determination. The lessee shall submit all relevant data to support its proposal. ONRR shall
then determine the processing allowance based upon the lessee's proposal and any additional
information ONRR deems necessary. No processing allowance will be granted for the costs of
processing lease production which is not royalty bearing. The lessee must submit the allocation proposal
within 3 months of claiming the allocated deduction on Form MMS–2014.
(4) Where the lessee's payments for processing under an arm's-length contract are not based on a
dollar per unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent
for the purposes of this section.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-arm's-length processing contract or has no
contract, including those situations where the lessee performs processing for itself, the processing
allowance will be based upon the lessee's reasonable actual costs as provided in this paragraph. All
processing allowances deducted under a non-arm's-length or no-contract situation are subject to
monitoring, review, audit, and adjustment. The lessee must claim a processing allowance by reflecting it
as a separate entry on the Form MMS–2014. When necessary or appropriate, ONRR 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 ONRR.
(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 ONRR
approval. A change in ownership of a processing plant shall not alter the depreciation schedule
established by the original processor/lessee for purposes of the allowance calculation. With or without a
change in ownership, a processing plant shall be depreciated only once. Equipment shall not be

depreciated below a reasonable salvage value.
(B) The ONRR 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 ONRR for an exception from the requirement that it compute actual costs in
accordance with paragraphs (b)(1) through (b)(3) of this section. The ONRR 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 ONRR grants the exception, the lessee shall use as
its processing allowance the volume weighted average prices charged other persons pursuant to arm'slength contracts for processing at the same plant.
(c) Reporting requirements —(1) Arm's-length contracts. (i) The lessee must notify ONRR of an
allowance based on incurred costs by using a separate entry on the Form MMS–2014.
(ii) ONRR 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 ONRR.
(2) Non-arm's-length or no contract. (i) The lessee must notify ONRR of an allowance based on the
incurred costs by using a separate entry on the Form MMS–2014.
(ii) For new processing plants, the lessee's initial deduction shall include estimates of the allowable gas
processing costs for the applicable period. Cost estimates shall be based upon the most recently
available operations data for the plant or, if such data are not available, the lessee shall use estimates
based upon industry data for similar gas processing plants.
(iii) Upon request by ONRR, 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 ONRR.
(iv) If the lessee is authorized to use the volume weighted average prices charged other persons as its
processing allowance in accordance with paragraph (b)(4) of this section, it shall follow the reporting
requirements of paragraph (c)(1) of this section.
(d) Interest. (1) If a lessee deducts a processing allowance on its Form MMS–2014 that exceeds
662/3percent of the value of the gas processed without obtaining prior approval of ONRR under
§1206.158, 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 ONRR.
(2) If a lessee erroneously reports a processing allowance which results in an underpayment of royalties,
interest shall be paid on the amount of that underpayment.
(3) Interest required to be paid by this section shall be determined in accordance with §1218.54 of this
chapter.
(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 §1218.54 of this chapter from the allowance reporting period
when the lessee took the deduction to the date the lessee repays the difference to ONRR. If the actual
processing allowance is greater than the amount the lessee has taken on Form MMS–2014 for each

month during the allowance reporting period, the lessee shall be entitled to a credit with interest.
(2) For lessees processing production from onshore Federal leases, the lessee must submit a corrected
Form MMS–2014 to reflect actual costs, together with any payment, in accordance with instructions
provided by ONRR.
(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
ONRR. If the lessee's estimated costs were less than the actual costs, the refund procedure will be
specified by ONRR.
(f) Other processing cost determinations. The provisions of this section shall apply to determine
processing costs when establishing value using a net back valuation procedure or any other procedure
that requires deduction of processing costs.
[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45762, Nov. 14, 1988; 61 FR 5466, Feb. 12, 1996;
64 FR 43288, Aug. 10, 1999; 73 FR 15891, Mar. 26, 2008]

§ 1206.160 Operating allowances.
top
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
top

Source: 64 FR 43515, Aug. 10, 1999, unless otherwise noted.
§ 1206.170 What does this subpart contain?
top
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 ONRR jointly agree to the valuation
methodology. For leases on Indian allotted lands, you and ONRR must agree to the valuation
methodology.
(d) All royalty payments you make to ONRR 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.

§ 1206.171 What definitions apply to this subpart?
top
The following definitions apply to this subpart and to subpart J of part 1202 of this title:
Accounting for comparison means the same as dual accounting.
Active spot market means a market where one or more ONRR-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 ONRR 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. ONRR may require the lessee to certify the percentage of ownership or control of
the entity. To be considered arm's-length for any production month, a contract must meet the
requirements of this definition for that production month as well as when the contract was executed.
Audit means a review, conducted under generally accepted accounting and auditing standards, of
royalty payment compliance activities of lessees or other persons who pay royalties, rents, or bonuses
on Indian leases.
BIA means the Bureau of Indian Affairs of the Department of the Interior.
BLM means the Bureau of Land Management of the Department of the Interior.
Compression means raising the pressure of gas.
Condensate means liquid hydrocarbons (normally exceeding 40 degrees of API gravity) recovered at the
surface without resorting to processing. Condensate is the mixture of liquid hydrocarbons that results
from condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground

reservoir.
Contract means any oral or written agreement, including amendments or revisions thereto, between two
or more persons and enforceable by law that with due consideration creates an obligation.
Dedicated means a contractual commitment to deliver gas production (or a specified portion of
production) from a lease or well when that production is specified in a sales contract and that production
must be sold pursuant to that contract to the extent that production occurs from that lease or well.
Drip condensate means any condensate recovered downstream of the facility measurement point
without resorting to processing. Drip condensate includes condensate recovered as a result of its
becoming a liquid during the transportation of the gas removed from the lease or recovered at the inlet of
a gas processing plant by mechanical means, often referred to as scrubber condensate.
Dual Accounting (or accounting for comparison ) refers to the requirement to pay royalty based on a
value which is the higher of the value of gas prior to processing less any applicable allowances as
compared to the combined value of drip condensate, residue gas, and gas plant products after
processing, less applicable allowances.
Entitlement (or entitled share ) means the gas production from a lease, or allocable to lease acreage
under the terms of an AFA, multiplied by the operating rights owner's percentage of interest ownership in
the lease or the acreage.
Facility measurement point (or point of royalty settlement ) means the point where the BLM-approved
measurement device is located for determining the volume of gas removed from the lease. The facility
measurement point may be on the lease or off-lease with BLM approval.
Field means a geographic region situated over one or more subsurface oil and gas reservoirs
encompassing at least the outermost boundaries of all oil and gas accumulations known to be within
those reservoirs vertically projected to the land surface. Onshore fields are usually given names and
their official boundaries are often designated by oil and gas regulatory agencies in the respective States
in which the fields are located.
Gas means any fluid, either combustible or noncombustible, hydrocarbon or nonhydrocarbon, which is
extracted from a reservoir and which has neither independent shape nor volume, but tends to expand
indefinitely. It is a substance that exists in a gaseous or rarefied state under standard temperature and
pressure conditions.
Gas plant products means separate marketable elements, compounds, or mixtures, whether in liquid,
gaseous, or solid form, resulting from processing gas. However, it does not include residue gas.
Gathering means the movement of lease production to a central accumulation or treatment point on the
lease, unit, or communitized area; or a central accumulation or treatment point off the lease, unit, or
communitized area as approved by BLM operations personnel.
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 ONRR-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 ONRR under §1206.172(d)(2).
Indian allottee means any Indian for whom land or an interest in land is held in trust by the United States
or who holds title subject to Federal restriction against alienation.
Indian tribe means any Indian tribe, band, nation, pueblo, community, rancheria, colony, or other group
of Indians for which any land or interest in land is held in trust by the United States or which is subject to
Federal restriction against alienation.
Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or
approved by the United States under a mineral leasing law that authorizes exploration for, development
or extraction of, or removal of lease products—or the land area covered by that authorization, whichever
is required by the context. For purposes of this subpart, this definition excludes Federal leases.
Lease products means any leased minerals attributable to, originating from, or allocated to a lease.
Lessee means any person to whom the United States, a tribe, and/or individual Indian landowner issues
a lease, and any person who has been assigned an obligation to make royalty or other payments
required by the lease. This includes any person who has an interest in a lease (including operating rights
owners) as well as an operator or payor who has no interest in the lease but who has assumed the
royalty payment responsibility.
Like-quality lease products means lease products which have similar chemical, physical, and legal
characteristics.
Marketable condition means a condition in which lease products are sufficiently free from impurities and
otherwise so conditioned that a purchaser will accept them under a sales contract typical for the field or
area.
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.
ONRR means the Office of Natural Resources Revenue, Department of the Interior. ONRR 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.
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.
Sales type code means the contract type or general disposition (e.g., arm's-length or non-arm's-length)
of production from the lease. The sales type code applies to the sales contract, or other disposition, and
not to the arm's-length or non-arm's-length nature of a transportation or processing allowance.
Spot sales agreement means a contract wherein a seller agrees to sell to a buyer a specified amount of
unprocessed gas, residue gas, or gas plant products at a specified price over a fixed period, usually of
short duration. It also does not normally require a cancellation notice to terminate, and does not contain
an obligation, or imply an intent, to continue in subsequent periods.
Takes means when the operating rights owner sells or removes production from, or allocated to, the
lease, or when such sale or removal occurs for the benefit of an operating rights owner.
Work-back method means the same as net-back method.
[64 FR 43515, Aug. 10, 1999, as amended at 73 FR 15891, Mar. 26, 2008]

§ 1206.172 How do I value gas produced from leases in an index zone?
top
(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 §1206.174.
(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 §1206.174.
(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 indexbased 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 §1206.172(e)(4)(i) exceeds the index-based value that
applies to the gas under this section (including any adjustments required under §1206.176), then the
value of the gas is the higher of the value determined under this section (including any adjustments
required under §1206.176) or §1206.174.
(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
§1206.174(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
§1206.173 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 §1206.174, 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 ONRR-approved publication, calculate the average of the highest reported prices for all
index-pricing points in the index zone, except for any prices excluded under paragraph (d)(6) of this
section;
(ii) Sum the averages calculated in paragraph (d)(1)(i) of this section and divide by the number of
publications; and
(iii) Reduce the number calculated under paragraph (d)(1)(ii) of this section by 10 percent, but not by
less than 10 cents per MMBtu or more than 30 cents per MMBtu. The result is the index-based value per
MMBtu for production from all leases in that index zone.
(2) ONRR will publish in the Federal Register the index zones that are eligible for the index-based
valuation method under this paragraph. ONRR 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 theFederal Register.ONRR will consider the following five factors and
conditions in determining eligible index zones:
(i) Areas for which ONRR-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 ONRR'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, ONRR will hold a technical conference to consider disqualification of an
index zone. ONRR 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) ONRR 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 ONRR to be added to the list of acceptable publications.
(6) ONRR may exclude an individual index price for an index zone in an ONRR-approved publication if
ONRR determines that the index price does not accurately reflect the value of production in that index
zone. ONRR will publish a list of excluded indices in the Federal Register .
(7) ONRR 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 §§1206.177, 1206.178, 1206.179, and
1206.180.
(e) Determining the minimum value for royalty purposes of gas sold beyond the first index pricing point.
(1) Notwithstanding any other provision of this section, the value for royalty purposes of gas production
from an Indian lease that is sold beyond the first index pricing point through which it flows cannot be less
than the value determined under this paragraph (e).
(2) By June 30 following any calendar year, you must calculate for each month of that calendar year
your safety net price per MMBtu using the procedures in paragraph (e)(3) of this section. You must
calculate a safety net price for each month and for each index zone where you have an Indian lease for
which you report and pay royalties.
(3) Your safety net price (S) for an index zone is the volume-weighted average contract price per
delivered MMBtu under your or your affiliate's arm's-length contracts for the disposition of residue gas or
unprocessed gas produced from your Indian leases in that index zone as computed under this
paragraph (e)(3).
(i) Include in your calculation only sales under those contracts that establish a delivery point beyond the
first index pricing point through which the gas flows, and that include any gas produced from or allocable
to one or more of your Indian leases in that index zone, even if the contract also includes gas produced
from Federal, State, or fee properties. Include in your volume-weighted average calculation those
volumes that are allocable to your Indian leases in that index zone.
(ii) Do not reduce the contract price for any transportation costs incurred to deliver the gas to the
purchaser.
(iii) For purposes of this paragraph (e), the contract price will not include the following amounts:

(A) Any amounts you receive in compromise or settlement of a predecessor contract for that gas;
(B) Deductions for you or any other person to put gas production into marketable condition or to market
the gas; and
(C) Any amounts related to marketable securities associated with the sales contract.
(4) Next, you must determine for each month the safety net differential (SND). You must perform this
calculation separately for each index zone.
(i) For each index zone, the safety net differential is equal to: SND = [(0.80 × S) − (1.25 × 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 × V × 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 nonIndian 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 ONRR 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) ONRR 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 ONRR 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
ONRR to exclude some or all of its leases from valuation under this section. ONRR will consult with BIA
regarding the request.
(i) If ONRR approves the request for your lease, you must value your production under §1206.174
beginning with production on the first day of the second month following the date ONRR 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, ONRR 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 ONRR to terminate exclusion of its leases from valuation under this section.
ONRR will consult with BIA regarding the request.
(i) If ONRR approves the request, you must value your production under §1206.172 beginning with

production on the first day of the second month following the date ONRR 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 ONRR 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) ONRR may exclude any
Indian allotted leases from valuation under this section. ONRR will consult with BIA regarding the
exclusion.
(ii) If ONRR excludes your lease, you must value your production under §1206.174 beginning with
production on the first day of the second month following the date ONRR publishes notice of its decision
in the Federal Register .
(iii) If ONRR excludes any Indian allotted leases under this paragraph (g)(1), it will exclude all Indian
allotted leases in the same field.
(2)(i) ONRR may terminate the exclusion of any Indian allotted leases from valuation under this section.
ONRR will consult with BIA regarding the termination.
(ii) If ONRR terminates the exclusion, you must value your production under §1206.172 beginning with
production on the first day of the second month following the date ONRR publishes notice of its decision
in the Federal Register .

§ 1206.173 How do I calculate the alternative methodology for dual accounting?
top
(a) Electing a dual accounting method. (1) If you are required to perform the accounting for comparison
(dual accounting) under §1206.176, you have two choices. You may elect to perform the dual
accounting calculation according to either §1206.176(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 ONRR-designated area. Your election for a designated area must apply to all of
your Indian leases in that area.
(i) ONRR 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 ONRR-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) ONRR-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 ONRR designates. ONRR 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 ONRR and the
tribal lessor for tribal leases, and ONRR 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 §1206.172 or
§1206.174 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 §1206.172
or §1206.174, as follows:
(i) Value of gas after processing = (value determined under either §1206.172 or §1206.174, as
applicable) × (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:

BTU
range
1001 to
1050
1051 to
1100
1101 to
1150

Increment if Lessee has no
ownership interest in plant
.0275

Increment if lessee has an
ownership interest in plant
.0375

.0400

.0625

.0425

.0750

1151 to
1200
1201 to
1250
1251 to
1300
1301 to
1350
1351 to
1400
1401 to
1450
1451 to
1500
1501 to
1550
1551 to
1600
1601 to
1650
1651 to
1700
1701+

.0700

.1225

.0975

.1700

.1175

.2050

.1400

.2400

.1450

.2500

.1500

.2600

.1550

.2700

.1600

.2800

.1650

.2900

.1850

.3225

.1950

.3425

.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.

§ 1206.174 How do I value gas production when an index-based method cannot be
used?
top
(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 ONRR 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
§1206.174(b) or the value under §1206.172.
(iii) Also use this section to value any other gas production that cannot be valued under §1206.172, 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 §1206.176.
(4) This paragraph applies if your lease has a major portion provision. It also applies if your lease does
not have a major portion provision but the lease provides for the Secretary to determine value.
(i) The value of production you must initially report and pay is the value determined in accordance with
the other paragraphs of this section.
(ii) ONRR 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 ONRR by the due date specified in the written notice from ONRR of the major
portion value. Late-payment interest under §1218.54 of this chapter on any underpayment will not begin
to accrue until the date the amended Form MMS–2014 is due to ONRR.
(iii) Except as provided in paragraph (a)(4)(iv) of this section, ONRR will calculate the major portion
value for each designated area (which are the same designated areas as under §1206.173) 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. ONRR 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. ONRR cannot unilaterally change the major portion value after you are notified
in writing of what that value is for your leases.
(iv) ONRR 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 ONRR
has reviewed in the designated area. ONRR may use this alternate or the augmented data source
beginning with production on the first day of the month following the date ONRR 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,
ONRR 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 ONRR 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 ONRR 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 ONRR 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, ONRR will notify you and give you an opportunity to
provide written information justifying your value.
(iv) This paragraph applies to situations where a pipeline purchases gas from a lessee according to a
cash-out program under a transportation contract. For all over-delivered volumes, the royalty value is the
price the pipeline is required to pay for volumes within the tolerances for over-delivery specified in the
transportation contract. Use the same value for volumes that exceed the over-delivery tolerances even if
those volumes are subject to a lower price specified in the transportation contract. However, if ONRR
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) ONRR 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 ONRR 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 ONRR 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 ONRR 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 ONRR established. You also must pay interest computed
on that difference under §1218.54 of this chapter. If you are entitled to a credit, ONRR will provide
instructions on how to take that credit.
(f) Value guidance. You may ask ONRR for guidance in determining value. You may propose a valuation
method to ONRR. Submit all available data related to your proposal and any additional information
ONRR deems necessary. ONRR will promptly review your proposal and provide you with a non-binding

determination of the guidance you request.
(g) Minimum value of production. (1) For gas, residue gas, and gas plant products valued under this
section, under no circumstances may the value of production for royalty purposes be less than the gross
proceeds accruing to the lessee (including its affiliates) for gas, residue gas and/or any gas plant
products, less applicable transportation allowances and processing allowances determined under this
subpart.
(2) For gas plant products valued under this section and not valued under §1206.173, 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 ONRR reviews. Notwithstanding any provision in these regulations to the contrary, no
review, reconciliation, monitoring, or other like process that results in an ONRR 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 ONRR to support valuation proposals,
including transportation allowances and processing allowances, may be exempted from disclosure under
the Freedom of Information Act, 5 U.S.C. 552, or other Federal law. Any data specified by law to be
privileged, confidential, or otherwise exempt, will be maintained in a confidential manner in accordance
with applicable laws and regulations. All requests for information about determinations made under this
subpart must be submitted in accordance with the Freedom of Information Act regulation of the
Department of the Interior, 43 CFR part 2.

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

§ 1206.175 How do I determine quantities and qualities of production for computing
royalties?
top
(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 ONRR approval of other methods for determining the quantity of residue gas and
gas plant products allocable to each lease. If ONRR 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.

§ 1206.176 How do I perform accounting for comparison?
top

(a) This section applies if the gas produced from your Indian lease is processed and that Indian lease
requires accounting for comparison (also referred to as actual dual accounting). Except as provided in
paragraphs (b) and (c) of this section, the actual dual accounting value, for royalty purposes, is the
greater of the following two values:
(1) The combined value of the following products:
(i) The residue gas and gas plant products resulting from processing the gas determined under either
§1206.172 or §1206.174, 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 §1206.52, less applicable allowances.
(2) The value of the gas prior to processing determined under either §1206.172 or §1206.174, 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 §1206.173 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 ONRR 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 §1206.173, 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
§1206.173(b)(4)(ii) to determine if you must perform a dual accounting calculation.

Transportation Allowances
top

§ 1206.177 What general requirements regarding transportation allowances apply to
me?
top
(a) When you value gas under §1206.174 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
§1206.178.
(c)(1) Except as provided in paragraphs (c)(2) and (3) of this section, your transportation allowance
deduction for each sales type code may not exceed 50 percent of the value of the unprocessed gas,
residue gas, or gas plant product. For purposes of this section, natural gas liquids are considered one
product.
(2) If you ask ONRR, ONRR may approve a transportation allowance deduction in excess of the

limitations in paragraph (c)(1) of this section. To receive this approval, you must demonstrate that the
transportation costs incurred in excess of the limitations in paragraph (c)(1) of this section were
reasonable, actual, and necessary. Under no circumstances may an allowance reduce the value for
royalty purposes under any sales type code to zero.
(3) Your application for exception (using Form MMS–4393, Request to Exceed Regulatory Allowance
Limitation) must contain all relevant and supporting documentation necessary for ONRR to make a
determination.
(d) If ONRR 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 §1218.54 of this chapter. Alternatively, you may be
entitled to a credit, but you will not receive any interest on your overpayment.
[64 FR 43515, Aug. 10, 1999, as amended at 73 FR 15891, Mar. 26, 2008]

§ 1206.178 How do I determine a transportation allowance?
top
(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 ONRR a copy of your
arm's-length transportation contract(s) and all subsequent amendments to the contract(s) within 2
months of the date ONRR receives your report which claims the allowance on the Form MMS–2014.
(ii) When either ONRR 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
ONRR may require that the transportation allowance be determined under paragraph (b) of this section.
(iii) If ONRR 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 ONRR will require that the transportation allowance be determined
under paragraph (b) of this section. In these circumstances, ONRR 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 ONRR approval, or without lessor approval on tribal leases.
(ii) As an alternative to paragraph (a)(2)(i) of this section, you may propose to ONRR a cost allocation
method based on the values of the products transported. ONRR 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 ONRR. You may use the transportation allowance determined in accordance
with your proposed allocation procedure until ONRR decides whether to accept your cost allocation.
(ii) You are required to submit all relevant data to support your allocation proposal. ONRR will then
determine the gas transportation allowance based upon your proposal and any additional information
ONRR 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, ONRR
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 ONRR
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 ONRR 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, ONRR may approve a longer
time period. ONRR will monitor the allowance deductions to ensure that deductions are reasonable and
allowable. When necessary or appropriate, ONRR 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 ONRR 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 ONRR approval.
A change in ownership of a transportation system will not alter the depreciation schedule that the original
transporter/lessee established for purposes of the allowance calculation. With or without a change in
ownership, a transportation system may be depreciated only once. Equipment may not be depreciated
below a reasonable salvage value. To compute a return on undepreciated capital investment, you will
multiply the undepreciated capital investment in the transportation system by the rate of return
determined under paragraph (b)(2)(v) of this section.
(B) To compute a return on depreciable capital investment, you will multiply the initial capital investment
in the transportation system by the rate of return determined under paragraph (b)(2)(v) of this section.
No allowance will be provided for depreciation. This alternative will apply only to transportation facilities
first placed in service after March 1, 1988.
(v) The rate of return is the industrial rate associated with Standard and Poor's BBB rating. The rate of
return is the monthly average rate as published in Standard and Poor's Bond Guide for the first month of
the reporting period for which the allowance is applicable and is effective during the reporting period.
The rate must be redetermined at the beginning of each subsequent transportation allowance reporting
period that is determined under paragraph (b)(4) of this section.
(3) This paragraph explains how to allocate transportation costs to each product and transportation
system.
(i) The deduction for transportation costs must be determined based on your cost of transporting each
product through each individual transportation system. If you transport more than one product in a
gaseous phase, the allocation of costs to each of the products transported must be made in a consistent
and equitable manner. The allocation should be in the same proportion that the volume of each product
(excluding waste products that have no value) bears to the volume of all products in the gaseous phase
(excluding waste products that have no value). Except as provided in this paragraph, you may not take
an allowance for transporting a product that is not royalty bearing without ONRR approval.
(ii) As an alternative to the requirements of paragraph (b)(3)(i) of this section, you may propose to ONRR
a cost allocation method based on the values of the products transported. ONRR 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 ONRR 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 ONRR. You may use the transportation allowance determined in
accordance with your proposed allocation procedure until ONRR issues its determination on the
acceptability of the cost allocation. You are required to submit all relevant data to support your proposal.
ONRR will then determine the transportation allowance based upon your proposal and any additional
information ONRR 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 ONRR requests, you must submit all data used to
determine your transportation allowance. The data must be provided within a reasonable period of time
that ONRR will determine.
(2) You must report transportation allowances as a separate entry on Form MMS–2014. ONRR 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 §1218.54 of this chapter 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. ONRR allows these costs
only if such services are required for transportation and exceed the services necessary to place
production into marketable condition required under §1206.174(h).
(g) Determining nonallowable costs for transportation allowances. Lessees may not include the following
costs in determining the arm's-length transportation allowance under paragraph (a) of this section or the

non-arm's-length transportation allowance under paragraph (b) of this section:
(1) Fees or costs incurred for storage. This includes storing production in a storage facility, whether on
or off the lease, for more than 30 days.
(2) Aggregater/marketer fees. This includes fees you pay to another person (including your affiliates) to
market your gas, including purchasing and reselling the gas, or finding or maintaining a market for the
gas production.
(3) Penalties you incur as shipper. These penalties include, but are not limited to the following:
(i) Over-delivery cash-out penalties. This includes the difference between the price the pipeline pays you
for over-delivered volumes outside the tolerances and the price you receive for over-delivered volumes
within tolerances.
(ii) Scheduling penalties. This includes penalties you incur for differences between daily volumes
delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point.
(iii) Imbalance penalties. This includes penalties you incur (generally on a monthly basis) for differences
between volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or
delivery point.
(iv) Operational penalties. This includes fees you incur for violation of the pipeline's curtailment or
operational orders issued to protect the operational integrity of the pipeline.
(4) Intra-hub transfer fees. These are fees you pay to hub operators for administrative services (e.g., title
transfer tracking) necessary to account for the sale of gas within a hub.
(5) Other nonallowable costs. Any cost you incur for services you are required to provide at no cost to
the lessor.
(h) Other transportation cost determinations. You must follow the provisions of this section to determine
transportation costs when establishing value using either a net-back valuation procedure or any other
procedure that allows deduction of actual transportation costs.
[64 FR 43515, Aug. 10, 1999, as amended at 73 FR 15891, Mar. 26, 2008]

Processing Allowances
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§ 1206.179 What general requirements regarding processing allowances apply to me?
top
(a) When you value any gas plant product under §1206.174, 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 §1206.174. Before you calculate the 66 2/3
percent limit, you must first reduce the value for any transportation allowances related to postprocessing transportation authorized under §1206.177.
(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, ONRR 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 1206. 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 ONRR 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 §1218.54 of this chapter. Alternatively, you may be entitled to a credit, but you will not receive any
interest on your overpayment.

§ 1206.180 How do I determine an actual processing allowance?
top
(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 ONRR a copy of your
arm's-length contract(s) and all subsequent amendments to the contract(s) within 2 months of the date
ONRR receives your first report that deducts the allowance on the Form MMS–2014.
(ii) When ONRR 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 ONRR may require that the
processing allowance be determined under paragraph (b) of this section.
(iii) If ONRR 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 ONRR will require that the processing allowance be determined
under paragraph (b) of this section. In these circumstances, ONRR 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 ONRR. You may use your proposed allocation procedure until ONRR issues
its determination. You are required to submit all relevant data to support your proposal. ONRR will then
determine the processing allowance based upon your proposal and any additional information ONRR
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 ONRR 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. ONRR may approve a longer time
period. ONRR will monitor the allowance deduction to ensure that deductions are reasonable and
allowable. When necessary or appropriate, ONRR may require you to modify your processing
allowance.
(2) The processing allowance for non-arm's-length or no-contract situations is based upon your actual
costs for processing during the reporting period. Allowable costs include operating and maintenance
expenses, overhead, and either depreciation and a return on undepreciated capital investment (in
accordance with paragraph (b)(2)(iv)(A) of this section), or a cost equal to the initial depreciable
investment in the processing plant multiplied by a rate of return in accordance with paragraph (b)(2)(iv)
(B) of this section. Allowable capital costs are generally those costs for depreciable fixed assets
(including costs of delivery and installation of capital equipment) that are an integral part of the
processing plant.
(i) Allowable operating expenses include operations supervision and engineering, operations labor, fuel,
utilities, materials, ad valorem property taxes, rent, supplies, and any other directly allocable and
attributable operating expense that the lessee can document.
(ii) Allowable maintenance expenses include maintenance of the processing plant, maintenance of
equipment, maintenance labor, and other directly allocable and attributable maintenance expenses that
you can document.
(iii) Overhead directly attributable and allocable to the operation and maintenance of the processing
plant is an allowable expense. State and Federal income taxes and severance taxes, including royalties,
are not allowable expenses.
(iv) You may use either depreciation with a return on undepreciable capital investment or a return on
depreciable capital investment. After you elect to use either method for a processing plant, you may not
later elect to change to the other alternative without ONRR 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-ofproduction method. Once you make an election, you may not change methods without ONRR 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 ONRR 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 ONRR 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 ONRR requests, you must submit all data used to
determine your processing allowance. The data must be provided within a reasonable period of time, as
ONRR determines.
(2) You must report gas processing allowances as a separate entry on the Form MMS–2014. ONRR
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 §1218.54 of this chapter from the first day of the first month you
deducted a processing allowance until the date you pay the royalties due. If the processing allowance
you are entitled is greater than the amount you took on Form MMS–2014, you are entitled to a credit.
However, no interest will be paid on the overpayment.
(e) Other processing cost determinations. You must follow the provisions of this section to determine
processing costs when establishing value using either a net-back valuation procedure or any other
procedure that requires deduction of actual processing costs.
[64 FR 43515, Aug. 10, 1999, as amended at 73 FR 15891, Mar. 26, 2008]

§ 1206.181 How do I establish processing costs for dual accounting purposes when I
do not process the gas?
top
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 §1206.176, 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 ONRR (for tribal leases) or
ONRR (for allotted leases) with your supporting documentation submitted to ONRR. If ONRR does not
take action on your proposal within 120 days, the proposal will be deemed to be denied and subject to
appeal to the ONRR Director under 30 CFR part 1290.
(d) Processing costs based on the regulations in §§1206.179 and 1206.180.

Subpart F—Federal Coal
top

Source: 54 FR 1523, Jan. 13, 1989, unless otherwise noted.
§ 1206.250 Purpose and scope.
top
(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 Office of Natural Resources Revenue (ONRR) 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]

§ 1206.251 Definitions.
top
Ad valorem lease means a lease where the royalty due to the lessor is based upon a percentage of the
amount or value of the coal.
Allowance means a deduction used in determining value for royalty purposes. Coal washing allowance
means an allowance for the reasonable, actual costs incurred by the lessee for coal washing.
Transportation allowance means an allowance for the reasonable, actual costs incurred by the lessee for
moving coal to a point of sale or point of delivery remote from both the lease and mine or wash plant.
Area means a geographic region in which coal has similar quality and economic characteristics. Area
boundaries are not officially designated and the areas are not necessarily named.
Arm's-length contract means a contract or agreement that has been arrived at in the marketplace
between independent, nonaffiliated persons with opposing economic interests regarding that contract.
For purposes of this subpart, two persons are affiliated if one person controls, is controlled by, or is
under common control with another person. For purposes of this subpart, based on the instruments of
ownership of the voting securities of an entity, or based on other forms of ownership:
(a) Ownership in excess of 50 percent constitutes control;
(b) Ownership of 10 through 50 percent creates a presumption of control; and
(c) Ownership of less than 10 percent creates a presumption of noncontrol which ONRR 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 ONRR may require the lessee to certify ownership control.
To be considered arm's-length for any production month, a contract must meet the requirements of this
definition for that production month as well as when the contract was executed.
Audit means a review, conducted in accordance with generally accepted accounting and auditing
standards, of royalty payment compliance activities of lessees or other interest holders who pay
royalties, rents, or bonuses on Federal leases.
BLM means the Bureau of Land Management of the Department of the Interior.

Coal means coal of all ranks from lignite through anthracite.
Coal washing means any treatment to remove impurities from coal. Coal washing may include, but is not
limited to, operations such as flotation, air, water, or heavy media separation; drying; and related
handling (or combination thereof).
Contract means any oral or written agreement, including amendments or revisions thereto, between two
or more persons and enforceable by law that with due consideration creates an obligation.
Gross proceeds (for royalty payment purposes) means the total monies and other consideration
accruing to a coal lessee for the production and disposition of the coal produced. Gross proceeds
includes, but is not limited to, payments to the lessee for certain services such as crushing, sizing,
screening, storing, mixing, loading, treatment with substances including chemicals or oils, and other
preparation of the coal to the extent that the lessee is obligated to perform them at no cost to the Federal
Government. Gross proceeds, as applied to coal, also includes but is not limited to reimbursements for
royalties, taxes or fees, and other reimbursements. Tax reimbursements are part of the gross proceeds
accruing to a lessee even though the Federal royalty interest may be exempt from taxation. Monies and
other consideration, including the forms of consideration identified in this paragraph, to which a lessee is
contractually or legally entitled but which it does not seek to collect through reasonable efforts are also
part of gross proceeds.
Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or
approved by the United States for a Federal coal resource under a mineral leasing law that authorizes
exploration for, development or extraction of, or removal of coal—or the land covered by that
authorization, whichever is required by the context.
Lessee means any person to whom the United States issues a lease, and any person who has been
assigned an obligation to make royalty or other payments required by the lease. This includes any
person who has an interest in a lease as well as an operator or payor who has no interest in the lease
but who has assumed the royalty payment responsibility.
Like-quality coal means coal that has similar chemical and physical characteristics.
Marketable condition means coal that is sufficiently free from impurities and otherwise in a condition that
it will be accepted by a purchaser under a sales contract typical for that area.
Mine means an underground or surface excavation or series of excavations and the surface or
underground support facilities that contribute directly or indirectly to mining, production, preparation, and
handling of lease products.
Net-back method means a method for calculating market value of coal at the lease or mine. Under this
method, costs of transportation, washing, handling, etc., are deducted from the ultimate proceeds
received for the coal at the first point at which reasonable values for the coal may be determined by a
sale pursuant to an arm's-length contract or by comparison to other sales of coal, to ascertain value at
the mine.
Net output means the quantity of washed coal that a washing plant produces.
Netting is the deduction of an allowance from the sales value by reporting a one line net sales value,
instead of correctly reporting the deduction as a separate line item on the Form MMS–4430.
Person means by individual, firm, corporation, association, partnership, consortium, or joint venture.
Sales type code means the contract type or general disposition (e.g., arm's-length or non-arm's-length)
of production from the lease. The sales type code applies to the sales contract, or other disposition, and
not to the arm's-length or non-arm's-length nature of a transportation or washing allowance.
Spot market price means the price received under any sales transaction when planned or actual
deliveries span a short period of time, usually not exceeding one year.
[54 FR 1523, Jan. 13, 1989, as amended at 55 FR 35433, Aug. 30, 1990; 61 FR 5479, Feb. 12, 1996;

64 FR 43288, Aug. 10, 1999; 66 FR 45769, Aug. 30, 2001; 73 FR 15891, Mar. 26, 2008]

§ 1206.252 Information collection.
top
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 control numbers are identified in part 1210—Forms and Reports.
[73 FR 15891, Mar. 26, 2008]

§ 1206.253 Coal subject to royalties—general provisions.
top
(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]

§ 1206.254 Quality and quantity measurement standards for reporting and paying
royalties.
top
For all leases subject to this subpart, the quantity of coal on which royalty is due shall be measured in
short tons (of 2,000 pounds each) by methods prescribed by the BLM. Coal quantity information will be
reported on appropriate forms required under 30 CFR part 210—Forms and Reports.
[54 FR 1523, Jan. 13, 1989, as amended at 57 FR 52720, Nov. 5, 1992; 66 FR 45769, Aug. 30, 2001;
73 FR 15891, Mar. 26, 2008]

§ 1206.255 Point of royalty determination.
top
(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 ONRR .
(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. ONRR 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 §1206.256(d) of this subpart.
[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5480, Feb. 12, 1996]

§ 1206.256 Valuation standards for cents-per-ton leases.
top
(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 §1206.257 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]

§ 1206.257 Valuation standards for ad valorem leases.
top
(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 §§1206.258 through 1206.262 of
this subpart, or any allowance authorized by §1206.265 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, ONRR 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 ONRR 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 ONRR 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 ONRR 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 ONRR determines that the
value may be unreasonable, ONRR will notify the lessee and give the lessee an opportunity to provide
written information justifying the lessee's reported coal value.
(4) ONRR 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 ONRR'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'slength 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'slength 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 ONRR'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 ONRR 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 ONRR 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 ONRR 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 Director for Office of Natural Resources
Revenue of his/her designee. The letter shall identify the valuation method to be used and contain a
brief description of the procedure to be followed. The notification required by this section is a one-time
notification due no later than the month the lessee first reports royalties on the Form MMS–4430 using a
valuation method authorized by paragraphs (c)(2) (ii), (iii), (iv), or (v) of this section, and each time there
is a change in a method under paragraphs (c)(2) (iv) or (v) of this section.
(e) If ONRR 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 ONRR. The lessee shall also be liable for
interest computed pursuant to §1218.202 of this chapter. If the lessee is entitled to a credit, ONRR will
provide instructions for the taking of that credit.
(f) The lessee may request a value determination from ONRR. In that event, the lessee shall propose to
ONRR a value determination method, and may use that method in determining value for royalty
purposes until ONRR issues its decision. The lessee shall submit all available data relevant to its
proposal. The ONRR shall expeditiously determine the value based upon the lessee's proposal and any
additional information ONRR deems necessary. That determination shall remain effective for the period
stated therein. After ONRR 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 §§1206.258 through 1206.262 and §1206.265 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 ONRR 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 ONRR 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 ONRR to support valuation proposals, including transportation, coal
washing, or other allowances under §1206.265 of this subpart, is exempted from disclosure by the
Freedom of Information Act, 5 U.S.C. 522. Any data specified by the Act to be privileged, confidential, or
otherwise exempt shall be maintained in a confidential manner in accordance with applicable law and
regulations. All requests for information about determinations made under this part are to be submitted
in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR
part 2.
[54 FR 1523, Jan. 13, 1989, as amended at 55 FR 35433, Aug. 30, 1990; 57 FR 52720, Nov. 5, 1992;
61 FR 5480, Feb. 12, 1996; 66 FR 45769, Aug. 30, 2001]

§ 1206.258 Washing allowances—general.
top
(a) For ad valorem leases subject to §1206.257 of this subpart, ONRR 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 §1206.257 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 ONRR 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 §1218.202 of this chapter, 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]

§ 1206.259 Determination of washing allowances.
top
(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. ONRR' 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, ONRR 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 ONRR may require that
the washing allowance be determined in accordance with paragraph (b) of this section.
(3) If ONRR 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 ONRR shall require that the washing allowance be
determined in accordance with paragraph (b) of this section. When ONRR determines that the value of
the washing may be unreasonable, ONRR 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 dollarper-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'slength or no contract situation are subject to monitoring, review, audit, and possible future adjustment.
The lessee must claim a washing allowance by reporting it as a separate line entry on the Form MMS–
4430. When necessary or appropriate, ONRR 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 ONRR.
(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 ONRR 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) ONRR 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 ONRR of an
allowance based on incurred costs by using a separate line entry on the Form MMS–4430.
(ii) ONRR 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 ONRR.
(2) Non-arm's-length or no contract. (i) The lessee must notify ONRR of an allowance based on the
incurred costs by using a separate line entry on the Form MMS–4430.
(ii) For new washing facilities or arrangements, the lessee's initial washing deduction shall include
estimates of the allowable coal washing costs for the applicable period. Cost estimates shall be based
upon the most recently available operations data for the washing system or, if such data are not
available, the lessee shall use estimates based upon industry data for similar washing systems.
(iii) Upon request by ONRR, 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 ONRR.
(d) Interest and assessments. (1) If a lessee nets a washing allowance on the Form MMS–4430, then
the lessee shall be assessed an amount up to 10 percent of the allowance netted not to exceed $250
per lease sales type code per sales period.
(2) If a lessee erroneously reports a washing allowance which results in an underpayment of royalties,
interest shall be paid on the amount of that underpayment.
(3) Interest required to be paid by this section shall be determined in accordance with §1218.202 of this
chapter.

(e) Adjustments. (1) If the actual coal washing allowance is less than the amount the lessee has taken
on Form ONRR–4430 for each month during the allowance reporting period, the lessee shall pay
additional royalties due plus interest computed under §1218.202 of this chapter from the date when the
lessee took the deduction to the date the lessee repays the difference to ONRR. If the actual washing
allowance is greater than the amount the lessee has taken on Form ONRR–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 ONRR–4430 to reflect actual costs, together with any
payment, in accordance with instructions provided by ONRR.
(f) Other washing cost determinations. The provisions of this section shall apply to determine washing
costs when establishing value using a net-back valuation procedure or any other procedure that requires
deduction of washing costs.
[54 FR 1523, Jan. 13, 1989, as amended at 57 FR 52720, Nov. 5, 1992; 61 FR 5480, Feb. 12, 1996; 64
FR 43288, Aug. 10, 1999; 66 FR 45769, Aug. 30, 2001; 73 FR 15891, Mar. 26, 2008; 76 FR 38561, July
1, 2011]

§ 1206.260 Allocation of washed coal.
top
(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.

§ 1206.261 Transportation allowances—general.
top
(a) For ad valorem leases subject to §1206.257 of this subpart, where the value for royalty purposes has
been determined at a point remote from the lease or mine, ONRR shall, as authorized by this section,
allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to:
(1) Transport the coal from a Federal lease to a sales point which is remote from both the lease and
mine; or
(2) Transport the coal from a Federal lease to a wash plant when that plant is remote from both the
lease and mine and, if applicable, from the wash plant to a remote sales point. In-mine transportation
costs shall not be included in the transportation allowance.
(b) Under no circumstances will the authorized washing allowance and the transportation allowance
reduce the value for royalty purposes to zero.
(c)(1) When coal transported from a mine to a wash plant is eligible for a transportation allowance in
accordance with this section, the lessee is not required to allocate transportation costs between the
quantity of clean coal output and the rejected waste material. The transportation allowance shall be
authorized for the total production which is transported. Transportation allowances shall be expressed as
a cost per ton of cleaned coal transported.
(2) For coal that is not washed at a wash plant, the transportation allowance shall be authorized for the

total production which is transported. Transportation allowances shall be expressed as a cost per ton of
coal transported.
(3) Transportation costs shall only be recognized as allowances when the transported coal is sold and
royalties are reported and paid.
(d) If, after a review and/or audit, ONRR 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 §1218.202 of this chapter, 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]

§ 1206.262 Determination of transportation allowances.
top
(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, ONRR 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 ONRR may require
that the transportation allowance be determined in accordance with paragraph (b) of this section.
(3) If ONRR 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 ONRR shall require that the
transportation allowance be determined in accordance with paragraph (b) of this section. When ONRR
determines that the value of the transportation may be unreasonable, ONRR 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, ONRR 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 ONRR.
(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 ONRR 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) ONRR 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 ONRR for exception from the requirement that it compute actual costs in
accordance with paragraphs (b)(1) and (b)(2) of this section. ONRR 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). ONRR 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, ONRR
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 ONRR 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 ONRR of an
allowance based on incurred costs by using a separate line entry on the Form MMS–4430.
(ii) ONRR 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 ONRR.
(2) Non-arm's-length or no contract —(i) The lessee must notify ONRR of an allowance based on the
incurred costs by using a separate line entry on Form MMS–4430.
(ii) For new transportation facilities or arrangements, the lessee's initial deduction shall include estimates
of the allowable coal transportation costs for the applicable period. Cost estimates shall be based upon
the most recently available operations data for the transportation system or, if such data are not
available, the lessee shall use estimates based upon industry data for similar transportation systems.
(iii) Upon request by ONRR, 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 ONRR.
(iv) If the lessee is authorized to use its Federal- or State-agency-approved rate as its transportation cost
in accordance with paragraph (b)(3) of this section, it shall follow the reporting requirements of
paragraph (c)(1) of this section.
(d) Interest and assessments. (1) If a lessee nets a transportation allowance on Form MMS–4430, the
lessee shall be assessed an amount of up to 10 percent of the allowance netted not to exceed $250 per
lease sales type code per sales period.
(2) If a lessee erroneously reports a transportation allowance which results in an underpayment of
royalties, interest shall be paid on the amount of that underpayment.
(3) Interest required to be paid by this section shall be determined in accordance with §1218.202 of this
chapter.
(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 §1218.202 of this chapter from the date when the
lessee took the deduction to the date the lessee repays the difference to ONRR. 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 ONRR.
(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; 73 FR 15891,
Mar. 26, 2008]

§ 1206.263 [Reserved]
top

§ 1206.264 In-situ and surface gasification and liquefaction operations.
top
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 ONRR. The ONRR will
review the lessee's proposal and issue a value determination. The lessee may use its proposed value
until ONRR issues a value determination.
[54 FR 1523, Jan. 13, 1989, as amended at 65 FR 43289, Aug. 10, 1999]

§ 1206.265 Value enhancement of marketable coal.
top
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 §1206.257(h) of this subpart, the lessee shall notify
ONRR 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
§1206.257(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 §1206.257(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
ONRR-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 §1206.259(b)(2)(v) of this subpart.

Subpart G—Other Solid Minerals
top

§ 1206.301 Value basis for royalty computation.
top
(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
top

Source: 72 FR 24459, May 2, 2007, unless otherwise noted.
§ 1206.350 What is the purpose of this subpart?
top
(a) This subpart applies to all geothermal resources produced from Federal geothermal leases issued
pursuant to the Geothermal Steam Act of 1970 (GSA), as amended by the Energy Policy Act of 2005
(EPAct) (30 U.S.C. 1001 et seq. ). The purpose of this subpart is to prescribe how to calculate royalties
and direct use fees for geothermal production.
(b) The ONRR may audit and adjust all royalty and fee payments.

(c) In some cases, the regulations in this subpart may be inconsistent with a statute, settlement
agreement, written agreement, or lease provision. If this happens, the statute, settlement agreement,
written agreement, or lease provision will govern to the extent of the inconsistency. For purposes of this
paragraph, the following definitions apply:
(1) “Settlement agreement” means a settlement agreement between the United States and a lessee
resulting from administrative or judicial litigation.
(2) “Written agreement” means a written agreement between the lessee and the ONRR Director or
Assistant Secretary, Policy, Management and Budget of the Department of the Interior that:
(i) Establishes a method to determine the royalty from any lease that ONRR expects at least would
approximate the value or royalty established under this subpart; and
(ii) Includes a value or gross proceeds determination under §1206.364 of this subpart.

§ 1206.351 What definitions apply to this subpart?
top
For purposes of this subpart, the following terms have the meanings indicated.
Affiliate means a person who controls, is controlled by, or is under common control with another person.
For purposes of this subpart:
(1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of
ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10
percent constitutes a presumption of noncontrol that ONRR may rebut.
(2) If there is ownership or common ownership of 10 through 50 percent of the voting securities, or
instruments of ownership, or other forms of ownership of another person, ONRR will consider the
following factors in determining whether there is control under the circumstances of a particular case:
(i) The extent to which there are common officers or directors;
(ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership: the
percentage of ownership or common ownership, the relative percentage of ownership or common
ownership compared to the percentage(s) of ownership by other persons, whether a person is the
greatest single owner, or whether there is an opposing voting bloc of greater ownership;
(iii) Operation of a lease, plant, pipeline, or other facility;
(iv) The extent of participation by other owners in operations and day-to-day management of a lease,
plant, pipeline, or other facility; and
(v) Other evidence of power to exercise control over or common control with another person.
(3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or
marriage, are affiliates.
Allowance means a deduction in determining value for royalty purposes.
Arm's-length contract means a contract or agreement between independent persons who are not
affiliates and who have opposing economic interests regarding that contract. To be considered arm's
length for any production month, a contract must satisfy this definition for that month, as well as when
the contract was executed.
Audit means a review, conducted in accordance with generally accepted accounting and auditing
standards, of royalty or fee payment compliance activities of lessees or other interest holders who pay

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

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

Public purpose means a program carried out by a State, tribal, or local government for the purpose of
providing facilities or services for the benefit of the public in connection with, but not limited to, public
health, safety or welfare, other than the commercial generation of electricity. Use of lands or facilities for
habitation, cultivation, trade or manufacturing is permissible only when necessary for and integral to ( i.e.
, an essential part of) the public purpose.
Public safety or welfare means a program carried out or promoted by a public agency for public
purposes involving, directly or indirectly, protection, safety, and law enforcement activities, and the
criminal justice system of a given political area. Public safety or welfare may include, but is not limited to,
programs carried out by:
(1) Public police departments;
(2) Sheriffs' offices;
(3) The courts;
(4) Penal and correctional institutions (including juvenile facilities);
(5) State and local civil defense organizations; and
(6) Fire departments and rescue squads (including volunteer fire departments and rescue squads
supported in whole or in part with public funds).
Reasonable alternative fuel means a conventional fuel (such as coal, oil, gas, or wood) that would
normally be used as a source of heat in direct use operations.
Secretary means the Secretary of the Interior or any person duly authorized to exercise the powers
vested in that office.
Transmission deduction means a deduction for the lessee's reasonable actual costs incurred to wheel or
transmit the electricity from the lessee's power plant to the purchaser's delivery point.
Wheeling means the transmission of electricity from a power plant to the point of delivery.

§ 1206.352 How do I calculate the royalty due on geothermal resources used for
commercial production or generation of electricity?
top
(a) If you sold geothermal resources produced from a Class I, II, or III lease at arm's length that the
purchaser uses to generate electricity, then the royalty on the geothermal resources is the gross
proceeds accruing to you from the sale of the geothermal resource to the arm's-length purchaser
multiplied by either:
(1) The royalty rate in your lease; or
(2) The royalty rate that BLM prescribes or calculates under 43 CFR 3211.17. See §1206.361 for
additional provisions applicable to determining gross proceeds under arm's-length sales.
(b) If you use the geothermal resource in your own power plant for the generation and sale of electricity,
the following provisions apply
(1) For Class I leases, you must determine the royalty on produced geothermal resources in accordance
with the first applicable of the following paragraphs:
(i) The gross proceeds accruing to you from the arm's-length sale of the electricity less applicable
deductions determined under §1206.353 and §1206.354 of this part, multiplied by the royalty rate in your
lease. See §1206.361 for additional provisions applicable to determining gross proceeds under arm's-

length sales. Under no circumstances may the deductions reduce the royalty value of the geothermal
resource to zero; or
(ii) A royalty determined by any other reasonable method approved by ONRR under §1206.364 of this
subpart.
(2) For Class II and Class III leases, the royalty on geothermal resources produced is your gross
proceeds from the sale of electricity multiplied by the royalty rate BLM prescribed for your lease under
43 CFR 3211.17. See §1206.361 for additional provisions applicable to determining gross proceeds
under arm's-length sales. You may not reduce gross proceeds by any deductions.

§ 1206.353 How do I determine transmission deductions?
top
(a) If you determine the value of your geothermal resources under §1206.352(b)(1)(i) of this subpart, you
may subtract a transmission deduction from the gross proceeds you received for the sale of electricity to
determine the plant tailgate value of the electricity.
(1) The transmission deduction consists of either or both of two components:
(i) Transmission line costs as determined under paragraph (b) of this section; and
(ii) Wheeling costs if the electricity is transmitted across a third party's transmission line under an arm'slength wheeling agreement.
(2) You may deduct the actual costs you (including your affiliate(s)) incur for transmitting electricity under
your arm's-length wheeling contract.
(b) To determine your transmission line cost, you must follow the requirements of paragraphs (b)(1) and
(b)(2) of this section.
(1) Your transmission line costs are your actual costs associated with the construction and operation of a
transmission line for the purpose of transmitting electricity attributable and allocable to your power plant
utilizing Federal geothermal resources.
(i) You must determine the monthly transmission line cost component of the transmission deduction by
multiplying the annual transmission line cost rate (in dollars per kilowatt-hour) by the amount of
electricity delivered for the reporting month.
(ii) You must redetermine the transmission line cost rate annually either at the beginning of the same
month of the year in which the power plant was placed into service or at a time concurrent with the
beginning of your annual corporate accounting period. The period you select must coincide with the
same period you chose for the generating deduction under §1206.354(b)(1). After you choose a
deduction period, you may not later elect to use a different deduction period without ONRR approval.
(2) Your actual transmission line costs during the reporting period include:
(i) Operating and maintenance expenses under paragraphs (d) and (e) of this section;
(ii) Overhead under paragraph (f) of this section; and either
(iii) Depreciation under paragraphs (g) and (h) of this section and a return on undepreciated capital
investment under paragraphs (g) and (i) of this section or
(iv) A return on the capital investment in the transmission line under paragraphs (g) and (j) of this
section.
(c)(1) Allowable capital costs under paragraph (b) of this section are generally those for depreciable

fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of
the transmission line.
(2)(i) You may include a return on capital you invested in the purchase of real estate for transmission
facilities if:
(A) Such purchase is necessary; and
(B) The surface is not part of the Federal lease.
(ii) The rate of return will be the same rate determined under paragraph (k) of this section.
(d) Allowable operating expenses include:
(1) Operations supervision and engineering;
(2) Operations labor;
(3) Fuel;
(4) Utilities;
(5) Materials;
(6) Ad valorem property taxes;
(7) Rent;
(8) Supplies; and
(9) Any other directly allocable and attributable operating or maintenance expense that you can
document.
(e) Allowable maintenance expenses include:
(1) Maintenance of the transmission line;
(2) Maintenance of equipment;
(3) Maintenance labor; and
(4) Other directly allocable and attributable maintenance expenses that you can document.
(f) Overhead directly attributable and allocable to the operation and maintenance of the transmission line
is an allowable expense. State and Federal income taxes and severance taxes and other fees, including
royalties, are not allowable expenses.
(g) To compute costs associated with capital investment, a lessee may use either depreciation with a
return on undepreciated capital investment, or a return on capital investment in the transmission line.
After a lessee has elected to use either method, the lessee may not later elect to change to the other
alternative without ONRR approval.
(h)(1) To compute depreciation, you must use a straight-line depreciation method based on the life of the
geothermal project, usually the term of the electricity sales contract, or other depreciation period
acceptable to ONRR. You may not depreciate equipment below a reasonable salvage value.
(2) A change in ownership of a transmission line does not alter the depreciation schedule established by
the original lessee-owner for purposes of computing transmission line costs.

(3) With or without a change in ownership, you may depreciate a transmission line only once.
(i) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated
capital balance as of the beginning of the period for which you are calculating the transmission
deduction by the rate of return provided in paragraph (k) of this section.
(j) To compute a return on capital investment in the transmission line, multiply the allowable capital
investment in the transmission line by the rate of return determined pursuant to paragraph (k) of this
section. There is no allowance for depreciation.
(k) The rate of return must be 2.0 multiplied by the industrial rate associated with Standard & Poor's BBB
rating. The BBB rate must be the monthly average rate as published in Standard & Poor's Bond Guide
for the first month for which the allowance is applicable. Redetermine the rate at the beginning of each
subsequent calendar year.
(l) Calculate the deduction for transmission costs based on your cost of transmitting electricity through
each individual transmission line.
(m)(1) For new transmission facilities or arrangements, base your initial deduction on estimates of
allowable electricity transmission costs for the applicable period. Use the most recently available
operations data for the transmission line or, if such data are not available, use estimates based on data
for similar transmission lines.
(2) When actual cost information is available, you must amend your prior Form MMS–2014 reports to
reflect actual transmission costs deductions for each month for which you reported and paid based on
estimated transmission costs. You must pay any additional royalties due (together with interest
computed under §1218.302 of this chapter). You are entitled to a credit for or refund of any overpaid
royalties.
(n) In conducting reviews and audits, ONRR may require you to submit arm's-length transmission
contracts, production agreements, operating agreements, and related documents and all other data
used to calculate the deduction. You must comply with any such requirements within the time ONRR
specifies. Recordkeeping requirements are found at part 1212 of this chapter.
(o) At the completion of transmission line dismantlement and salvage operations, you may report a credit
for or request a refund of royalties in an amount equal to the royalty rate times the amount by which
actual transmission line dismantlement costs exceed actual income attributable to salvage of the
transmission line.

§ 1206.354 How do I determine generating deductions?
top
(a) If you determine the value of your geothermal resources under §1206.352(b)(1)(i) of this subpart, you
may deduct your reasonable actual costs incurred to generate electricity from the plant tailgate value of
the electricity (usually the transmission-reduced value of the delivered electricity). You may deduct the
actual costs you incur for generating electricity under your arm's-length power plant contract.
(b)(1) You must base your generating costs deduction on your actual annual costs associated with the
construction and operation of a geothermal power plant.
(i) You must determine your monthly generating deduction by multiplying the annual generating cost rate
(in dollars per kilowatt-hour) by the amount of plant tailgate electricity measured (or computed) for the
reporting month. The generating cost rate is determined from the annual amount of your plant tailgate
electricity.
(ii) You must redetermine your generating cost rate annually either at the beginning of the same month
of the year in which the power plant was placed into service or at a time concurrent with the beginning of
your annual corporate accounting period. The period you select must coincide with the same period
chosen for the transmission deduction under §1206.353(b)(1). After you choose a deduction period, you
may not later elect to use a different deduction period without ONRR approval.

(2) Your generating costs are your actual power plant costs during the reporting period, including:
(i) Operating and maintenance expenses under paragraphs (d) and (e) of this section;
(ii) Overhead under paragraph (f) of this section; and either
(iii) Depreciation under paragraphs (g) and (h) of this section and a return on undepreciated capital
investment under paragraphs (g) and (i) of this section; or
(iv) A return on capital investment in the power plant under paragraphs (g) and (j) of this section.
(c)(1) Allowable capital costs under paragraph (b) of this section are generally those for depreciable
fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of
the power plant or are required by the design specifications of the power conversion cycle.
(2)(i) You may include a return on capital you invested in the purchase of real estate for a power plant
site if:
(A) The purchase is necessary; and,
(B) The surface is not part of the Federal lease.
(ii) The rate of return will be the same rate determined under paragraph (k) of this section.
(3) You may not deduct the costs of gathering systems and other production-related facilities.
(d) Allowable operating expenses include:
(1) Operations supervision and engineering;
(2) Operations labor;
(3) Auxiliary fuel and/or utilities used to operate the power plant during down time;
(4) Utilities;
(5) Materials;
(6) Ad valorem property taxes;
(7) Rent;
(8) Supplies; and
(9) Any other directly allocable and attributable operating expense.
(e) Allowable maintenance expenses include:
(1) Maintenance of the power plant;
(2) Maintenance of equipment;
(3) Maintenance labor; and
(4) Other directly allocable and attributable maintenance expenses that you can document.
(f) Overhead directly attributable and allocable to the operation and maintenance of the power plant is

an allowable expense. State and Federal income taxes and severance taxes and other fees, including
royalties, are not allowable expenses.
(g) To compute costs associated with capital investment, a lessee may use either depreciation with a
return on undepreciated capital investment, or a return on capital investment in the power plant. After a
lessee has elected to use either method, the lessee may not later elect to change to the other alternative
without ONRR approval.
(h)(1) To compute depreciation, you must use a straight-line depreciation method based on the life of the
geothermal project, usually the term of the electricity sales contract, or other depreciation period
acceptable to ONRR. You may not depreciate equipment below a reasonable salvage value.
(2) A change in ownership of the power plant does not alter the depreciation schedule established by the
original lessee-owner for purposes of computing generating costs.
(3) With or without a change in ownership, you may depreciate a power plant only once.
(i) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated
capital balance as of the beginning of the period for which you are calculating the generating deduction
allowance by the rate of return provided in paragraph (k) of this section.
(j) To compute a return on capital investment in the power plant, multiply the allowable capital
investment in the power plant by the rate of return determined pursuant to paragraph (k) of this section.
There is no allowance for depreciation.
(k) The rate of return must be 2.0 multiplied by the industrial rate associated with Standard & Poor's BBB
rating. The BBB rate must be the monthly average rate as published in Standard & Poor's Bond Guide
for the first month for which the allowance is applicable. You must redetermine the rate at the beginning
of each subsequent calendar year.
(l) Calculate the deduction for generating costs based on your cost of generating electricity through each
individual power plant.
(m)(1) For new power plants or arrangements, base your initial deduction on estimates of allowable
electricity generation costs for the applicable period. Use the most recently available operations data for
the power plant or, if such data are not available, use estimates based on data for similar power plants.
(2) When actual cost information is available, you must amend your prior Form MMS–2014 reports to
reflect actual generating cost deductions for each month for which you reported and paid based on
estimated generating costs. You must pay any additional royalties due (together with interest computed
under §1218.302 of this chapter). You are entitled to a credit for or refund of any overpaid royalties.
(n) In conducting reviews and audits, ONRR may require you to submit arm's-length power plant
contracts, production agreements, operating agreements, related documents and all other data used to
calculate the deduction. You must comply with any such requirements within the time ONRR specifies.
Recordkeeping requirements are found at part 1212 of this chapter.
(o) At the completion of power plant dismantlement and salvage operations, you may report a credit for
or request a refund of royalty in an amount equal to the royalty rate times the amount by which actual
power plant dismantlement costs exceed actual income attributable to salvage of the power plant.

§ 1206.355 How do I calculate royalty due on geothermal resources I sell at arm's
length to a purchaser for direct use?
top
If you sell geothermal resources produced from Class I, II, or III leases at arm's length to a purchaser for
direct use, then the royalty on the geothermal resource is the gross proceeds accruing to you from the
sale of the geothermal resource to the arm's-length purchaser multiplied by the royalty rate in your lease
or that BLM prescribes under 43 CFR 3211.18. See §1206.361 for additional provisions applicable to

determining gross proceeds under arm's-length sales.

§ 1206.356 How do I calculate royalty or fees due on geothermal resources I use for
direct use purposes?
top
If you use the geothermal resource for direct use:
(a) For Class I leases, you must determine the royalty due on geothermal resources in accordance with
the first applicable of the following three paragraphs.
(1) The weighted average of the gross proceeds established in arm's-length contracts for the purchase
of significant quantities of geothermal resources to operate the lessee's same direct-use facility
multiplied by the royalty rate in your lease. In evaluating the acceptability of arm's-length contracts, the
following factors will be considered: time of execution, duration, terms, volume, quality of resource, and
such other factors as may be appropriate to reflect the value of the resource.
(2) The equivalent value of the least expensive, reasonable alternative energy source (fuel) multiplied by
the royalty rate in your lease. The equivalent value of the least expensive, reasonable alternative energy
source will be based on the amount of thermal energy that would otherwise be used by the direct use
facility in place of the geothermal resource. That amount of thermal energy (in Btu) displaced by the
geothermal resource will be determined by the equation:

Where hinis the enthalpy in Btu/lb at the direct use facility inlet (based on measured inlet temperature),
houtis the enthalpy in Btu/lb at the facility outlet (based on measured outlet temperature), density is in
lbs/cu ft based on inlet temperature, the factor 0.133681 (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 factor of the alternative energy source will be 0.7 for coal and 0.8 for oil,
natural gas, and other fuels derived from oil and natural gas, or an efficiency factor proposed by the
lessee and approved by ONRR. The methods of measuring resource parameters (temperature, volume,
etc.) and the frequency of computing and accumulating the amount of thermal energy displaced will be
determined and approved by BLM under 43 CFR 3275.13–3275.17.
(3) A royalty determined by any other reasonable method approved by ONRR or the Assistant
Secretary, Policy, Management and Budget of the Department of the Interior, under §1206.364 of this
part.
(b) For geothermal resources produced from Class II and Class III leases, you must multiply the
appropriate fee from the schedule in subparagraph (b)(1) of this section by the number of gallons or
pounds you produce from the direct use lease each month.
(1) You must use the following fee schedule to calculate fees due under this section:
Direct Use Fee Schedule
[Hot water]

If your average monthly inlet
temperature ( °F) is
At least . . .
130

But less than . . .
140

Your fees are . . .
($/million
($/million
gallons)
pounds)
2.524
0.307

140
150
160
170
180
190
200
210
220
230
240
250
260
270
280
290
300
310
320
330
340
350

150
160
170
180
190
200
210
220
230
240
250
260
270
280
290
300
310
320
330
340
350
360

7.549
12.543
17.503
22.426
27.310
32.153
36.955
41.710
46.417
51.075
55.682
60.236
64.736
69.176
73.558
77.876
82.133
86.328
90.445
94.501
98.481
102.387

0.921
1.536
2.150
2.764
3.379
3.993
4.607
5.221
5.836
6.450
7.064
7.679
8.293
8.907
9.521
10.136
10.750
11.364
11.979
12.593
13.207
13.821

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

Where:
RV= Royalty due as a function of produced volume in the fee schedule, expressed as dollars
per million (106 ) gallons;
Rm= Royalty due as a function of produced mass in the fee schedule, expressed as dollars
per million (106 ) pounds;
ρ[rho] = Water density at inlet temperature expressed as lbs per gallon;

Tin= Measured inlet temperature in °F (as required by BLM under 43 CFR part 3275);
Tout= Established assumed outlet temperature of 130°F;
e = Boiler Efficiency Factor for coal of 70 percent;
Pprbc= The 3-year historical average of Powder River Basin spot coal prices, as published by
the Energy Information Administration, or other recognized authoritative reference source of
coal prices, in dollars (per MMBtu);
Frr= The assumed Lease Royalty Rate of 10 percent.
(2) The fee that you report is subject to monitoring, review, and audit.
(3) The schedule of fees established under this paragraph will apply to any Class III lease with respect to
any royalty payments previously made when the lease was a Class I lease that were due and owing,
and were paid, on or after July 16, 2003. To use this provision, you must provide ONRR data showing
the amount of geothermal production in pounds or gallons of geothermal fluid to input into the fee
schedule (see 43 CFR part 3276).
(i) If the royalties you previously paid are less than the fees due under this section, you must pay the
difference plus interest on that difference computed under §1218.302 of this chapter.
(ii) If the royalties you previously paid are more than the fees due under this section, then you are
entitled to a refund or credit from ONRR of 50 percent of the overpaid royalties. You are also entitled to
a refund or credit of any interest that you paid on the overpaid royalties.
(c) For geothermal resources other than hot water, ONRR will determine fees on a case-by-case basis.
[48 FR 35641, Aug. 5, 1983, 76 FR 76615, Dec. 8, 2011]

§ 1206.357 How do I calculate royalty due on byproducts?
top
(a) If you sell byproducts, you must determine the royalty due on the byproducts that are royalty-bearing
under:
(1) Applicable lease terms of Class I leases and of Class III leases that do not elect to be subject to all of
the BLM regulations promulgated for leases issued after August 8, 2005, under 43 CFR 3200.7(a)(2), or
(2) Applicable statutory provisions at 30 U.S.C. 1004(a)(2) for Class II leases and for Class III leases
that do elect to be subject to all of the BLM regulations promulgated for leases issued after August 8,
2005, under 43 CFR 3200.7(a)(2).
(b) You must determine the royalty due on the byproducts by multiplying the royalty rate in your lease or
that BLM prescribes under 43 CFR 3211.19 by a value of the byproducts determined in accordance with
the first applicable of the following subparagraphs:
(1) The gross proceeds accruing to you from the arm's-length sale of the byproducts, less any applicable
byproduct transportation allowances determined under §§1206.358 and 1206.359. See §1206.361 for
additional provisions applicable to determining gross proceeds;
(2) Other relevant matters including, but not limited to, published or publicly available spot-market prices,
or information submitted by the lessee concerning circumstances unique to a particular lease operation
or the saleability of certain byproducts; or

(3) Any other reasonable valuation method approved by ONRR.

§ 1206.358 What are byproduct transportation allowances?
top
(a) When you determine the value of byproducts at a point off the geothermal lease, unit, or participating
area, you are allowed a deduction in determining value, for royalty purposes, for your reasonable, actual
costs incurred to:
(1) Transport the byproducts from a Federal lease, unit, or participating area to a sales point or point of
delivery that is off the lease, unit, or participating area; or
(2) Transport the byproducts from a Federal lease, unit, or participating area, or from a geothermal use
facility to a byproduct recovery facility when that byproduct recovery facility is off the lease, unit, or
participating area and, if applicable, from the recovery facility to a sales point or point of delivery off the
lease, unit, or participating area.
(b) Costs for transporting geothermal fluids from the lease to the geothermal use facility, whether on or
off the lease, are not includible in the byproduct transportation allowance.
(c)(1) When you transport byproducts from a lease, unit, participating area, or geothermal use facility to
a byproduct recovery facility, you are not required to allocate transportation costs between the quantity
of marketable byproducts and the rejected waste material. The byproduct transportation allowance is
authorized for the total production that is transported. You must express byproduct transportation
allowances as a cost per unit of marketable byproducts transported.
(2) For byproducts that are extracted on the lease, unit, participating area, or at the geothermal use
facility, the byproduct transportation allowance is authorized for the total byproduct that is transported to
a point of sale off the lease, unit, or participating area. You must express byproduct transportation
allowances as a cost per unit of byproduct transported.
(3) You may deduct transportation costs only when you sell, deliver, or otherwise utilize the transported
byproduct and report and pay royalties on the byproduct.
(d) Reporting requirements. (1) You must use a discrete field on Form MMS–2014 to notify ONRR of a
transportation allowance.
(2) In conducting reviews and audits, ONRR may require you to submit arm's-length transportation
contracts, production agreements, operating agreements, and related documents. You must comply with
any such requirements within the time ONRR specifies. Recordkeeping requirements are found at part
1212 of this chapter.
(e) Byproduct transportation allowances are subject to monitoring, review, and audit. If, after a review or
audit, ONRR determines that you have improperly determined a byproduct transportation allowance, you
must pay any additional royalties due (plus interest computed under §1218.302 of this chapter). You are
entitled to a credit for or refund of any overpaid royalties.
(f) If you commingled byproducts produced from Federal and non-Federal leases for transportation, you
may not disproportionately allocate transportation costs to Federal lease production.

§ 1206.359 How do I determine byproduct transportation allowances?
top
(a) For transportation costs you incur under an arm's-length contract, the transportation allowance will
be the reasonable, actual costs you incurred for transporting the byproducts under that contract.
(1) In conducting reviews and audits, ONRR will examine whether the contract reflects more than the

consideration actually transferred either directly or indirectly from you to the transporter for the
transportation. If the contract reflects more than the total consideration you paid, ONRR may require you
to determine the byproduct transportation allowance under paragraph (b) of this section.
(2) If ONRR determines that the consideration you paid under an arm's-length byproduct transportation
contract does not reflect the reasonable value of the transportation because of misconduct by or
between the contracting parties, or because you otherwise have breached your duty to the lessor to
market the production for the mutual benefit of the lessee and the lessor, ONRR will require you to
determine the byproduct transportation allowance under paragraph (b) of this section. When ONRR
determines that the value of the transportation may be unreasonable, ONRR will notify you and give you
an opportunity to provide written information justifying your transportation costs.
(3) Where your payments for transportation under an arm's-length contract are not established on a
dollars-per-unit basis, you must convert whatever consideration you paid to a dollar value equivalent for
the purposes of this section.
(b) If you transport the byproduct yourself or under a non-arm's-length transportation arrangement, the
byproduct transportation allowance is your reasonable actual costs for transportation during the
reporting period, including:
(1) Operating and maintenance expenses under paragraphs (d) and (e) of this section;
(2) Overhead under paragraph (f) of this section; and either
(3) Depreciation under paragraphs (g) and (h) of this section and a return on undepreciated capital
investment under paragraphs (g) and (i) of this section; or
(4) A return on capital investment in the transportation system under paragraphs (g) and (j) of this
section.
(c)(1) Allowable capital costs under paragraph (b) of this section are generally those for depreciable
fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of
the transportation system.
(2)(i) You may include a return on capital you invested in the purchase of real estate to locate the
byproduct transportation facilities if:
(A) The purchase is necessary; and
(B) The surface is not part of a Federal lease.
(ii) The rate of return will be the same rate determined in paragraph (k) of this section.
(3) You may not deduct the costs of gathering systems and other production-related facilities.
(d) Allowable operating expenses include:
(1) Operations supervision and engineering;
(2) Operations labor;
(3) Fuel;
(4) Utilities;
(5) Materials;
(6) Ad valorem property taxes;

(7) Rent;
(8) Supplies; and
(9) Any other directly allocable and attributable operating expense that you can document.
(e) Allowable maintenance expenses include:
(1) Maintenance of the transportation system;
(2) Maintenance of equipment;
(3) Maintenance labor; and
(4) Other directly allocable and attributable maintenance expenses that you can document.
(f) Overhead directly attributable and allocable to the operation and maintenance of the transportation
system is an allowable expense. State and Federal income taxes and severance taxes and other fees,
including royalties, are not allowable expenses.
(g) To compute costs associated with capital investment, a lessee may use either paragraphs (h) and (i)
or paragraph (j) of this section. After a lessee has elected to use either method for a transportation
system, the lessee may not later elect to change to the other alternative without ONRR approval.
(h)(1) To compute depreciation, you must use a straight-line depreciation method based on either the life
of the equipment or the life of the geothermal project which the transportation system services. After you
choose the basis for depreciation, you may not change that basis without ONRR approval. You may not
depreciate equipment below a reasonable salvage value.
(2) A change in ownership of a transportation system does not alter the depreciation schedule
established by the original lessee-owner for purposes of computing transportation costs.
(3) With or without a change in ownership, you may depreciate a transportation system only once.
(i) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated
capital balance as of the beginning of the period for which you are calculating the transportation
allowance by the rate of return provided in paragraph (k) of this section.
(j) To compute a return on capital investment in the transportation system, the allowed cost will be the
amount equal to the allowable capital investment in the transportation system multiplied by the rate of
return determined pursuant to paragraph (k) of this section. There is no allowance for depreciation.
(k) The rate of return must be the industrial rate associated with Standard & Poor's BBB rating. The BBB
rate must be the monthly average rate as published in Standard & Poor's Bond Guide for the first month
for which the allowance is applicable. You must redetermine the rate at the beginning of each
subsequent calendar year.
(l)(1) For new transportation facilities or arrangements, base your initial deduction on estimates of
allowable byproduct transportation costs for the applicable period. Use the most recently available
operations data for the transportation system or, if such data are not available, use estimates based on
data for similar transportation systems.
(2) When actual cost information is available, you must amend your prior Form MMS–2014 reports to
reflect actual byproduct transportation cost deductions for each month for which you reported and paid
based on estimated byproduct transportation costs. You must pay any additional royalties due (together
with interest computed under §1218.302 of this chapter). You are entitled to a credit for or a refund of
any overpaid royalties.

§ 1206.360 What records must I keep to support my calculations of royalty or fees
under this subpart?

top
If you determine royalties or direct use fees for your geothermal resource under this subpart, you must
retain all data relevant to the determination of the royalty value or the fee you paid. Recordkeeping
requirements are found at part 1212 of this chapter.
(a) You must be able to show:
(1) How you calculated the royalty value or fee you reported, including all allowable deductions; and
(2) How you complied with this subpart.
(b) Upon request, you must submit all data to ONRR. You must comply with any such requirement within
the time ONRR specifies.

§ 1206.361 How will ONRR determine whether my royalty or direct use fee payments
are correct?
top
(a)(1) The royalties or direct use fees that you report are subject to monitoring, review, and audit. The
ONRR may review and audit your data, and ONRR will direct you to use a different measure of royalty
value, gross proceeds, or fee, whichever is applicable, if it determines that the reported value, gross
proceeds, or fee is inconsistent with the requirements of this subpart.
(2) If ONRR directs you to use a different royalty value, measure of gross proceeds, or fee, you must
either pay any royalties or fees due (together with interest computed under §1218.302 of this chapter) or
report a credit for or request a refund of any overpaid royalties or fees.
(b) When the provisions in this subpart refer to gross proceeds either for the sale of electricity or the sale
of a geothermal resource, in conducting reviews and audits ONRR will examine whether your sales
contract reflects the total consideration actually transferred, either directly or indirectly, from the buyer to
you for the geothermal resource or electricity. If ONRR determines that a contract does not reflect the
total consideration, or the gross proceeds accruing to you under a contract do not reflect reasonable
consideration because of misconduct by or between the contracting parties, or because you otherwise
have breached your duty to the lessor to market the production for the mutual benefit of the lessee and
the lessor, ONRR may require you to increase the gross proceeds to reflect any additional
consideration. Alternatively, for Class I leases, ONRR may require you to use another valuation method
in the regulations applicable to dispositions other than under an arm's-length contract. ONRR will notify
you to give you an opportunity to provide written information justifying your gross proceeds.
(c) For arm's-length sales, you have the burden of demonstrating that your contract is arm's length.
(d) ONRR may require you to certify that the provisions in your sales contract include all of the
consideration the buyer paid you, either directly or indirectly, for the electricity or geothermal resource.
(e) Notwithstanding any other provision of this subpart, under no circumstances will the value of
production for royalty purposes under a Class I lease where the geothermal resources are sold before
use be less than the gross proceeds accruing to you.
(f) Gross proceeds for the sale of electricity or for the sale of the geothermal resource will be based on
the highest price a prudent lessee can receive through legally enforceable claims under its contract.
(1) Absent contract revision or amendment, if you fail to take proper or timely action to receive prices or
benefits to which you are entitled, you must pay royalty based upon that obtainable price or benefit.
(2) Contract revisions or amendments you make must be in writing and signed by all parties to the
contract.

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

§ 1206.362 What are my responsibilities to place production into marketable condition
and to market production?
top
You must place geothermal resources and byproducts in marketable condition and market the
geothermal resources or byproducts for the mutual benefit of the lessee and the lessor at no cost to the
Federal Government. If you use gross proceeds under an arm's-length contract in determining royalty,
you must increase those gross proceeds to the extent that the purchaser, or any other person, provides
certain services that the seller normally would be responsible to perform to place the geothermal
resources or byproducts in marketable condition or to market the geothermal resources or byproducts.

§ 1206.363 When is an ONRR audit, review, reconciliation, monitoring, or other like
process considered final?
top
Notwithstanding any provision in these regulations to the contrary, no audit, review, reconciliation,
monitoring, or other like process that results in a redetermination by ONRR of royalty or fees due under
this subpart is considered final or binding as against the Federal Government or its beneficiaries until
ONRR formally closes the audit period in writing.

§ 1206.364 How do I request a value or gross proceeds determination?
top
(a) You may request a value determination from ONRR regarding any geothermal resources produced
from a Class I lease or for byproducts produced from a Class I, Class II, or Class III lease. You may also
request a gross proceeds determination for a Class II or Class III lease. Your request must:
(1) Be in writing;
(2) Identify specifically all leases involved, all owners of interests in those leases, and the operator(s) for
those leases;
(3) Completely explain all relevant facts. You must inform ONRR of any changes to relevant facts that
occur before we respond to your request;
(4) Include copies of all relevant documents;
(5) Provide your analysis of the issue(s), including citations to all relevant precedents (including adverse
precedents); and
(6) Suggest your proposed gross proceeds calculation or valuation method.
(b) In response to your request:
(1) The Assistant Secretary, Policy, Management and Budget, may issue a determination; or
(2) ONRR may issue a determination; or

(3) ONRR may inform you in writing that ONRR will not provide a determination. Situations in which
ONRR typically will not provide any determination include, but are not limited to:
(i) Requests for guidance on hypothetical situations; and
(ii) Matters that are the subject of pending litigation or administrative appeals.
(c)(1) A determination signed by the Assistant Secretary, Policy, Management and Budget, is binding on
both you and ONRR until the Assistant Secretary modifies or rescinds it.
(2) After the Assistant Secretary issues a determination, you must make any adjustments in royalty
payments that follow from the determination and, if you owe additional royalties, pay the royalties owed
together with late payment interest computed under §1218.302 of this chapter.
(3) A determination signed by the Assistant Secretary is the final action of the Department and is subject
to judicial review under 5 U.S.C. 701–706.
(d) A determination issued by ONRR is binding on ONRR and delegated States, but not on you, with
respect to the specific situation addressed in the determination unless ONRR (for ONRR-issued
determinations) or the Assistant Secretary modifies or rescinds it.
(1) A determination by ONRR is not an appealable decision or order under 30 CFR part 1290 subpart B.
(2) If you receive an order requiring you to pay royalty on the same basis as the determination, you may
appeal that order under 30 CFR part 1290 subpart B.
(e) In making a determination, ONRR or the Assistant Secretary may use any of the applicable criteria in
this subpart.
(f) A change in an applicable statute or regulation on which any determination is based takes
precedence over the determination after the effective date of the statute or regulation, regardless of
whether ONRR or the Assistant Secretary modifies or rescinds the determination.
(g) ONRR or the Assistant Secretary generally will not retroactively modify or rescind a determination
issued under paragraph (d) of this section, unless:
(1) There was a misstatement or omission of material facts; or
(2) The facts subsequently developed are materially different from the facts on which the guidance was
based.
(h) ONRR may make requests and replies under this section available to the public, subject to the
confidentiality requirements under §1206.365.

§ 1206.365 Does ONRR protect information I provide?
top
Certain information you submit to ONRR regarding royalties or fees on geothermal resources or
byproducts, including deductions and allowances, may be exempt from disclosure. To the extent
applicable laws and regulations permit, ONRR 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.

§ 1206.366 What is the nominal fee that a State, tribal, or local government lessee
must pay for the use of geothermal resources?

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

Subpart I—OCS Sulfur [Reserved]
top

Subpart J—Indian Coal
top

Source: 61 FR 5481, Feb. 12, 1996, unless otherwise noted.
§ 1206.450 Purpose and scope.
top
(a) This subpart prescribes the procedures to establish the value, for royalty purposes, of all coal from
Indian Tribal and allotted leases (except leases on the Osage Indian Reservation, Osage County,
Oklahoma).
(b) If the specific provisions of any statute, treaty, or settlement agreement between the Indian lessor
and a lessee resulting from administrative or judicial litigation, or any coal lease subject to the
requirements of this subpart, are inconsistent with any regulation in this subpart, then the statute, treaty,
lease provision, or settlement shall govern to the extent of that inconsistency.
(c) All royalty payments are subject to later audit and adjustment.
(d) The regulations in this subpart are intended to ensure that the trust responsibilities of the United
States with respect to the administration of Indian coal leases are discharged in accordance with the
requirements of the governing mineral leasing laws, treaties, and lease terms.

§ 1206.451 Definitions.
top
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 ONRR-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 ONRR-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 ONRR-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 ONRR 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. ONRR may require the lessee to certify ownership control. To
be considered arm's-length for any production month, a contract must meet the requirements of this
definition for that production month, as well as when the contract was executed.
Audit means a review, conducted in accordance with generally accepted accounting and auditing
standards, of royalty payment compliance activities of lessees or other interest holders who pay
royalties, rents, or bonuses on Indian leases.
BIA means the Bureau of Indian Affairs of the Department of the Interior.
BLM means the Bureau of Land Management of the Department of the Interior.
Coal means coal of all ranks from lignite through anthracite.
Coal washing means any treatment to remove impurities from coal. Coal washing may include, but is not
limited to, operations such as flotation, air, water, or heavy media separation; drying; and related
handling (or combination thereof).
Contract means any oral or written agreement, including amendments or revisions thereto, between two
or more persons and enforceable by law that with due consideration creates an obligation.
Gross proceeds (for royalty payment purposes) means the total monies and other consideration
accruing to a coal lessee for the production and disposition of the coal produced. Gross proceeds
includes, but is not limited to, payments to the lessee for certain services such as crushing, sizing,
screening, storing, mixing, loading, treatment with substances including chemicals or oils, and other
preparation of the coal to the extent that the lessee is obligated to perform them at no cost to the Indian
lessor. Gross proceeds, as applied to coal, also includes but is not limited to reimbursements for
royalties, taxes or fees, and other reimbursements. Tax reimbursements are part of the gross proceeds
accruing to a lessee even though the Indian royalty interest may be exempt from taxation. Monies and
other consideration, including the forms of consideration identified in this paragraph, to which a lessee is
contractually or legally entitled but which it does not seek to collect through reasonable efforts are also
part of gross proceeds.
Indian allottee means any Indian for whom land or an interest in land is held in trust by the United States
or who holds title subject to Federal restriction against alienation.
Indian Tribe means any Indian Tribe, band, nation, pueblo, community, rancheria, colony, or other group
of Indians for which any land or interest in land is held in trust by the United States or which is subject to
Federal restriction against alienation.
Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or
approved by the United States for an Indian coal resource under a mineral leasing law that authorizes
exploration for, development or extraction of, or removal of coal—or the land covered by that
authorization, whichever is required by the context.
Lessee means any person to whom the Indian Tribe or an Indian allottee issues a lease, and any person
who has been assigned an obligation to make royalty or other payments required by the lease. This
includes any person who has an interest in a lease as well as an operator or payor who has no interest
in the lease but who has assumed the royalty payment responsibility.
Like-quality coal means coal that has similar chemical and physical characteristics.
Marketable condition means coal that is sufficiently free from impurities and otherwise in a condition that
it will be 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.
ONRR means the Office of Natural Resources Revenue of the Department of the Interior.
Person means by individual, firm, corporation, association, partnership, consortium, or joint venture.
Sales type code means the contract type or general disposition (e.g., arm's-length or non-arm's-length)
of production from the lease. The sales type code applies to the sales contract, or other disposition, and
not to the arm's-length or non-arm's-length nature of a transportation or washing allowance.
Spot market price means the price received under any sales transaction when planned or actual
deliveries span a short period of time, usually not exceeding one year.
[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999; 73 FR 15891, Mar. 26, 2008]

§ 1206.452 Coal subject to royalties—general provisions.
top
(a) All coal (except coal unavoidably lost as determined by BLM pursuant to 43 CFR group 3400) from
an Indian lease subject to this part is subject to royalty. This includes coal used, sold, or otherwise
disposed of by the lessee on or off the lease.
(b) If a lessee receives compensation for unavoidably lost coal through insurance coverage or other
arrangements, royalties at the rate specified in the lease are to be paid on the amount of compensation
received for the coal. No royalty is due on insurance compensation received by the lessee for other
losses.
(c) If waste piles or slurry ponds are reworked to recover coal, the lessee shall pay royalty at the rate
specified in the lease at the time the recovered coal is used, sold, or otherwise finally disposed of. The
royalty rate shall be that rate applicable to the production method used to initially mine coal in the waste
pile or slurry pond; i.e. , underground mining method or surface mining method. Coal in waste pits or
slurry ponds initially mined from Indian leases shall be allocated to such leases regardless of whether it
is stored on Indian lands. The lessee shall maintain accurate records to determine to which individual
Indian lease coal in the waste pit or slurry pond should be allocated. However, nothing in this section
requires payment of a royalty on coal for which a royalty has already been paid.

§ 1206.453 Quality and quantity measurement standards for reporting and paying
royalties.
top
For all leases subject to this subpart, the quantity of coal on which royalty is due shall be measured in
short tons (of 2,000 pounds each) by methods prescribed by the BLM. Coal quantity information will be
reported on appropriate forms required under 30 CFR part 1210—Forms and Reports.
[61 FR 5481, Feb. 12, 1996, as amended at 66 FR 45769, Aug. 30, 2001; 73 FR 15892, Mar. 26, 2008]

§ 1206.454 Point of royalty determination.
top
(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 ONRR.
(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. ONRR 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 §1206.455(d) of this subpart.

§ 1206.455 Valuation standards for cents-per-ton leases.
top
(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 §1206.456 of
this subpart, and royalties shall be paid at the royalty rate specified in the readjusted lease.

§ 1206.456 Valuation standards for ad valorem leases.
top
(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 §§1206.457 through 1206.461 of this
subpart, or any allowance authorized by §1206.464 of this subpart. The royalty due shall be equal to the
value for royalty purposes multiplied by the royalty rate in the lease.
(b)(1) The value of coal that is sold pursuant to an arm's-length contract shall be the gross proceeds
accruing to the lessee, except as provided in paragraphs (b)(2), (b)(3), and (b)(5) of this section. The
lessee shall have the burden of demonstrating that its contract is arm's-length. The value which the
lessee reports, for royalty purposes, is subject to monitoring, review, and audit.
(2) In conducting reviews and audits, ONRR 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 ONRR 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 ONRR 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 ONRR 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 ONRR
determines that the value may be unreasonable, ONRR will notify the lessee and give the lessee an
opportunity to provide written information justifying the lessee's reported coal value.
(4) ONRR 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 ONRR' 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'slength 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'slength contracts between buyers and sellers neither of whom is affiliated with the lessee for sales,
purchases, or other dispositions of like-quality coal produced in the area. In evaluating the comparability
of arm's-length contracts for the purposes of these regulations, the following factors shall be considered:
price, time of execution, duration, market or markets served, terms, quality of coal, quantity, and such
other factors as may be appropriate to reflect the value of the coal;
(ii) Prices reported for that coal to a public utility commission;
(iii) Prices reported for that coal to the Energy Information Administration of the Department of Energy;
(iv) Other relevant matters including, but not limited to, published or publicly available spot market
prices, or information submitted by the lessee concerning circumstances unique to a particular lease
operation or the salability of certain types of coal;
(v) If a reasonable value cannot be determined using paragraphs (c)(2)(i), (c)(2)(ii), (c)(2)(iii), or (c)(2)(iv)
of this section, then a net-back method or any other reasonable method shall be used to determine
value.
(3) When the value of coal is determined pursuant to paragraph (c)(2) of this section, that value
determination shall be consistent with the provisions contained in paragraph (b)(5) of this section.
(d)(1) Where the value is determined pursuant to paragraph (c) of this section, that value does not
require ONRR' 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 ONRR 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 ONRR 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 ONRR 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 Director for Office of Natural
Resources Revenue 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 ONRR 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 ONRR. The lessee shall also be liable for
interest computed pursuant to 30 CFR 218.202. If the lessee is entitled to a credit, ONRR will provide
instructions for the taking of that credit.
(f) The lessee may request a value determination from ONRR. In that event, the lessee shall propose to
ONRR a value determination method, and may use that method in determining value for royalty
purposes until ONRR issues its decision. The lessee shall submit all available data relevant to its
proposal. ONRR shall expeditiously determine the value based upon the lessee's proposal and any
additional information ONRR deems necessary. That determination shall remain effective for the period
stated therein. After ONRR 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 §§1206.457 through 1206.461 and §1206.464 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 ONRR 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 ONRR 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 ONRR to support valuation proposals, including transportation, coal
washing, or other allowances pursuant to §§1206.457 through 1206.461 and §1206.464 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 ONRR 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]

§ 1206.457 Washing allowances—general.
top
(a) For ad valorem leases subject to §1206.456 of this subpart, ONRR 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 §1206.456 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 ONRR 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 §1218.202 of this chapter, 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]

§ 1206.458 Determination of washing allowances.
top
(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. ONRR'
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 ONRR, unless ONRR approves a longer period
upon a showing of good cause by the lessee.
(2) In conducting reviews and audits, ONRR 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 ONRR may require that the
washing allowance be determined in accordance with paragraph (b) of this section.
(3) If ONRR 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 ONRR shall require that the washing allowance be
determined in accordance with paragraph (b) of this section. When ONRR determines that the value of
the washing may be unreasonable, ONRR 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 dollarper-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'slength or no contract situation are subject to monitoring, review, audit, and possible future adjustment.
Prior ONRR 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 ONRR, unless ONRR approves a longer period upon a showing of
good cause by the lessee. ONRR will monitor the allowance deduction to ensure that deductions are
reasonable and allowable. When necessary or appropriate, ONRR 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 ONRR.
(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 ONRR 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) ONRR 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 ONRR approves a longer period
(during which period the lessee shall continue to use the allowance from the previous reporting period).
(iv) ONRR 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 ONRR.
(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 ONRR in writing shall
qualify as being in effect at the time these regulations become effective.
(vi) ONRR may establish, in appropriate circumstances, reporting requirements that are different from
the requirements of this section.
(2) Non-arm's-length or no contract. (i) With the exception of those washing allowances specified in
paragraphs (c)(2)(v) and (c)(2)(vii) of this section, the lessee shall submit an initial Form MMS–4292
prior to, or at the same time as, the washing allowance determined pursuant to a non-arm's-length
contract or no contract situation is reported on Form MMS–4430, Solid Minerals Production and Royalty
Report. A Form MMS–4292 received by the end of the month that the Form MMS–4430 is due shall be
considered to be timely received. The initial reporting may be based on estimated costs.
(ii) The initial Form MMS–4292 shall be effective for a reporting period beginning the month that the
lessee first is authorized to deduct a washing allowance and shall continue until the end of the calendar
year, or until the washing under the non-arm's-length contract or the no contract situation terminates,
whichever is earlier.
(iii) For calendar-year reporting periods succeeding the initial reporting period, the lessee shall submit a
completed Form MMS–4292 containing the actual costs for the previous reporting period. If coal
washing is continuing, the lessee shall include on Form MMS–4292 its estimated costs for the next
calendar year. The estimated coal washing allowance shall be based on the actual costs for the previous
period plus or minus any adjustments which are based on the lessee's knowledge of decreases or
increases which will affect the allowance. Form MMS–4292 must be received by ONRR within 3 months
after the end of the previous reporting period, unless ONRR 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 ONRR in writing shall
qualify as being in effect at the time these regulations become effective.
(vi) Upon request by ONRR, 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 ONRR.
(vii) ONRR may establish, in appropriate circumstances, reporting requirements which are different from
the requirements of this section.
(3) ONRR 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 ONRR
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 §1218.202 of this
chapter.
(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 §1218.202, 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 ONRR.
(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]

§ 1206.459 Allocation of washed coal.
top
(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.

§ 1206.460 Transportation allowances—general.
top
(a) For ad valorem leases subject to §1206.456 of this subpart, where the value for royalty purposes has
been determined at a point remote from the lease or mine, ONRR 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, ONRR 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 §7thnsp;1218.202 of this chapter, 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]

§ 1206.461 Determination of transportation allowances.
top
(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. ONRR' 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 ONRR,
unless ONRR approves a longer period upon a showing of good cause by the lessee.
(2) In conducting reviews and audits, ONRR 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 ONRR may require
that the transportation allowance be determined in accordance with paragraph (b) of this section.
(3) If ONRR 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 ONRR shall require that the
transportation allowance be determined in accordance with paragraph (b) of this section. When ONRR
determines that the value of the transportation may be unreasonable, ONRR 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 ONRR 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 ONRR, unless ONRR approves a
longer period upon a showing of good cause by the lessee. ONRR will monitor the allowance deductions
to ensure that deductions are reasonable and allowable. When necessary or appropriate, ONRR 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 ONRR.
(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 ONRR 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) ONRR 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 ONRR for exception from the requirement that it compute actual costs in
accordance with paragraphs (b)(1) and (b)(2) of this section. ONRR will grant the exception only if the
lessee has a rate for the transportation approved by a Federal agency for Indian leases. ONRR 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, ONRR 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 ONRR 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 ONRR 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) ONRR 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 ONRR.
(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 ONRR in writing shall
qualify as being in effect at the time these regulations become effective.
(vi) ONRR 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 ONRR
within 3 months after the end of the previous reporting period, unless ONRR 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 ONRR in writing shall
qualify as being in effect at the time these regulations become effective.

(vi) Upon request by ONRR, 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 ONRR.
(vii) ONRR 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) ONRR 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
ONRR 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 §1218.202 of this
chapter.
(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 §1218.202 of this chapter,
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 ONRR.
(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]

§ 1206.462 [Reserved]
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§ 1206.463 In-situ and surface gasification and liquefaction operations.
top
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 ONRR. ONRR will review
the lessee's proposal and issue a value determination. The lessee may use its proposed value until
ONRR issues a value determination.
[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999]

§ 1206.464 Value enhancement of marketable coal.
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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 §1206.456(h) of this subpart, the lessee shall notify
ONRR 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
§1206.456(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 §1206.456(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 ONRR-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 §1206.458(b)(2)(v) of this
subpart.
[61 FR 5481, Feb. 12, 1996, as amended 64 FR 43289, Aug. 10, 1999]
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