Title 30 CFR Chapter XII

Electronic Code of Federal Regulations
e-CFR data is current as of May 10, 2019
Title 30 → Chapter XII → Subchapter A

Title 30: Mineral Resources

PART 1202—ROYALTIES
Contents
Subpart A—General Provisions [Reserved]
Subpart B—Oil, Gas, and OCS Sulfur, General
§1202.51 Scope and definitions.
§1202.52 Royalties.
§1202.53 Minimum royalty.
Subpart C—Federal and Indian Oil
§1202.100 Royalty on oil.
§1202.101 Standards for reporting and paying royalties.
Subpart D—Federal Gas
§1202.150 Royalty on gas.
§1202.151 Royalty on processed gas.
§1202.152 Standards for reporting and paying royalties on gas.

AUTHORITY: 5 U.S.C. 301 et seq.; 25 U.S.C. 396 et seq., 396a et seq., 2101 et seq.; 30 U.S.C. 181 et
seq., 351 et seq., 1001 et seq.;1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq.; 1331 et seq., 1801 et seq.
SOURCE: 48 FR 35641, Aug. 5, 1983, unless otherwise noted. Redesignated at 75 FR 61066, Oct. 4, 2010.

Subpart A—General Provisions [Reserved]
Subpart B—Oil, Gas, and OCS Sulfur, General
SOURCE: 53 FR 1217, Jan. 15, 1988, unless otherwise noted.

§1202.51 Scope and definitions.
(a) This subpart is applicable to Federal and Indian (Tribal and allotted) oil and gas leases
(except leases on the Osage Indian Reservation, Osage County, Oklahoma) and OCS sulfur leases.
(b) The definitions in subparts B, C, D, and E of part 1206 of this title are applicable to subparts
B, C, D, and J of this part.
[53 FR 1217, Jan. 15, 1988, as amended at 64 FR 43513, Aug. 10, 1999; 81 FR 43369, July 1, 2016; 82 FR 36953,
Aug. 7, 2017]

§1202.52 Royalties.
(a) Royalties on oil, gas, and OCS sulfur shall be at the royalty rate specified in the lease,
unless the Secretary, pursuant to the provisions of the applicable mineral leasing laws, reduces, or
in the case of OCS leases, reduces or eliminates, the royalty rate or net profit share set forth in the
lease.
(b) For purposes of this subpart, the use of the term royalty(ies) includes the term net profit
share(s).
§1202.53 Minimum royalty.
For leases that provide for minimum royalty payments, the lessee shall pay the minimum
royalty as specified in the lease.

Subpart C—Federal and Indian Oil
§1202.100 Royalty on oil.
(a) Royalties due on oil production from leases subject to the requirements of this part,
including condensate separated from gas without processing, shall be at the royalty rate established
by the terms of the lease. Royalty shall be paid in value unless the Office of Natural Resources
Revenue (ONRR) requires payment in-kind. When paid in value, the royalty due shall be the value,
for royalty purposes, determined pursuant to part 1206 of this title multiplied by the royalty rate in the
lease.
(b)(1) All oil (except oil unavoidably lost or used on, or for the benefit of, the lease, including
that oil used off-lease for the benefit of the lease when such off-lease use is permitted by the Bureau
of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) or BLM, as appropriate)
produced from a Federal or Indian lease to which this part applies is subject to royalty.
(2) When oil is used on, or for the benefit of, the lease at a production facility handling
production from more than one lease with the approval of the BSEE or BLM, as appropriate, or at a
production facility handling unitized or communitized production, only that proportionate share of
each lease's production (actual or allocated) necessary to operate the production facility may be
used royalty-free.
(3) Where the terms of any lease are inconsistent with this section, the lease terms shall govern
to the extent of that inconsistency.

(c) If BLM determines that oil was avoidably lost or wasted from an onshore lease, or that oil
was drained from an onshore lease for which compensatory royalty is due, or if BSEE determines
that oil was avoidably lost or wasted from an offshore lease, then the value of that oil shall be
determined in accordance with 30 CFR part 1206.
(d) If a lessee receives insurance compensation for unavoidably lost oil, royalties are due on
the amount of that compensation. This paragraph shall not apply to compensation through selfinsurance.
(e)(1) In those instances where the lessee of any lease committed to a federally approved
unitization or communitization agreement does not actually take the proportionate share of the
agreement production attributable to its lease under the terms of the agreement, the full share of
production attributable to the lease under the terms of the agreement nonetheless is subject to the
royalty payment and reporting requirements of this title. Except as provided in paragraph (e)(2) of
this section, the value, for royalty purposes, of production attributable to unitized or communitized
leases will be determined in accordance with 30 CFR part 1206. In applying the requirements of 30
CFR part 1206, the circumstances involved in the actual disposition of the portion of the production
to which the lessee was entitled but did not take shall be considered as controlling in arriving at the
value, for royalty purposes, of that portion as though the person actually selling or disposing of the
production were the lessee of the Federal or Indian lease.
(2) If a Federal or Indian lessee takes less than its proportionate share of agreement
production, upon request of the lessee ONRR may authorize a royalty valuation method different
from that required by paragraph (e)(1) of this section, but consistent with the purposes of these
regulations, for any volumes not taken by the lessee but for which royalties are due.
(3) For purposes of this subchapter, all persons actually taking volumes in excess of their
proportionate share of production in any month under a unitization or communitization agreement
shall be deemed to have taken ratably from all persons actually taking less than their proportionate
share of the agreement production for that month.
(4) If a lessee takes less than its proportionate share of agreement production for any month
but royalties are paid on the full volume of its proportionate share in accordance with the provisions
of this section, no additional royalty will be owed for that lease for prior periods when the lessee
subsequently takes more than its proportionate share to balance its account or when the lessee is
paid a sum of money by the other agreement participants to balance its account.
(f) For production from Federal and Indian leases which are committed to federally-approved
unitization or communitization agreements, upon request of a lessee ONRR may establish the value
of production pursuant to a method other than the method required by the regulations in this title if:
(1) The proposed method for establishing value is consistent with the requirements of the applicable
statutes, lease terms, and agreement terms; (2) persons with an interest in the agreement, including,
to the extent practical, royalty interests, are given notice and an opportunity to comment on the
proposed valuation method before it is authorized; and (3) to the extent practical, persons with an
interest in a Federal or Indian lease committed to the agreement, including royalty interests, must
agree to use the proposed method for valuing production from the agreement for royalty purposes.
[53 FR 1217, Jan. 15, 1988, as amended at 78 FR 30200, May 22, 2013]

§1202.101 Standards for reporting and paying royalties.
Oil volumes are to be reported in barrels of clean oil of 42 standard U.S. gallons (231 cubic
inches each) at 60 °F. When reporting oil volumes for royalty purposes, corrections must have been
made for Basic Sediment and Water (BS&W) and other impurities. Reported American Petroleum
Institute (API) oil gravities are to be those determined in accordance with standard industry
procedures after correction to 60 °F.
[53 FR 1217, Jan. 15, 1988]

Subpart D—Federal Gas
SOURCE: 53 FR 1271, Jan. 15, 1988, unless otherwise noted.

§1202.150 Royalty on gas.
(a) Royalties due on gas production from leases subject to the requirements of this subpart,
except helium produced from Federal leases, shall be at the rate established by the terms of the
lease. Royalty shall be paid in value unless ONRR requires payment in kind. When paid in value, the
royalty due shall be the value, for royalty purposes, determined pursuant to 30 CFR part 1206 of this
title multiplied by the royalty rate in the lease.
(b)(1) All gas (except gas unavoidably lost or used on, or for the benefit of, the lease, including
that gas used off-lease for the benefit of the lease when such off-lease use is permitted by the BSEE
or BLM, as appropriate) produced from a Federal lease to which this subpart applies is subject to
royalty.
(2) When gas is used on, or for the benefit of, the lease at a production facility handling
production from more than one lease with the approval of BSEE or BLM, as appropriate, or at a
production facility handling unitized or communitized production, only that proportionate share of
each lease's production (actual or allocated) necessary to operate the production facility may be
used royalty free.
(3) Where the terms of any lease are inconsistent with this subpart, the lease terms shall
govern to the extent of that inconsistency.
(c) If BLM determines that gas was avoidably lost or wasted from an onshore lease, or that gas
was drained from an onshore lease for which compensatory royalty is due, or if BSEE determines
that gas was avoidably lost or wasted from an OCS lease, then the value of that gas shall be
determined in accordance with 30 CFR part 1206.
(d) If a lessee receives insurance compensation for unavoidably lost gas, royalties are due on
the amount of that compensation. This paragraph shall not apply to compensation through selfinsurance.
(e)(1) In those instances where the lessee of any lease committed to a Federally approved
unitization or communitization agreement does not actually take the proportionate share of the
production attributable to its Federal lease under the terms of the agreement, the full share of
production attributable to the lease under the terms of the agreement nonetheless is subject to the
royalty payment and reporting requirements of this title. Except as provided in paragraph (e)(2) of
this section, the value for royalty purposes of production attributable to unitized or communitized
leases will be determined in accordance with 30 CFR part 1206. In applying the requirements of 30

CFR part 1206, the circumstances involved in the actual disposition of the portion of the production
to which the lessee was entitled but did not take shall be considered as controlling in arriving at the
value for royalty purposes of that portion, as if the person actually selling or disposing of the
production were the lessee of the Federal lease.
(2) If a Federal lessee takes less than its proportionate share of agreement production, upon
request of the lessee ONRR may authorize a royalty valuation method different from that required by
paragraph (e)(1) of this section, but consistent with the purpose of these regulations, for any
volumes not taken by the lessee but for which royalties are due.
(3) For purposes of this subchapter, all persons actually taking volumes in excess of their
proportionate share of production in any month under a unitization or communitization agreement
shall be deemed to have taken ratably from all persons actually taking less than their proportionate
share of the agreement production for that month.
(4) If a lessee takes less than its proportionate share of agreement production for any month
but royalties are paid on the full volume of its proportionate share in accordance with the provisions
of this section, no additional royalty will be owed for that lease for prior periods at the time the lessee
subsequently takes more than its proportionate share to balance its account or when the lessee is
paid a sum of money by the other agreement participants to balance its account.
(f) For production from Federal leases which are committed to federally-approved unitization or
communitization agreements, upon request of a lessee ONRR may establish the value of production
pursuant to a method other than the method required by the regulations in this title if: (1) The
proposed method for establishing value is consistent with the requirements of the applicable
statutes, lease terms and agreement terms; (2) to the extent practical, persons with an interest in the
agreement, including royalty interests, are given notice and an opportunity to comment on the
proposed valuation method before it is authorized; and (3) to the extent practical, persons with an
interest in a Federal lease committed to the agreement, including royalty interests, must agree to
use the proposed method for valuing production from the agreement for royalty purposes.
[53 FR 1271, Jan. 15, 1988, as amended at 64 FR 43513, Aug. 10, 1999; 78 FR 30200, May 22, 2013]

§1202.151 Royalty on processed gas.
(a)(1) A royalty, as provided in the lease, shall be paid on the value of:
(i) Any condensate recovered downstream of the point of royalty settlement without resorting to
processing; and
(ii) Residue gas and all gas plant products resulting from processing the gas produced from a
lease subject to this subpart.
(2) ONRR shall authorize a processing allowance for the reasonable, actual costs of processing
the gas produced from Federal leases. Processing allowances shall be determined in accordance
with 30 CFR part 1206 subpart D for gas production from Federal leases and 30 CFR part 1206
subpart E for gas production from Indian leases.
(b) A reasonable amount of residue gas shall be allowed royalty free for operation of the
processing plant, but no allowance shall be made for boosting residue gas or other expenses
incidental to marketing, except as provided in 30 CFR part 1206. In those situations where a

processing plant processes gas from more than one lease, only that proportionate share of each
lease's residue gas necessary for the operation of the processing plant shall be allowed royalty free.
(c) No royalty is due on residue gas, or any gas plant product resulting from processing gas,
which is reinjected into a reservoir within the same lease, unit area, or communitized area, when the
reinjection is included in a plan of development or operations and the plan has received BLM or
Bureau of Ocean Energy Management (BOEM) approval for onshore or offshore operations,
respectively, until such time as they are finally produced from the reservoir for sale or other
disposition off-lease.
[53 FR 1217, Jan. 15, 1988, as amended at 61 FR 5490, Feb. 12, 1996; 64 FR 43513, Aug. 10, 1999; 78 FR 30200,
May 22, 2013]

§1202.152 Standards for reporting and paying royalties on gas.
(a)(1) If you are responsible for reporting production or royalties, you must:
(i) Report gas volumes and British thermal unit (Btu) heating values, if applicable, under the
same degree of water saturation;
(ii) Report gas volumes in units of 1,000 cubic feet (mcf); and
(iii) Report gas volumes and Btu heating value at a standard pressure base of 14.73 pounds
per square inch absolute (psia) and a standard temperature base of 60 °F.
(2) The frequency and method of Btu measurement as set forth in the lessee's contract shall be
used to determine Btu heating values for reporting purposes. However, the lessee shall measure the
Btu value at least semiannually by recognized standard industry testing methods even if the lessee's
contract provides for less frequent measurement.
(b)(1) Residue gas and gas plant product volumes shall be reported as specified in this
paragraph.
(2) Carbon dioxide (CO2), nitrogen (N2), helium (He), residue gas, and any other gas marketed
as a separate product shall be reported by using the same standards specified in paragraph (a) of
this section.
(3) Natural gas liquids (NGL) volumes shall be reported in standard U.S. gallons (231 cubic
inches) at 60 °F.
(4) Sulfur (S) volumes shall be reported in long tons (2,240 pounds).
[53 FR 1271, Jan. 15, 1988, as amended at 63 FR 26367, May 12, 1998]

PART 1204—ALTERNATIVES FOR MARGINAL
PROPERTIES
Contents
Subpart A—General Provisions
§1204.1 What is the purpose of this part?
§1204.2 What definitions apply to this part?
§1204.3 What alternatives are available for marginal properties?
§1204.4 What is a marginal property under this part?
§1204.5 What statutory requirements must I meet to obtain royalty prepayment or accounting and
auditing relief?
§1204.6 May I appeal if ONRR denies my request for prepayment or other relief?
Subpart B—Prepayment of Royalty [Reserved]
Subpart C—Accounting and Auditing Relief
§1204.200 What is the purpose of this subpart?
§1204.201 Who may obtain accounting and auditing relief?
§1204.202 What is the cumulative royalty reports and payments relief option?
§1204.203 What is the other relief option?
§1204.204 What accounting and auditing relief will ONRR not allow?
§1204.205 How do I obtain accounting and auditing relief?
§1204.206 What will ONRR do when it receives my request for other relief?
§1204.207 Who will approve, deny, or modify my request for accounting and auditing relief?
§1204.208 May a State decide that it will or will not allow one or both of the relief options under this
subpart?
§1204.209 What if a property ceases to qualify for relief obtained under this subpart?
§1204.210 What if a property is approved as part of a nonqualifying agreement?
§1204.211 When may ONRR rescind relief for a property?
§1204.212 What if I took relief for which I was ineligible?
§1204.213 May I obtain relief for a property that benefits from other Federal or State incentive
programs?
§1204.214 Is minimum royalty due on a property for which I took relief?
§1204.215 Are the information collection requirements in this subpart approved by the Office of
Management and Budget (OMB)?

AUTHORITY: 30 U.S.C. 1701 et seq.
SOURCE: 69 FR 55088, Sept. 13, 2004, unless otherwise noted. Redesignated at 75 FR 61067, Oct. 4, 2010.

Subpart A—General Provisions
§1204.1 What is the purpose of this part?
This part explains how you as a lessee or designee of a Federal onshore or Outer Continental
Shelf (OCS) oil and gas lease may obtain prepayment or accounting and auditing relief for
production from certain marginal properties. This part does not apply to production from Indian
leases, even if the Indian lease is within an agreement that qualifies as a marginal property.
§1204.2 What definitions apply to this part?
Agreement means a federally approved communitization agreement or unit participating area.
Barrels of oil equivalent (BOE) means the combined equivalent production of oil and gas stated
in barrels of oil. Each barrel of oil production is equal to one BOE. Also, each 6,000 cubic feet of gas
production is equal to one BOE.
Base period means the 12-month period from July 1 through June 30 immediately preceding
the calendar year for which you take or request marginal property relief. For example, if you request
relief for calendar year 2006, your base period is July 1, 2004, through June 30, 2005.
Combined equivalent production means the total of all oil and gas production for the marginal
property, stated in BOE.
Designee means the person designated by a lessee under §1218.52 to make all or part of the
royalty or other payments due on a lease on the lessee's behalf.
Producing wells means only those producing oil or gas wells that contribute to the sum of BOE
used in the calculation under §1204.4(c). Producing wells do not include injection or water wells.
Wells with multiple zones commingled downhole are considered as a single well.
Property means a lease, a portion of a lease, or an agreement that may be a marginal property
if it meets the qualification requirements of §1204.4.
State concerned (State) means the State that receives a statutorily prescribed portion of the
royalties from a Federal onshore or OCS lease.
§1204.3 What alternatives are available for marginal properties?
If you have production from a marginal property, ONRR and the State may allow you the
following options:
(a) Prepay royalty. ONRR and the State may allow you to make a lump-sum advance payment
of royalties instead of monthly royalty payments for the remainder of the lease term. See subpart B
for prepayment of royalty requirements.
(b) Take accounting and auditing relief. ONRR and the State may allow various accounting and
auditing relief options to encourage you to continue to produce and develop your marginal property.
See subpart C for accounting and auditing relief requirements.

§1204.4 What is a marginal property under this part?
(a) To qualify as a marginal property eligible for royalty prepayment or accounting and auditing
relief under this part, the property must meet the following requirements:

If your lease is . . .

Then . . .

And . . .

(1) Not in an agreement The lease must qualify as
a marginal property under
paragraph (b) of this
section
(2) Entirely or partly
committed to one
agreement

The entire agreement must Agreement production allocable to your
qualify as a marginal
lease may be eligible for relief under this
property under paragraph part. Any production from your lease that is
(b) of this section
not committed to the agreement also may
be eligible for separate relief under
paragraph (a)(4) of this table.

(3) Entirely or partly
Each agreement must
committed to more than qualify separately as a
one agreement
marginal property under
paragraph (b) of this
section

(4) Partly committed to
an agreement and you
have production from
the part of the lease that
is not committed to the
agreement

For any agreement that does qualify, that
agreement's production allocable to your
lease may be eligible for relief under this
part. Any production from your lease that is
not committed to an agreement also may be
eligible for separate relief under paragraph
(a)(4) of this table.

The part of the lease that
is not committed to the
agreement must qualify
separately as a marginal
property under paragraph
(b) of this section

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

§1204.5 What statutory requirements must I meet to obtain royalty prepayment or
accounting and auditing relief?
(a) ONRR and the State may allow royalty prepayment or accounting and auditing relief for
your marginal property production if ONRR and the State jointly determine that the prepayment or
accounting and auditing relief is in the best interests of the Federal Government and the State to:
(1) Promote production;
(2) Reduce the administrative costs of ONRR and the State; and
(3) Increase net receipts to the Federal Government and the State.
(b) At any time, if ONRR and the State determine that either prepayment or accounting and
auditing relief no longer meets the criteria in paragraph (a) of this section, ONRR, with the State's
concurrence, may discontinue any prepayment or accounting and auditing relief options granted for
production from any marginal property.
(1) ONRR will provide you written notice of the decision to discontinue relief.
(i) If you took the cumulative reports and payments relief option under §1204.202, your relief
will terminate at the end of the calendar year in which you received the notice.
(ii) If you were approved for prepayment relief under subpart B of this part or other relief under
§1204.203, ONRR's notice will tell you when your relief terminates.
(2) ONRR's decision to discontinue relief is not subject to administrative appeal.
§1204.6 May I appeal if ONRR denies my request for prepayment or other relief?
If ONRR denies your request for prepayment relief under subpart B of this part or other relief
under §1204.203, you may appeal under 30 CFR part 1290.

Subpart B—Prepayment of Royalty [Reserved]
Subpart C—Accounting and Auditing Relief
§1204.200 What is the purpose of this subpart?
This subpart explains how you as a lessee or designee may obtain accounting and auditing
relief for your Federal onshore or OCS lease production from a marginal property. The two types of
accounting and auditing relief that you can receive under this subpart are cumulative reports and
payment relief (explained in §1204.202) and other accounting and auditing relief appropriate for your
property (explained in §1204.203).

§1204.201 Who may obtain accounting and auditing relief?
(a) You may obtain accounting and auditing relief under this subpart:
(1) If you are a lessee or a designee for a Federal lease with production from a property that
qualifies as a marginal property under §1204.4;
(2) If you meet any additional requirements for specific types of relief under this subpart; and
(3) Only for the fractional interest in production from the marginal property for which you report
and pay royalty. You may obtain relief even if the other lessees or designees for your lease or
agreement do not request relief.
(b) You may not obtain one or both of the relief options specified in this subpart on any portion
of production from a marginal property if:
(1) The marginal property covers multiple States; and
(2) One of the States determines under §1204.208 that it will not allow the relief option you
seek.
§1204.202 What is the cumulative royalty reports and payments relief option?
(a) The cumulative royalty reports and payments relief option allows you to submit one royalty
report and payment annually for production during a calendar year. You are eligible for this option
only if the total volume produced from the marginal property (not just your share of the production) is
1,000 BOE or less during the base period.
(b) To use the cumulative royalty reports and payments relief option, you must do all of the
following:
(1) Notify ONRR in writing by January 31 of the calendar year for which you begin taking your
relief. See §1204.205(a) for what your notification must contain;
(2) Submit your royalty report and payment in accordance with 30 CFR 1218.51(g) by the end
of February of the year following the calendar year for which you reported annually, unless you have
an estimated payment on file. If you have an estimated payment on file, you must submit your
royalty report and payment by the end of March of the year following the calendar year for which you
reported annually;
(3) Use the sales month prior to the month that you submit your annual report and payment
under paragraph (b)(2) of this section on your Report of Sales and Royalty Remittance, Form
ONRR-2014, for the entire previous calendar year's production for which you are paying annually.
(For example, for a report in February use January as your sales month, and for a report in March
use February as your sales month, to report production for the entire previous calendar year for
which you are paying annually);
(4) Report one line of cumulative royalty information on Form ONRR-2014 for the calendar
year, the same as if it were a monthly report; and

(5) Report allowances on Form ONRR-2014 on the same annual basis as the royalties for your
marginal property production.
(c) If you do not pay your royalty by the date due in paragraph (b) of this section, you will owe
late payment interest determined under 30 CFR 1218.54 from the date your payment was due under
this section until the date ONRR receives it.
(d) If you take relief you are not qualified for, you may be liable for civil penalties. Also you
must:
(1) Pay ONRR late payment interest determined under §1218.54 from the date your payment
was due until the date ONRR receives it; and
(2) Amend your Form ONRR-2014 to reflect the required monthly reporting.
(e) If you dispose of your ownership interest in a marginal property for which you have taken
relief under this section (or if you are a designee who reports and pays royalty for a lessee who has
disposed of its ownership interest), you must:
(1) Report and pay royalties for the portion of the calendar year for which you had an ownership
interest; and
(2) Make the report and payment by the end of the month after you dispose of the ownership
interest in the marginal property. If you do not report and pay timely, you will owe interest determined
under §1218.54 from the date the payment was due under this section.
[69 FR 55088, Sept. 13, 2004, as amended at 78 FR 30200, May 22, 2013]

§1204.203 What is the other relief option?
(a) Under this relief option, you may request any type of accounting and auditing relief that is
appropriate for production from your marginal property, provided it is not prohibited under §1204.204
and meets the statutory requirements of §1204.5. Examples of relief options you could request are:
(1) To report and pay royalties using a valuation method other than that required under 30 CFR
part 1206 that approximates royalties payable under that part 1206; and
(2) To reduce your royalty audit burden. However, ONRR will not consider any request that
eliminates ONRR's or the States' right to audit.
(b) You must request approval from ONRR under §1204.205(b), and receive approval under
§1204.206 before taking relief under this option.
§1204.204 What accounting and auditing relief will ONRR not allow?
ONRR will not approve your request for accounting and auditing relief under this subpart if your
request:
(a) Prohibits ONRR or the State from conducting any form of audit;
(b) Permanently relieves you from making future royalty reports or payments;

(c) Provides for less frequent royalty reports and payments than annually;
(d) Provides for you to submit royalty reports and payments at separate times;
(e) Impairs ONRR's ability to properly or efficiently account for or distribute royalties;
(f) Requests relief for a lease under which the Federal Government takes its royalties in kind;
(g) Alters production reporting requirements;
(h) Alters lease operation or safety requirements;
(i) Conflicts with rent, minimum royalty, or lease requirements; or
(j) Requests relief for production from a marginal property located in whole or in part in a State
that has determined that it will not allow such relief under §1204.208.
§1204.205 How do I obtain accounting and auditing relief?
(a) To take cumulative reports and payments relief under §1204.202, you must notify ONRR in
writing by January 31 of the calendar year for which you begin taking your relief.
(1) Your notification must contain:
(i) Your company name, ONRR-assigned payor code, address, phone number, and contact
name; and
(ii) The specific ONRR lease number and agreement number, if applicable.
(2) You may file a single notification for multiple marginal properties.
(b) To obtain other relief under §1204.203, you must file a written request for relief with ONRR.
(1) Your request must contain:
(i) Your company name, ONRR-assigned payor code, address, phone number, and contact
name;
(ii) The ONRR lease number and agreement number, if applicable; and
(iii) A complete and detailed description of the specific accounting or auditing relief you seek.
(2) You may file a single request for multiple marginal properties if you are requesting the same
relief for all properties.

§1204.206 What will ONRR do when it receives my request for other relief?
When ONRR receives your request for other relief under §1204.205(b), it will notify you in
writing as follows:
(a) If your request for relief is complete, ONRR may either approve, deny, or modify your
request in writing after consultation with any State required under §1204.207(b).
(1) If ONRR approves your request for relief, ONRR will notify you of the effective date of your
accounting or auditing relief and other specifics of the relief approved.
(2) If ONRR denies your relief request, ONRR will notify you of the reasons for denial and your
appeal rights under §1204.6.
(3) If ONRR modifies your relief request, ONRR will notify you of the modifications.
(i) You have 60 days from your receipt of ONRR's notice to either accept or reject any
modification(s) in writing.
(ii) If you reject the modification(s) or fail to respond to ONRR's notice, ONRR will deny your
relief request. ONRR will notify you in writing of the reasons for denial and your appeal rights under
§1204.6.
(b) If your request for relief is not complete, ONRR will notify you in writing that your request is
incomplete and identify any missing information.
(1) You must submit the missing information within 60 days of your receipt of ONRR's notice
that your request is incomplete.
(2) After you submit all required information, ONRR may approve, deny, or modify your request
for relief under paragraph (a) of this section.
(3) If you do not submit all required information within 60 days of your receipt of ONRR's notice
that your request is incomplete, ONRR will deny your relief request. ONRR will notify you in writing
of the reasons for denial and your appeal rights under §1204.6.
(4) You may submit a new request for relief under this subpart at any time after ONRR returns
your incomplete request.
[69 FR 55088, Sept. 13, 2004, as amended at 78 FR 30200, May 22, 2013]

§1204.207 Who will approve, deny, or modify my request for accounting and auditing relief?
(a) If there is not a State concerned for your marginal property, only ONRR will decide whether
to approve, deny, or modify your relief request.
(b) If there is a State concerned for your marginal property that has determined in advance
under §1204.208 that it will allow either or both of the relief options under this subpart, ONRR will
decide whether to approve, deny, or modify your relief request after consulting with the State
concerned.

[69 FR 55088, Sept. 13, 2004, as amended at 76 FR 38561, July 1, 2011]

§1204.208 May a State decide that it will or will not allow one or both of the relief options
under this subpart?
(a) A State may decide in advance that it will or will not allow one or both of the relief options
specified in this subpart for a particular calendar year. If a State decides that it will not consent to
one or both of the relief options, ONRR will not grant that type of marginal property relief.
(b) To help States decide whether to allow one or both of the relief options specified in this
subpart, for each calendar year ONRR will send States a Report of Marginal Properties by October 1
preceding the calendar year.
(c) If a State decides under paragraph (a) of this section that it will or will not allow one or both
of the relief options in this subpart during the next calendar year, within 30 days of the State's receipt
of the Report of Marginal Properties under paragraph (b) of this section, the State must:
(1) Notify the Director for Office of Natural Resources Revenue, in writing, of its intent to allow
or not allow one or both of the relief options under this subpart; and
(2) Specify in its notice of intent to ONRR which relief option(s) it will allow or not allow.
(d) If a State decides in advance under paragraph (a) of this section that it will not allow one or
both of the relief options specified in this subpart, it may decide for subsequent calendar years that it
will allow one or both of the relief options in this subpart. If it so decides, within 30 days of the State's
receipt of the Report of Marginal Properties under paragraph (b) of this section, the State must:
(1) Notify the Director for Office of Natural Resources Revenue, in writing, of its intent to allow
one or both of the relief options allowed under this subpart during the next calendar year; and
(2) Specify in its notice of intent to ONRR which relief option(s) it will allow.
(e) If a State does not notify ONRR under paragraph (c) or (d) of this section, the State will be
deemed to have decided not to allow either of the relief options under this subpart for the next
calendar year.
(f) ONRR will publish a notice of the State s intent to allow or not allow certain relief options
under this section in the FEDERAL REGISTER no later than 30 days before the beginning of the
applicable calendar year.
§1204.209 What if a property ceases to qualify for relief obtained under this subpart?
(a) A marginal property must qualify for relief under this subpart for each calendar year based
on production during the base period for that calendar year. The notice or request you provided to
ONRR under §1204.205 for the first calendar year that the property qualified for relief remains
effective for successive calendar years if the property continues to qualify.
(b) If a property is no longer eligible for relief for any reason during a calendar year other than
the reason under §1204.210 or paragraph (c) of this section, the relief for the property terminates as
of December 31 of that calendar year. You must notify ONRR in writing by December 31 that the
relief for the property has terminated.

(c) If you dispose of your interest in a marginal property during the calendar year, your relief
terminates as of the end of the sales month in which you disposed of the property. Report and pay
royalties for your production using the procedures in §1204.202(e).
§1204.210 What if a property is approved as part of a nonqualifying agreement?
If the Bureau of Land Management (BLM) or BOEM retroactively approves a marginal property
that qualified for relief for inclusion as part of an agreement that does not qualify for relief under this
subpart, the property no longer qualifies for relief under this subpart then:
(a) ONRR will not retroactively rescind the marginal property relief for production from your
property under §1204.211;
(b) Your marginal property relief terminates as of December 31 of the calendar year that you
receive the BLM or BOEM approval of your marginal property as part of a nonqualifying agreement;
and
(c) For the calendar year in which you receive the BLM or BOEMRE approval, and for any
previous period affected by the approval, the volumes on which you report and pay royalty for your
lease must be amended to reflect all volumes produced on or allocated to your lease under the
nonqualifying agreement as modified by BLM or BOEM. Report and pay royalties for your production
using the procedures in §1204.202(b).
(d) If you owe additional royalties based on the retroactive agreement approval and do not pay
your royalty by the date due in §1204.202(b), you will owe late payment interest determined under
§1218.54 from the date your payment was due under §1204.202 (b)(2) until the date ONRR receives
it.
[69 FR 55088, Sept. 13, 2004, as amended at 78 FR 30200, May 22, 2013]

§1204.211 When may ONRR rescind relief for a property?
(a) ONRR may retroactively rescind the relief for your property if ONRR determines that your
property was not eligible for the relief obtained under this subpart because:
(1) You did not submit a notice or request for relief under §1204.205;
(2) You submitted erroneous information in the notice or request for relief you provided to
ONRR under §1204.205 or in your royalty or production reports; or
(3) Your property is no longer eligible for relief because production increased, but you failed to
provide the notice required under §1204.209(b).
(b) ONRR may rescind relief for your property if ONRR decides to take royalty in kind.
§1204.212 What if I took relief for which I was ineligible?
If you took relief under this subpart for a period for which you were not eligible, you:
(a) May owe additional royalties and late payment interest determined under §1218.54 from the
date your additional payments were due until the date ONRR receives them; and

(b) May be subject to civil penalties.
§1204.213 May I obtain relief for a property that benefits from other Federal or State
incentive programs?
You may obtain accounting and auditing relief for production from a marginal property under
this subpart even if the property benefits from other Federal or State production incentive programs.
§1204.214 Is minimum royalty due on a property for which I took relief?
(a) If you took cumulative royalty reports and payment relief on a property under this subpart,
minimum royalty is still due for that property by the date prescribed in your lease and in the amount
prescribed therein.
(b) If you pay minimum royalty on production from a marginal property during a calendar year
for which you are taking cumulative royalty reports and payment relief, and:
(1) The annual payment you owe under this subpart is greater than the minimum royalty you
paid, you must pay the difference between the minimum royalty you paid and your annual payment
due under this subpart; or
(2) The annual payment you owe under this subpart is less than the minimum royalty you paid,
you are not entitled to a credit because you must pay at least the minimum royalty amount on your
lease each year.
§1204.215 Are the information collection requirements in this subpart approved by the
Office of Management and Budget (OMB)?
OMB approved the information collection requirements contained in this subpart under 44
U.S.C. 3501 et seq. ONRR identifies the approved OMB control number in 30 CFR 1210.10.
[78 FR 30200, May 22, 2013]

PART 1206—PRODUCT VALUATION
Contents

Subpart A—General Provisions and Definitions
§1206.10 Information collection.

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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's-length
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 Purpose and scope.
§1206.151 Definitions.
§1206.152 Valuation standards—unprocessed gas.
§1206.153 Valuation standards—processed gas.
§1206.154 Determination of quantities and qualities for computing royalties.
§1206.155 Accounting for comparison.
§1206.156 Transportation allowances—general.
§1206.157 Determination of transportation allowances.
§1206.158 Processing allowances—general.
§1206.159 Determination of processing allowances.
§1206.160 Operating allowances.

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Subpart C—Federal Oil
SOURCE: 82 FR 36953, Aug. 7, 2017, unless otherwise noted.

§1206.100 What is the purpose of this subpart?
(a) This subpart applies to all oil produced from Federal oil and gas leases onshore and on the
Outer Continental Shelf (OCS). It explains how you as a lessee must calculate the value of
production for royalty purposes consistent with the mineral leasing laws, other applicable laws, and
lease terms.
(b) If you are a designee and if you dispose of production on behalf of a lessee, the terms “you”
and “your” in this subpart refer to you and not to the lessee. In this circumstance, you must
determine and report royalty value for the lessee's oil by applying the rules in this subpart to your
disposition of the lessee's oil.
(c) If you are a designee and only report for a lessee, and do not dispose of the lessee's
production, references to “you” and “your” in this subpart refer to the lessee and not the designee. In
this circumstance, you as a designee must determine and report royalty value for the lessee's oil by
applying the rules in this subpart to the lessee's disposition of its oil.
(d) If the regulations in this subpart are inconsistent with:
(1) A Federal statute;
(2) A settlement agreement between the United States and a lessee resulting from
administrative or judicial litigation;
(3) A written agreement between the lessee and the 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?
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.
BOEM means the Bureau of Ocean Energy Management of the Department of the Interior.
BSEE means the Bureau of Safety and Environmental Enforcement 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. BOEM 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 BSEE 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 ONRR-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. P0 therefore is the average of the daily
NYMEX settlement prices for deliveries during March published for each business day between
January 22 and February 20. P1 is the average of the daily NYMEX settlement prices for deliveries
during April published for each business day between January 22 and February 20. P2 is the average
of the daily NYMEX settlement prices for deliveries during May published for each business day
between January 22 and February 20. In this example, assume that P0 = $28.00 per bbl, P1= $27.70
per bbl, and P2 = $27.10 per bbl. In this example (a declining market), Roll = .6667 × ($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. P0 therefore is the average of the daily NYMEX
settlement prices for deliveries during July published for each business day between May 21 and
June 20. P1 is the average of the daily NYMEX settlement prices for deliveries during August
published for each business day between May 21 and June 20. P2 is the average of the daily
NYMEX settlement prices for deliveries during September published for each business day between
May 21 and June 20. In this example, assume that P0 = $28.00 per bbl, P1 = $28.90 per bbl, and P2 =
$29.50 per bbl. In this example (a rising market), Roll = .6667 × ($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]
§1206.102 How do I calculate royalty value for oil that I or my affiliate sell(s) under an arm'slength contract?
(a) The value of oil under this section is the gross proceeds accruing to the seller under the
arm's-length contract, less applicable allowances determined under §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's-length exchange agreements. You may not change your election more often than
once every 2 years.
(2)(i) If you sell or transfer your oil production to your affiliate and that affiliate or another
affiliate then sells the oil under an arm's-length contract, you may use either §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's-length contract.
§1206.103 How do I value oil that is not sold under an arm's-length contract?
This section explains how to value oil that you may not value under §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), (2), or (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 (3) of this section. After you select either paragraph (b)(2) or (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.
§1206.104 What publications are acceptable to ONRR?
(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.
§1206.105 What records must I keep to support my calculations of value under this subpart?
If you determine the value of your oil under this subpart, you must retain all data relevant to the
determination of royalty value.
(a) You must be able to show:

(1) How you calculated the value you reported, including all adjustments for location, quality,
and transportation, and
(2) How you complied with these rules.
(b) Recordkeeping requirements are found at part 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?
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?
(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?
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?
(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 ONRR-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
ONRR-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.
§1206.110 How do I determine a transportation allowance under an arm's-length
transportation contract?
(a) If you or your affiliate incur transportation costs under an arm's-length transportation
contract, you may claim a transportation allowance for the reasonable, actual costs incurred as more
fully explained in paragraph (b) of this section, except as provided in paragraphs (a)(1) and (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
royalty-bearing.
(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 ONRR-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 ONRR-2014.
(f) If your payments for transportation under an arm's-length contract are not on a dollar-perunit 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 ONRR-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.
§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?
(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:
(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 which 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 which you can document.
(f) Overhead directly attributable and allocable to the operation and maintenance of the
transportation system is an allowable expense. State and Federal income taxes and severance
taxes and other fees, including royalties, are not allowable expenses.
(g) To compute depreciation, you may elect to use either a straight-line depreciation method
based on the life of equipment or on the life of the reserves which the transportation system
services, or a unit-of-production method. After you make an election, you may not change methods
without 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 ONRR-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 ONRR-2014.

§1206.112 What adjustments and transportation allowances apply when I value oil
production from my lease using NYMEX prices or ANS spot prices?
This section applies when you use NYMEX prices or ANS spot prices to calculate the value of
production under §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 (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 ONRRapproved 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 BSEE 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 (d)(1) of this section,
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.
§1206.113 How will ONRR identify market centers?
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 the FEDERAL 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?
You or your affiliate must use a separate entry on form ONRR-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?
(a) You or your affiliate must use a separate entry on form ONRR-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?
(a) If you or your affiliate deducts a transportation allowance on form ONRR-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 ONRR-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.
§1206.117 What reporting adjustments must I make for transportation allowances?
(a) If your or your affiliate's actual transportation allowance is less than the amount you claimed
on form ONRR-2014 for each month during the allowance reporting period, you must pay additional
royalties plus interest computed under §1218.54 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
ONRR-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?
(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 BSEE 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 BSEE for offshore leases, adjust the value for those differences in quantity or quality.
(c) Any actual loss that you may incur before the royalty settlement metering or measurement
point is not subject to royalty if BLM or BSEE, 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.
§1206.120 How are operating allowances determined?
BOEM may use an operating allowance for the purpose of computing payment obligations
when specified in the notice of sale and the lease. BOEM will specify the allowance amount or
formula in the notice of sale and in the lease agreement.

Subpart D—Federal Gas
SOURCE: 82 FR 26963, Aug. 7, 2017, unless otherwise noted.

§1206.150 Purpose and scope.
(a) This subpart is applicable to all gas production from Federal oil and gas leases. The
purpose of this subpart is to establish the value of production for royalty purposes consistent with the
mineral leasing laws, other applicable laws and lease terms.
(b) If the regulations in this subpart are inconsistent with:
(1) A Federal statute;
(2) A settlement agreement between the United States and a lessee resulting from
administrative or judicial litigation;
(3) A written agreement between the lessee and the 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.
§1206.151 Definitions.
For purposes of this subpart:
Affiliate means a person who controls, is controlled by, or is under common control with another
person. For purposes of this subpart:
(1) Ownership or common ownership of more than 50 percent of the voting securities, or
instruments of ownership, or other forms of ownership, of another person constitutes control.
Ownership of less than 10 percent constitutes a presumption of noncontrol that 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.
BOEM means the Bureau of Ocean Energy Management of the Department of the Interior.
BSEE means the Bureau of Safety and Environmental Enforcement of the Department of the
Interior.
Compression means the process of raising the pressure of gas.
Condensate means liquid hydrocarbons (normally exceeding 40 degrees of API gravity)
recovered at the surface without resorting to processing. Condensate is the mixture of liquid
hydrocarbons that results from condensation of petroleum hydrocarbons existing initially in a
gaseous phase in an underground reservoir.
Contract means any oral or written agreement, including amendments or revisions thereto,
between two or more persons and enforceable by law that with due consideration creates an
obligation.
Field means a geographic region situated over one or more subsurface oil and gas reservoirs
encompassing at least the outermost boundaries of all oil and gas accumulations known to be within
those reservoirs vertically projected to the land surface. Onshore fields are usually given names and
their official boundaries are often designated by oil and gas regulatory agencies in the respective
States in which the fields are located. Outer Continental Shelf (OCS) fields are named and their
boundaries are designated by BOEM.
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 BSEE 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 ONRR-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 nonarm'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.
§1206.152 Valuation standards—unprocessed gas.
(a)(1) This section applies to the valuation of all gas that is not processed and all gas that is
processed but is sold or otherwise disposed of by the lessee pursuant to an arm's-length contract
prior to processing (including all gas where the lessee's arm's-length contract for the sale of that gas
prior to processing provides for the value to be determined on the basis of a percentage of the
purchaser's proceeds resulting from processing the gas). This section also applies to processed gas
that must be valued prior to processing in accordance with §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 over-delivered volumes under paragraph (c)(2) or (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 (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 onetime notification due no later than the end of the month following the month the lessee first reports
royalties on a form ONRR-2014 using a valuation method authorized by paragraph (c)(2) or (3) of
this section, and each time there is a change in a method under paragraph (c)(2) or (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.
§1206.153 Valuation standards—processed gas.
(a)(1) This section applies to the valuation of all gas that is processed by the lessee and any
other gas production to which this subpart applies and that is not subject to the valuation provisions
of §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 (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 over-delivered volumes under paragraph (c)(2) or (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'slength 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 likequality 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
(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 ONRR-2014 using a valuation method authorized by paragraph (c)(2) or
(3) of this section, and each time there is a change in a method under paragraph (c)(2) or (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.

§1206.154 Determination of quantities and qualities for computing royalties.
(a)(1) Royalties shall be computed on the basis of the quantity and quality of unprocessed gas
at the point of royalty settlement approved by BLM or BSEE 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 or BSEE, 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 or BSEE, 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.
§1206.155 Accounting for comparison.
(a) Except as provided in paragraph (b) of this section, where the lessee (or a person to whom
the lessee has transferred gas pursuant to a non-arm's-length contract or without a contract)
processes the lessee's gas and after processing the gas the residue gas is not sold pursuant to an
arm's-length contract, the value, for royalty purposes, shall be the greater of:
(1) The combined value, for royalty purposes, of the residue gas and gas plant products
resulting from processing the gas determined pursuant to §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.
§1206.156 Transportation allowances—general.
(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 (2) of this section. The lessee must
demonstrate that the transportation costs incurred in excess of the limitations prescribed in
paragraphs (c)(1) and (2) of this section were reasonable, actual, and necessary. An application for
exception (using form ONRR-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 ONRR-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.
§1206.157 Determination of transportation allowances.
(a) Arm's-length transportation contracts. (1)(i) For transportation costs incurred by a lessee
under an arm's-length contract, the transportation allowance shall be the reasonable, actual costs
incurred by the lessee for transporting the unprocessed gas, residue gas and/or gas plant products
under that contract, except as provided in paragraphs (a)(1)(ii) and (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's prior approval is not required before a lessee may deduct costs
incurred under an arm's-length contract. Such allowances shall be subject to the provisions of
paragraph (f) of this section. The lessee must claim a transportation allowance by reporting it as a
separate entry on the form ONRR-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 (a)(2)(i) of this section, 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 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 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 ONRR-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'slength 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 ONRR-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) of this section, 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
ONRR-2014.

(5) You may apply for an exception from the requirement to compute actual costs under
paragraphs (b)(1) through (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'slength 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 volumeweighted average of the rates paid by third parties under arm's-length transportation contracts in the
most recent preceding production month in which the tariff remains in effect and third parties paid
such rates, for up to five successive production months. You must use the non-arm's-length payment
by the lessee to the pipeline if it is less than the volume-weighted average of the rates paid by third
parties under arm's-length contracts.
(c) Reporting requirements—(1) Arm's-length contracts. (i) You must use a separate entry on
form ONRR-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 ONRR-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
ONRR-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 ONRR-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 ONRR-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 ONRR-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 ONRR-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 nonarm'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 ONRR2014 by the amount of that payment. You must modify the form ONRR-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 overdelivered 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.
§1206.158 Processing allowances—general.
(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 66 2⁄3 percent 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 ONRR-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 ONRR-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.
§1206.159 Determination of processing allowances.
(a) Arm's-length processing contracts. (1)(i) For processing costs incurred by a lessee under an
arm's-length contract, the processing allowance shall be the reasonable actual costs incurred by the
lessee for processing the gas under that contract, except as provided in paragraphs (a)(1)(ii) and (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's 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 ONRR-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 ONRR-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 ONRR-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's-length 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 ONRR-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 ONRR-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 ONRR-2014 that
exceeds 66 2⁄3 percent 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 ONRR-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 ONRR-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 ONRR-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 ONRR-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.
§1206.160 Operating allowances.
Notwithstanding any other provisions in these regulations, an operating allowance may be used
for the purpose of computing payment obligations when specified in the notice of sale and the lease.
The allowance amount or formula shall be specified in the notice of sale and in the lease agreement.