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Title 30: Mineral Resources
PART 202—ROYALTIES
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Subpart C—Federal and Indian Oil
§ 202.100 Royalty on oil.
(a) Royalties due on oil production from leases subject to the requirements of this part, including
condensate separated from gas without processing, shall be at the royalty rate established by the terms
of the lease. Royalty shall be paid in value unless MMS requires payment in-kind. When paid in value,
the royalty due shall be the value, for royalty purposes, determined pursuant to part 206 of this title
multiplied by the royalty rate in the lease.
(b)(1) All oil (except oil unavoidably lost or used on, or for the benefit of, the lease, including that oil used
off-lease for the benefit of the lease when such off-lease use is permitted by the MMS or BLM, as
appropriate) produced from a Federal or Indian lease to which this part applies is subject to royalty.
(2) When oil is used on, or for the benefit of, the lease at a production facility handling production from
more than one lease with the approval of the MMS or BLM, as appropriate, or at a production facility
handling unitized or communitized production, only that proportionate share of each lease's production
(actual or allocated) necessary to operate the production facility may be used royalty-free.
(3) Where the terms of any lease are inconsistent with this section, the lease terms shall govern to the
extent of that inconsistency.
(c) If BLM determines that oil was avoidably lost or wasted from an onshore lease, or that oil was
drained from an onshore lease for which compensatory royalty is due, or if MMS determines that oil was
avoidably lost or wasted from an offshore lease, then the value of that oil shall be determined in
accordance with 30 CFR part 206.
(d) If a lessee receives insurance compensation for unavoidably lost oil, royalties are due on the amount
of that compensation. This paragraph shall not apply to compensation through self-insurance.
(e)(1) In those instances where the lessee of any lease committed to a federally approved unitization or
communitization agreement does not actually take the proportionate share of the agreement production
attributable to its lease under the terms of the agreement, the full share of production attributable to the
lease under the terms of the agreement nonetheless is subject to the royalty payment and reporting
requirements of this title. Except as provided in paragraph (e)(2) of this section, the value, for royalty
purposes, of production attributable to unitized or communitized leases will be determined in accordance
with 30 CFR part 206. In applying the requirements of 30 CFR part 206, the circumstances involved in
the actual disposition of the portion of the production to which the lessee was entitled but did not take
shall be considered as controlling in arriving at the value, for royalty purposes, of that portion as though
the person actually selling or disposing of the production were the lessee of the Federal or Indian lease.
(2) If a Federal or Indian lessee takes less than its proportionate share of agreement production, upon
request of the lessee MMS may authorize a royalty valuation method different from that required by
paragraph (e)(1) of this section, but consistent with the purposes of these regulations, for any volumes
not taken by the lessee but for which royalties are due.
(3) For purposes of this subchapter, all persons actually taking volumes in excess of their proportionate
share of production in any month under a unitization or communitization agreement shall be deemed to

have taken ratably from all persons actually taking less than their proportionate share of the agreement
production for that month.
(4) If a lessee takes less than its proportionate share of agreement production for any month but
royalties are paid on the full volume of its proportionate share in accordance with the provisions of this
section, no additional royalty will be owed for that lease for prior periods when the lessee subsequently
takes more than its proportionate share to balance its account or when the lessee is paid a sum of
money by the other agreement participants to balance its account.
(f) For production from Federal and Indian leases which are committed to federally-approved unitization
or communitization agreements, upon request of a lessee MMS may establish the value of production
pursuant to a method other than the method required by the regulations in this title if: (1) The proposed
method for establishing value is consistent with the requirements of the applicable statutes, lease terms,
and agreement terms; (2) persons with an interest in the agreement, including, to the extent practical,
royalty interests, are given notice and an opportunity to comment on the proposed valuation method
before it is authorized; and (3) to the extent practical, persons with an interest in a Federal or Indian
lease committed to the agreement, including royalty interests, must agree to use the proposed method
for valuing production from the agreement for royalty purposes.
[53 FR 1217, Jan. 15, 1988]

§ 202.101 Standards for reporting and paying royalties.
Oil volumes are to be reported in barrels of clean oil of 42 standard U.S. gallons (231 cubic inches each)
at 60 °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]
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Title 30: Mineral Resources
PART 202—ROYALTIES
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Subpart D—Federal Gas
Source: 53 FR 1271, Jan. 15, 1988, unless otherwise noted.
§ 202.150 Royalty on gas.
(a) Royalties due on gas production from leases subject to the requirements of this subpart, except
helium produced from Federal leases, shall be at the rate established by the terms of the lease. Royalty
shall be paid in value unless MMS requires payment in kind. When paid in value, the royalty due shall be
the value, for royalty purposes, determined pursuant to 30 CFR part 206 of this title multiplied by the
royalty rate in the lease.
(b)(1) All gas (except gas unavoidably lost or used on, or for the benefit of, the lease, including that gas
used off-lease for the benefit of the lease when such off-lease use is permitted by the MMS or BLM, as
appropriate) produced from a Federal lease to which this subpart applies is subject to royalty.
(2) When gas is used on, or for the benefit of, the lease at a production facility handling production from
more than one lease with the approval of MMS or BLM, as appropriate, or at a production facility
handling unitized or communitized production, only that proportionate share of each lease's production
(actual or allocated) necessary to operate the production facility may be used royalty free.
(3) Where the terms of any lease are inconsistent with this subpart, the lease terms shall govern to the
extent of that inconsistency.
(c) If BLM determines that gas was avoidably lost or wasted from an onshore lease, or that gas was
drained from an onshore lease for which compensatory royalty is due, or if MMS determines that gas
was avoidably lost or wasted from an OCS lease, then the value of that gas shall be determined in
accordance with 30 CFR part 206.
(d) If a lessee receives insurance compensation for unavoidably lost gas, royalties are due on the
amount of that compensation. This paragraph shall not apply to compensation through self-insurance.
(e)(1) In those instances where the lessee of any lease committed to a Federally approved unitization or
communitization agreement does not actually take the proportionate share of the production attributable
to its Federal lease under the terms of the agreement, the full share of production attributable to the
lease under the terms of the agreement nonetheless is subject to the royalty payment and reporting
requirements of this title. Except as provided in paragraph (e)(2) of this section, the value for royalty
purposes of production attributable to unitized or communitized leases will be determined in accordance
with 30 CFR part 206. In applying the requirements of 30 CFR part 206, the circumstances involved in
the actual disposition of the portion of the production to which the lessee was entitled but did not take
shall be considered as controlling in arriving at the value for royalty purposes of that portion, as if the
person actually selling or disposing of the production were the lessee of the Federal lease.
(2) If a Federal lessee takes less than its proportionate share of agreement production, upon request of
the lessee MMS may authorize a royalty valuation method different from that required by paragraph (e)
(1) of this section, but consistent with the purpose of these regulations, for any volumes not taken by the
lessee but for which royalties are due.

(3) For purposes of this subchapter, all persons actually taking volumes in excess of their proportionate
share of production in any month under a unitization or communitization agreement shall be deemed to
have taken ratably from all persons actually taking less than their proportionate share of the agreement
production for that month.
(4) If a lessee takes less than its proportionate share of agreement production for any month but
royalties are paid on the full volume of its proportionate share in accordance with the provisions of this
section, no additional royalty will be owed for that lease for prior periods at the time the lessee
subsequently takes more than its proportionate share to balance its account or when the lessee is paid a
sum of money by the other agreement participants to balance its account.
(f) For production from Federal leases which are committed to federally-approved unitization or
communitization agreements, upon request of a lessee MMS may establish the value of production
pursuant to a method other than the method required by the regulations in this title if: (1) The proposed
method for establishing value is consistent with the requirements of the applicable statutes, lease terms
and agreement terms; (2) to the extent practical, persons with an interest in the agreement, including
royalty interests, are given notice and an opportunity to comment on the proposed valuation method
before it is authorized; and (3) to the extent practical, persons with an interest in a Federal lease
committed to the agreement, including royalty interests, must agree to use the proposed method for
valuing production from the agreement for royalty purposes.
[53 FR 1271, Jan. 15, 1988, as amended at 64 FR 43513, Aug. 10, 1999]

§ 202.151 Royalty on processed gas.
(a)(1) A royalty, as provided in the lease, shall be paid on the value of:
(i) Any condensate recovered downstream of the point of royalty settlement without resorting to
processing; and
(ii) Residue gas and all gas plant products resulting from processing the gas produced from a lease
subject to this subpart.
(2) MMS shall authorize a processing allowance for the reasonable, actual costs of processing the gas
produced from Federal leases. Processing allowances shall be determined in accordance with 30 CFR
part 206 subpart D for gas production from Federal leases and 30 CFR part 206 subpart E for gas
production from Indian leases.
(b) A reasonable amount of residue gas shall be allowed royalty free for operation of the processing
plant, but no allowance shall be made for boosting residue gas or other expenses incidental to
marketing, except as provided in 30 CFR part 206. In those situations where a processing plant
processes gas from more than one lease, only that proportionate share of each lease's residue gas
necessary for the operation of the processing plant shall be allowed royalty free.
(c) No royalty is due on residue gas, or any gas plant product resulting from processing gas, which is
reinjected into a reservoir within the same lease, unit area, or communitized area, when the reinjection is
included in a plan of development or operations and the plan has received BLM or MMS approval for
onshore or offshore operations, respectively, until such time as they are finally produced from the
reservoir for sale or other disposition off-lease.
[53 FR 1217, Jan. 15, 1988, as amended at 61 FR 5490, Feb. 12, 1996; 64 FR 43513, Aug. 10, 1999]

§ 202.152 Standards for reporting and paying royalties on gas.
(a)(1) If you are responsible for reporting production or royalties, you must:
(i) Report gas volumes and British thermal unit (Btu) heating values, if applicable, under the same
degree of water saturation;
(ii) Report gas volumes in units of 1,000 cubic feet (mcf); and
(iii) Report gas volumes and Btu heating value at a standard pressure base of 14.73 pounds per square
inch absolute (psia) and a standard temperature base of 60 °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]
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e-CFR Data is current as of February 13, 2009
Title 30: Mineral Resources
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PART 204—ALTERNATIVES FOR MARGINAL PROPERTIES

Section Contents

Subpart A—General Provisions
§ 204.1 What is the purpose of this part?
§ 204.2 What definitions apply to this part?
§ 204.3 What alternatives are available for marginal properties?
§ 204.4 What is a marginal property under this part?
§ 204.5 What statutory requirements must I meet to obtain royalty prepayment or accounting
and auditing relief?
§ 204.6 May I appeal if MMS denies my request for prepayment or other relief?
Subpart B—Prepayment of Royalty [Reserved]
Subpart C—Accounting and Auditing Relief
§ 204.200 What is the purpose of this subpart?
§ 204.201 Who may obtain accounting and auditing relief?
§ 204.202 What is the cumulative royalty reports and payments relief option?
§ 204.203 What is the other relief option?
§ 204.204 What accounting and auditing relief will MMS not allow?
§ 204.205 How do I obtain accounting and auditing relief?
§ 204.206 What will MMS do when it receives my request for other relief?
§ 204.207 Who will approve, deny, or modify my request for accounting and auditing relief?
§ 204.208 May a State decide that it will or will not allow one or both of the relief options
under this subpart?
§ 204.209 What if a property ceases to qualify for relief obtained under this subpart?
§ 204.210 What if a property is approved as part of a nonqualifying agreement?
§ 204.211 When may MMS rescind relief for a property?
§ 204.212 What if I took relief for which I was ineligible?
§ 204.213 May I obtain relief for a property that benefits from other Federal or State
incentive programs?
§ 204.214 Is minimum royalty due on a property for which I took relief?
§ 204.215 Are the information collection requirements in this subpart approved by the Office
of Management and Budget (OMB)?

Authority: 30 U.S.C. 1701 et seq.
Source: 69 FR 55088, Sept. 13, 2004, unless otherwise noted.
Subpart A—General Provisions

top

§ 204.1 What is the purpose of this part?
top
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.

§ 204.2 What definitions apply to this part?
top
Agreement means a federally approved communitization agreement or unit participating area.
Barrels of oil equivalent (BOE) means the combined equivalent production of oil and gas stated in
barrels of oil. Each barrel of oil production is equal to one BOE. Also, each 6,000 cubic feet of gas
production is equal to one BOE.
Base period means the 12-month period from July 1 through June 30 immediately preceding the
calendar year for which you take or request marginal property relief. For example, if you request relief for
calendar year 2006, your base period is July 1, 2004, through June 30, 2005.
Combined equivalent production means the total of all oil and gas production for the marginal property,
stated in BOE.
Designee means the person designated by a lessee under 30 CFR 218.52 to make all or part of the
royalty or other payments due on a lease on the lessee's behalf.
Producing wells means only those producing oil or gas wells that contribute to the sum of BOE used in
the calculation under §204.4(c). Producing wells do not include injection or water wells. Wells with
multiple zones commingled downhole are considered as a single well.
Property means a lease, a portion of a lease, or an agreement that may be a marginal property if it
meets the qualification requirements of §204.4.
State concerned (State) means the State that receives a statutorily prescribed portion of the royalties
from a Federal onshore or OCS lease.

§ 204.3 What alternatives are available for marginal properties?
top
If you have production from a marginal property, MMS and the State may allow you the following
options:
(a) Prepay royalty. MMS and the State may allow you to make a lump-sum advance payment of royalties
instead of monthly royalty payments for the remainder of the lease term. See Subpart B for prepayment
of royalty requirements.
(b) Take accounting and auditing relief. MMS and the State may allow various accounting and auditing
relief options to encourage you to continue to produce and develop your marginal property. See Subpart
C for accounting and auditing relief requirements.

§ 204.4 What is a marginal property under this part?
top
(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 . . .
(1) Not in an
The lease must
agreement
qualify as a marginal
property under
paragraph (b) of this
section
(2) Entirely or partly The entire agreement
committed to one
must qualify as a
agreement
marginal property
under paragraph (b)
of this section

(3) Entirely or partly
committed to more
than one agreement

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

And . . .

Agreement production allocable
to your lease may be eligible for
relief under this part. Any
production from your lease that is
not committed to the agreement
also may be eligible for separate
relief under paragraph (a)(4) of
this table.
Each agreement
For any agreement that does
must qualify
qualify, that agreement's
separately as a
production allocable to your lease
marginal property
may be eligible for relief under
under paragraph (b) this part. Any production from
of this section
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.

§ 204.5 What statutory requirements must I meet to obtain royalty prepayment or
accounting and auditing relief?
top
(a) MMS and the State may allow royalty prepayment or accounting and auditing relief for your marginal
property production if MMS and the State jointly determine that the prepayment or accounting and
auditing relief is in the best interests of the Federal Government and the State to:
(1) Promote production;
(2) Reduce the administrative costs of MMS and the State; and

(3) Increase net receipts to the Federal Government and the State.
(b) At any time, if MMS and the State determine that either prepayment or accounting and auditing relief
no longer meets the criteria in paragraph (a) of this section, MMS, with the State's concurrence, may
discontinue any prepayment or accounting and auditing relief options granted for production from any
marginal property.
(1) MMS will provide you written notice of the decision to discontinue relief.
(i) If you took the cumulative reports and payments relief option under §204.202, your relief will terminate
at the end of the calendar year in which you received the notice.
(ii) If you were approved for prepayment relief under subpart B of this part or other relief under §204.203,
MMS's notice will tell you when your relief terminates.
(2) MMS's decision to discontinue relief is not subject to administrative appeal.

§ 204.6 May I appeal if MMS denies my request for prepayment or other relief?
top
If MMS denies your request for prepayment relief under Subpart B of this part or other relief under
§204.203, you may appeal under 30 CFR part 290.

Subpart B—Prepayment of Royalty [Reserved]
top

Subpart C—Accounting and Auditing Relief
top

§ 204.200 What is the purpose of this subpart?
top
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 §204.202) and other accounting and auditing relief appropriate for your property (explained
in §204.203).

§ 204.201 Who may obtain accounting and auditing relief?
top
(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 §204.4;
(2) If you meet any additional requirements for specific types of relief under this subpart; and
(3) Only for the fractional interest in production from the marginal property for which you report and pay
royalty. You may obtain relief even if the other lessees or designees for your lease or agreement do not
request relief.
(b) You may not obtain one or both of the relief options specified in this subpart on any portion of
production from a marginal property if:

(1) The marginal property covers multiple States; and
(2) One of the States determines under §204.208 that it will not allow the relief option you seek.

§ 204.202 What is the cumulative royalty reports and payments relief option?
top
(a) The cumulative royalty reports and payments relief option allows you to submit one royalty report and
payment annually for production during a calendar year. You are eligible for this option only if the total
volume produced from the marginal property (not just your share of the production) is 1,000 BOE or less
during the base period.
(b) To use the cumulative royalty reports and payments relief option, you must do all of the following:
(1) Notify MMS in writing by January 31 of the calendar year for which you begin taking your relief. See
§204.205(a) for what your notification must contain;
(2) Submit your royalty report and payment in accordance with 30 CFR 218.51(g) by the end of February
of the year following the calendar year for which you reported annually, unless you have an estimated
payment on file. If you have an estimated payment on file, you must submit your royalty report and
payment by the end of March of the year following the calendar year for which you reported annually;
(3) Use the sales month prior to the month that you submit your annual report and payment under
paragraph (b)(2) of this section on your Report of Sales and Royalty Remittance, Form MMS–2014, for
the entire previous calendar year's production for which you are paying annually. (For example, for a
report in February use January as your sales month, and for a report in March use February as your
sales month, to report production for the entire previous calendar year for which you are paying
annually);
(4) Report one line of cumulative royalty information on Form MMS–2014 for the calendar year, the
same as if it were a monthly report; and
(5) Report allowances on Form MMS–2014 on the same annual basis as the royalties for your marginal
property production.
(c) If you do not pay your royalty by the date due in paragraph (b) of this section, you will owe late
payment interest determined under 30 CFR 218.54 from the date your payment was due under this
section until the date MMS receives it.
(d) If you take relief you are not qualified for, you may be liable for civil penalties. Also you must:
(1) Pay MMS late payment interest determined under 30 CFR 218.54 from the date your payment was
due until the date MMS receives it; and
(2) Amend your Form MMS–2014 to reflect the required monthly reporting.
(e) If you dispose of your ownership interest in a marginal property for which you have taken relief under
this section (or if you are a designee who reports and pays royalty for a lessee who has disposed of its
ownership interest), you must:
(1) Report and pay royalties for the portion of the calendar year for which you had an ownership interest;
and
(2) Make the report and payment by the end of the month after you dispose of the ownership interest in
the marginal property. If you do not report and pay timely, you will owe interest determined under 30
CFR 218.54 from the date the payment was due under this section.

§ 204.203 What is the other relief option?
top
(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 §204.204 and meets the

statutory requirements of §204.5. Examples of relief options you could request are:
(1) To report and pay royalties using a valuation method other than that required under 30 CFR part 206
that approximates royalties payable under that part 206; and
(2) To reduce your royalty audit burden. However, MMS will not consider any request that eliminates
MMS's or the States' right to audit.
(b) You must request approval from MMS under §204.205(b), and receive approval under §204.206
before taking relief under this option.

§ 204.204 What accounting and auditing relief will MMS not allow?
top
MMS will not approve your request for accounting and auditing relief under this subpart if your request:
(a) Prohibits MMS or the State from conducting any form of audit;
(b) Permanently relieves you from making future royalty reports or payments;
(c) Provides for less frequent royalty reports and payments than annually;
(d) Provides for you to submit royalty reports and payments at separate times;
(e) Impairs MMS's ability to properly or efficiently account for or distribute royalties;
(f) Requests relief for a lease under which the Federal Government takes its royalties in kind;
(g) Alters production reporting requirements;
(h) Alters lease operation or safety requirements;
(i) Conflicts with rent, minimum royalty, or lease requirements; or
(j) Requests relief for production from a marginal property located in whole or in part in a State that has
determined that it will not allow such relief under §204.208.

§ 204.205 How do I obtain accounting and auditing relief?
top
(a) To take cumulative reports and payments relief under §204.202, you must notify MMS in writing by
January 31 of the calendar year for which you begin taking your relief.
(1) Your notification must contain:
(i) Your company name, MMS-assigned payor code, address, phone number, and contact name; and
(ii) The specific MMS lease number and agreement number, if applicable.
(2) You may file a single notification for multiple marginal properties.
(b) To obtain other relief under §204.203, you must file a written request for relief with MMS.
(1) Your request must contain:
(i) Your company name, MMS-assigned payor code, address, phone number, and contact name;
(ii) The MMS lease number and agreement number, if applicable; and

(iii) A complete and detailed description of the specific accounting or auditing relief you seek.
(2) You may file a single request for multiple marginal properties if you are requesting the same relief for
all properties.

§ 204.206 What will MMS do when it receives my request for other relief?
top
When MMS receives your request for other relief under §204.205(b), it will notify you in writing as
follows:
(a) If your request for relief is complete, MMS may either approve, deny, or modify your request in
writing after consultation with any State required under §204.207(b).
(1) If MMS approves your request for relief, MMS will notify you of the effective date of your accounting
or auditing relief and other specifics of the relief approved.
(2) If MMS denies your relief request, MMS will notify you of the reasons for denial and your appeal
rights under §204.6.
(3) If MMS modifies your relief request, MMS will notify you of the modifications.
(i) You have 60 days from your receipt of MMS's notice to either accept or reject any modification(s) in
writing.
(ii) If you reject the modification(s) or fail to respond to MMS's notice, MMS will deny your relief request.
MMS will notify you in writing of the reasons for denial and your appeal rights under §204.6.
(b) If your request for relief is not complete, MMS will notify you in writing that your request is incomplete
and identify any missing information.
(1) You must submit the missing information within 60 days of your receipt of MMS's notice that your
request is incomplete.
(2) After you submit all required information, MMS may approve, deny, or modify your request for relief
under paragraph (a) of this section.
(3) If you do not submit all required information within 60 days of your receipt of MMS's notice that your
request is incomplete, MMS will deny your relief request. MMS will notify you in writing of the reasons for
denial and your appeal rights under §204.6.
(4) You may submit a new request for relief under this subpart at any time after MMS returns your
incomplete request.

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

§ 204.208 May a State decide that it will or will not allow one or both of the relief
options under this subpart?
top

(a) A State may decide in advance that it will or will not allow one or both of the relief options specified in
this subpart for a particular calendar year. If a State decides that it will not consent to one or both of the
relief options, MMS will not grant that type of marginal property relief.
(b) To help States decide whether to allow one or both of the relief options specified in this subpart, for
each calendar year MMS will send States a Report of Marginal Properties by October 1 preceding the
calendar year.
(c) If a State decides under paragraph (a) of this section that it will or will not allow one or both of the
relief options in this subpart during the next calendar year, within 30 days of the State's receipt of the
Report of Marginal Properties under paragraph (b) of this section, the State must:
(1) Notify the Associate Director for Minerals Revenue Management, MMS, in writing, of its intent to
allow or not allow one or both of the relief options under this subpart; and
(2) Specify in its notice of intent to MMS which relief option(s) it will allow or not allow.
(d) If a State decides in advance under paragraph (a) of this section that it will not allow one or both of
the relief options specified in this subpart, it may decide for subsequent calendar years that it will allow
one or both of the relief options in this subpart. If it so decides, within 30 days of the State's receipt of
the Report of Marginal Properties under paragraph (b) of this section, the State must:
(1) Notify the Associate Director for Minerals Revenue Management, MMS, in writing, of its intent to
allow one or both of the relief options allowed under this subpart during the next calendar year; and
(2) Specify in its notice of intent to MMS which relief option(s) it will allow.
(e) If a State does not notify MMS under paragraph (c) or (d) of this section, the State will be deemed to
have decided not to allow either of the relief options under this subpart for the next calendar year.
(f) MMS will publish a notice of the State s intent to allow or not allow certain relief options under this
section in theFederal Registerno later than 30 days before the beginning of the applicable calendar year.

§ 204.209 What if a property ceases to qualify for relief obtained under this subpart?
top
(a) A marginal property must qualify for relief under this subpart for each calendar year based on
production during the base period for that calendar year. The notice or request you provided to MMS
under §204.205 for the first calendar year that the property qualified for relief remains effective for
successive calendar years if the property continues to qualify.
(b) If a property is no longer eligible for relief for any reason during a calendar year other than the reason
under §204.210 or paragraph (c) of this section, the relief for the property terminates as of December 31
of that calendar year. You must notify MMS in writing by December 31 that the relief for the property has
terminated.
(c) If you dispose of your interest in a marginal property during the calendar year, your relief terminates
as of the end of the sales month in which you disposed of the property. Report and pay royalties for your
production using the procedures in §204.202(e).

§ 204.210 What if a property is approved as part of a nonqualifying agreement?
top
If the Bureau of Land Management (BLM) or MMS's Offshore Minerals Management (OMM)
retroactively approves a marginal property that qualified for relief for inclusion as part of an agreement
that does not qualify for relief under this subpart, the property no longer qualifies for relief under this
subpart then:
(a) MMS will not retroactively rescind the marginal property relief for production from your property under
§204.211;
(b) Your marginal property relief terminates as of December 31 of the calendar year that you receive the

BLM or OMM approval of your marginal property as part of a nonqualifying agreement; and
(c) For the calendar year in which you receive the BLM or OMM approval, and for any previous period
affected by the approval, the volumes on which you report and pay royalty for your lease must be
amended to reflect all volumes produced on or allocated to your lease under the nonqualifying
agreement as modified by BLM or OMM. Report and pay royalties for your production using the
procedures in §204.202(b).
(d) If you owe additional royalties based on the retroactive agreement approval and do not pay your
royalty by the date due in §204.202(b), you will owe late payment interest determined under 30 CFR
218.54 from the date your payment was due under §204.202 (b)(2) until the date MMS receives it.

§ 204.211 When may MMS rescind relief for a property?
top
(a) MMS may retroactively rescind the relief for your property if MMS determines that your property was
not eligible for the relief obtained under this subpart because:
(1) You did not submit a notice or request for relief under §204.205;
(2) You submitted erroneous information in the notice or request for relief you provided to MMS under
§204.205 or in your royalty or production reports; or
(3) Your property is no longer eligible for relief because production increased, but you failed to provide
the notice required under §204.209(b).
(b) MMS may rescind relief for your property if MMS decides to take royalty in kind.

§ 204.212 What if I took relief for which I was ineligible?
top
If you took relief under this subpart for a period for which you were not eligible, you:
(a) May owe additional royalties and late payment interest determined under 30 CFR 218.54 from the
date your additional payments were due until the date MMS receives them; and
(b) May be subject to civil penalties.

§ 204.213 May I obtain relief for a property that benefits from other Federal or State
incentive programs?
top
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.

§ 204.214 Is minimum royalty due on a property for which I took relief?
top
(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.

§ 204.215 Are the information collection requirements in this subpart approved by the
Office of Management and Budget (OMB)?
top
OMB has approved the information collection requirements contained in this subpart under 44 U.S.C.
3501 et seq. , and assigned OMB control number 1010–0155. See 30 CFR part 210 for details
concerning your estimated reporting burden and how you may comment on the accuracy of the burden
estimate.
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Home Page > Executive Branch > Code of Federal Regulations > Electronic Code of Federal Regulations

e-CFR Data is current as of February 13, 2009
Title 30: Mineral Resources

PART 206—PRODUCT VALUATION
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Subpart C—Federal Oil
Source: 65 FR 14088, Mar. 15, 2000, unless otherwise noted.
§ 206.100 What is the purpose of this subpart?
(a) This subpart applies to all oil produced from Federal oil and gas leases onshore and on the Outer
Continental Shelf (OCS). It explains how you as a lessee must calculate the value of production for
royalty purposes consistent with the mineral leasing laws, other applicable laws, and lease terms.
(b) If you are a designee and if you dispose of production on behalf of a lessee, the terms “you” and
“your” in this subpart refer to you and not to the lessee. In this circumstance, you must determine and
report royalty value for the lessee's oil by applying the rules in this subpart to your disposition of the
lessee's oil.
(c) If you are a designee and only report for a lessee, and do not dispose of the lessee's production,
references to “you” and “your” in this subpart refer to the lessee and not the designee. In this
circumstance, you as a designee must determine and report royalty value for the lessee's oil by applying
the rules in this subpart to the lessee's disposition of its oil.
(d) If the regulations in this subpart are inconsistent with:
(1) A Federal statute;
(2) A settlement agreement between the United States and a lessee resulting from administrative or
judicial litigation;
(3) A written agreement between the lessee and the MMS Director establishing a method to determine
the value of production from any lease that MMS expects at least would approximate the value
established under this subpart; or
(4) An express provision of an oil and gas lease subject to this subpart, then the statute, settlement
agreement, written agreement, or lease provision will govern to the extent of the inconsistency.
(e) MMS may audit and adjust all royalty payments.

§ 206.101 What definitions apply to this subpart?
The following definitions apply to this subpart:
Affiliate means a person who controls, is controlled by, or is under common control with another person.
For purposes of this subpart:
(1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of
ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10

percent constitutes a presumption of noncontrol that MMS may rebut.
(2) If there is ownership or common ownership of 10 through 50 percent of the voting securities or
instruments of ownership, or other forms of ownership, of another person, MMS will consider the
following factors in determining whether there is control under the circumstances of a particular case:
(i) The extent to which there are common officers or directors;
(ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership: the
percentage of ownership or common ownership, the relative percentage of ownership or common
ownership compared to the percentage(s) of ownership by other persons, whether a person is the
greatest single owner, or whether there is an opposing voting bloc of greater ownership;
(iii) Operation of a lease, plant, or other facility;
(iv) The extent of participation by other owners in operations and day-to-day management of a lease,
plant, or other facility; and
(v) Other evidence of power to exercise control over or common control with another person.
(3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or
marriage, are affiliates.
ANS means Alaska North Slope (ANS).
Area means a geographic region at least as large as the limits of an oil field, in which oil has similar
quality, economic, and legal characteristics.
Arm's-length contract means a contract or agreement between independent persons who are not
affiliates and who have opposing economic interests regarding that contract. To be considered arm's
length for any production month, a contract must satisfy this definition for that month, as well as when
the contract was executed.
Audit means a review, conducted under generally accepted accounting and auditing standards, of
royalty payment compliance activities of lessees, designees or other persons who pay royalties, rents, or
bonuses on Federal leases.
BLM means the Bureau of Land Management of the Department of the Interior.
Condensate means liquid hydrocarbons (normally exceeding 40 degrees of API gravity) recovered at the
surface without processing. Condensate is the mixture of liquid hydrocarbons resulting from
condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground
reservoir.
Contract means any oral or written agreement, including amendments or revisions, between two or more
persons, that is enforceable by law and that with due consideration creates an obligation.
Designee means the person the lessee designates to report and pay the lessee's royalties for a lease.
Exchange agreement means an agreement where one person agrees to deliver oil to another person at
a specified location in exchange for oil deliveries at another location. Exchange agreements may or may
not specify prices for the oil involved. They frequently specify dollar amounts reflecting location, quality,
or other differentials. Exchange agreements include buy/sell agreements, which specify prices to be paid
at each exchange point and may appear to be two separate sales within the same agreement. Examples
of other types of exchange agreements include, but are not limited to, exchanges of produced oil for
specific types of crude oil (e.g., West Texas Intermediate); exchanges of produced oil for other crude oil
at other locations (Location Trades); exchanges of produced oil for other grades of oil (Grade Trades);
and multi-party exchanges.
Field means a geographic region situated over one or more subsurface oil and gas reservoirs and
encompassing at least the outermost boundaries of all oil and gas accumulations known within those
reservoirs, vertically projected to the land surface. State oil and gas regulatory agencies usually name
onshore fields and designate their official boundaries. MMS names and designates boundaries of OCS
fields.
Gathering means the movement of lease production to a central accumulation or treatment point on the

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

Person means any individual, firm, corporation, association, partnership, consortium, or joint venture
(when established as a separate entity).
Prompt month means the nearest month of delivery for which NYMEX futures prices are published
during the trading month.
Quality differential means an amount paid or received under an exchange agreement (whether in money
or in barrels of oil) that results from differences in API gravity, sulfur content, viscosity, metals content,
and other quality factors between oil delivered and oil received in the exchange. A quality differential
may represent all or part of the difference between the price received for oil delivered and the price paid
for oil received under a buy/sell agreement.
Rocky Mountain Region means the States of Colorado, Montana, North Dakota, South Dakota, Utah,
and Wyoming, except for those portions of the San Juan Basin and other oil-producing fields in the “Four
Corners” area that lie within Colorado and Utah.
Roll means an adjustment to the NYMEX price that is calculated as follows:
Roll = .6667 × (P0−P1) + .3333 × (P0−P2), where: P0= the average of the daily NYMEX settlement prices
for deliveries during the prompt month that is the same as the month of production, as published for
each day during the trading month for which the month of production is the prompt month; P1= the
average of the daily NYMEX settlement prices for deliveries during the month following the month of
production, published for each day during the trading month for which the month of production is the
prompt month; and P2= the average of the daily NYMEX settlement prices for deliveries during the
second month following the month of production, as published for each day during the trading month for
which the month of production is the prompt month. Calculate the average of the daily NYMEX
settlement prices using only the days on which such prices are published (excluding weekends and
holidays).
(1) Example 1. Prices in Out Months are Lower Going Forward: The month of production for which you
must determine royalty value is March. March was the prompt month (for year 2003) from January 22
through February 20. April was the first month following the month of production, and May was the
second month following the month of production. P0therefore is the average of the daily NYMEX
settlement prices for deliveries during March published for each business day between January 22 and
February 20. P1is the average of the daily NYMEX settlement prices for deliveries during April published
for each business day between January 22 and February 20. P2is the average of the daily NYMEX
settlement prices for deliveries during May published for each business day between January 22 and
February 20. In this example, assume that P0= $28.00 per bbl, P1= $27.70 per bbl, and P2= $27.10 per
bbl. In this example (a declining market), Roll = .6667 × ($28.00−$27.70) + .3333 × ($28.00−$27.10) =
$.20 + $.30 = $.50. You add this number to the NYMEX price.
(2) Example 2. Prices in Out Months are Higher Going Forward: The month of production for which you
must determine royalty value is July. July 2003 was the prompt month from May 21 through June 20.
August was the first month following the month of production, and September was the second month
following the month of production. P0therefore is the average of the daily NYMEX settlement prices for
deliveries during July published for each business day between May 21 and June 20. P1is the average
of the daily NYMEX settlement prices for deliveries during August published for each business day
between May 21 and June 20. P2is the average of the daily NYMEX settlement prices for deliveries
during September published for each business day between May 21 and June 20. In this example,
assume that P0= $28.00 per bbl, P1= $28.90 per bbl, and P2= $29.50 per bbl. In this example (a rising
market), Roll = .6667 × ($28.00−$28.90) + .3333 × ($28.00−$29.50) = (−$.60) + (−$.50) = −$1.10. You
add this negative number to the NYMEX price (effectively a subtraction from the NYMEX price).
Sale means a contract between two persons where:
(1) The seller unconditionally transfers title to the oil to the buyer and does not retain any related rights
such as the right to buy back similar quantities of oil from the buyer elsewhere;
(2) The buyer pays money or other consideration for the oil; and
(3) The parties' intent is for a sale of the oil to occur.
Spot price means the price under a spot sales contract where:
(1) A seller agrees to sell to a buyer a specified amount of oil at a specified price over a specified period

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

§ 206.102 How do I calculate royalty value for oil that I or my affiliate sell(s) under an
arm's-length contract?
(a) The value of oil under this section is the gross proceeds accruing to the seller under the arm's-length
contract, less applicable allowances determined under §§206.110 or 206.111. This value does not apply
if you exercise an option to use a different value provided in paragraph (d)(1) or (d)(2)(i) of this section,
or if one of the exceptions in paragraph (c) of this section applies. Use this paragraph (a) to value oil
that:
(1) You sell under an arm's-length sales contract; or
(2) You sell or transfer to your affiliate or another person under a non-arm's-length contract and that
affiliate or person, or another affiliate of either of them, then sells the oil under an arm's-length contract,
unless you exercise the option provided in paragraph (d)(2)(i) of this section.
(b) If you have multiple arm's-length contracts to sell oil produced from a lease that is valued under
paragraph (a) of this section, the value of the oil is the volume-weighted average of the values
established under this section for each contract for the sale of oil produced from that lease.
(c) This paragraph contains exceptions to the valuation rule in paragraph (a) of this section. Apply these
exceptions on an individual contract basis.
(1) In conducting reviews and audits, if MMS determines that any arm's-length sales contract does not
reflect the total consideration actually transferred either directly or indirectly from the buyer to the seller,

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

prices or benefits to which the seller is entitled must be in writing and signed by all parties to the arm'slength contract.

§ 206.103 How do I value oil that is not sold under an arm's-length contract?
This section explains how to value oil that you may not value under §206.102 or that you elect under
§206.102(d) to value under this section. First determine whether paragraph (a), (b), or (c) of this section
applies to production from your lease, or whether you may apply paragraph (d) or (e) with MMS
approval.
(a) Production from leases in California or Alaska. Value is the average of the daily mean ANS spot
prices published in any MMS-approved publication during the trading month most concurrent with the
production month. (For example, if the production month is June, compute the average of the daily mean
prices using the daily ANS spot prices published in the MMS-approved publication for all the business
days in June.)
(1) To calculate the daily mean spot price, average the daily high and low prices for the month in the
selected publication.
(2) Use only the days and corresponding spot prices for which such prices are published.
(3) You must adjust the value for applicable location and quality differentials, and you may adjust it for
transportation costs, under §206.112.
(4) After you select an MMS-approved publication, you may not select a different publication more often
than once every 2 years, unless the publication you use is no longer published or MMS revokes its
approval of the publication. If you are required to change publications, you must begin a new 2-year
period.
(b) Production from leases in the Rocky Mountain Region. This paragraph provides methods and options
for valuing your production under different factual situations. You must consistently apply paragraph (b)
(1), (b)(2), or (b)(3) of this section to value all of your production from the same unit, communitization
agreement, or lease (if the lease or a portion of the lease is not part of a unit or communitization
agreement) that you cannot value under §206.102 or that you elect under §206.102(d) to value under
this section.
(1) If you have an MMS-approved tendering program, you must value oil produced from leases in the
area the tendering program covers at the highest winning bid price for tendered volumes.
(i) The minimum requirements for MMS to approve your tendering program are:
(A) You must offer and sell at least 30 percent of your or your affiliates' production from both Federal
and non-Federal leases in the area under your tendering program; and
(B) You must receive at least three bids for the tendered volumes from bidders who do not have their
own tendering programs that cover some or all of the same area.
(ii) If you do not have an MMS-approved tendering program, you may elect to value your oil under either
paragraph (b)(2) or (b)(3) of this section. After you select either paragraph (b)(2) or (b)(3) of this section,
you may not change to the other method more often than once every 2 years, unless the method you
have been using is no longer applicable and you must apply the other paragraph. If you change
methods, you must begin a new 2-year period.
(2) Value is the volume-weighted average of the gross proceeds accruing to the seller under your or
your affiliates' arm's-length contracts for the purchase or sale of production from the field or area during
the production month.
(i) The total volume purchased or sold under those contracts must exceed 50 percent of your and your
affiliates' production from both Federal and non-Federal leases in the same field or area during that
month.
(ii) Before calculating the volume-weighted average, you must normalize the quality of the oil in your or
your affiliates' arm's-length purchases or 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 §206.112.
(4) If you demonstrate to MMS's satisfaction that paragraphs (b)(1) through (b)(3) of this section result in
an unreasonable value for your production as a result of circumstances regarding that production, the
MMS Director may establish an alternative valuation method.
(c) Production from leases not located in California, Alaska, or the Rocky Mountain Region. (1) Value is
the NYMEX price, plus the roll, adjusted for applicable location and quality differentials and
transportation costs under §206.112.
(2) If the MMS Director determines that use of the roll no longer reflects prevailing industry practice in
crude oil sales contracts or that the most common formula used by industry to calculate the roll changes,
MMS may terminate or modify use of the roll under paragraph (c)(1) of this section at the end of each 2year period following July 6, 2004, through notice published in theFederal Registernot later than 60 days
before the end of the 2-year period. MMS will explain the rationale for terminating or modifying the use of
the roll in this notice.
(d) Unreasonable value. If MMS determines that the NYMEX price or ANS spot price does not represent
a reasonable royalty value in any particular case, MMS may establish reasonable royalty value based on
other relevant matters.
(e) Production delivered to your refinery and the NYMEX price or ANS spot price is an unreasonable
value. (1) Instead of valuing your production under paragraph (a), (b), or (c) of this section, you may
apply to the MMS Director to establish a value representing the market at the refinery if:
(i) You transport your oil directly to your or your affiliate's refinery, or exchange your oil for oil delivered
to your or your affiliate's refinery; and
(ii) You must value your oil under this section at the NYMEX price or ANS spot price; and
(iii) You believe that use of the NYMEX price or ANS spot price results in an unreasonable royalty value.
(2) You must provide adequate documentation and evidence demonstrating the market value at the
refinery. That evidence may include, but is not limited to:
(i) Costs of acquiring other crude oil at or for the refinery;
(ii) How adjustments for quality, location, and transportation were factored into the price paid for other
oil;
(iii) Volumes acquired for and refined at the refinery; and
(iv) Any other appropriate evidence or documentation that MMS requires.
(3) If the MMS Director establishes a value representing market value at the refinery, you may not take
an allowance against that value under §206.112(b) unless it is included in the Director's approval.
[65 FR 14088, Mar. 15, 2002, as amended at 67 FR 19111, Apr. 18, 2002; 69 FR 24976, May 5, 2004]

§ 206.104 What publications are acceptable to MMS?
(a) MMS periodically will publish in theFederal Registera list of acceptable publications for the NYMEX
price and ANS spot price based on certain criteria, including, but not limited to:
(1) Publications buyers and sellers frequently use;
(2) Publications frequently mentioned in purchase or sales contracts;
(3) Publications that use adequate survey techniques, including development of estimates based on
daily surveys of buyers and sellers of crude oil, and, for ANS spot prices, buyers and sellers of ANS
crude oil; and
(4) Publications independent from MMS, other lessors, and lessees.

(b) Any publication may petition MMS to be added to the list of acceptable publications.
(c) MMS will specify the tables you must use in the acceptable publications.
(d) MMS may revoke its approval of a particular publication if it determines that the prices or differentials
published in the publication do not accurately represent NYMEX prices or differentials or ANS spot
market prices or differentials.
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24976, May 5, 2004]

§ 206.105 What records must I keep to support my calculations of value under this
subpart?
If you determine the value of your oil under this subpart, you must retain all data relevant to the
determination of royalty value.
(a) You must be able to show:
(1) How you calculated the value you reported, including all adjustments for location, quality, and
transportation, and
(2) How you complied with these rules.
(b) Recordkeeping requirements are found at part 207 of this chapter.
(c) MMS may review and audit your data, and MMS will direct you to use a different value if it determines
that the reported value is inconsistent with the requirements of this subpart.

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

§ 206.107 How do I request a value determination?
(a) You may request a value determination from MMS regarding any Federal lease oil production. Your
request must:
(1) Be in writing;
(2) Identify specifically all leases involved, the record title or operating rights owners of those leases, and
the designees for those leases;
(3) Completely explain all relevant facts. You must inform MMS of any changes to relevant facts that
occur before we respond to your request;
(4) Include copies of all relevant documents;
(5) Provide your analysis of the issue(s), including citations to all relevant precedents (including adverse
precedents); and
(6) Suggest your proposed valuation method.
(b) MMS will reply to requests expeditiously. MMS may either:
(1) Issue a value determination signed by the Assistant Secretary, Land and Minerals Management; or
(2) Issue a value determination by MMS; or

(3) Inform you in writing that MMS will not provide a value determination. Situations in which MMS
typically will not provide any value determination include, but are not limited to:
(i) Requests for guidance on hypothetical situations; and
(ii) Matters that are the subject of pending litigation or administrative appeals.
(c)(1) A value determination signed by the Assistant Secretary, Land and Minerals Management, is
binding on both you and MMS until the Assistant Secretary modifies or rescinds it.
(2) After the Assistant Secretary issues a value determination, you must make any adjustments in
royalty payments that follow from the determination and, if you owe additional royalties, pay late
payment interest under 30 CFR 218.54.
(3) A value determination signed by the Assistant Secretary is the final action of the Department and is
subject to judicial review under 5 U.S.C. 701–706.
(d) A value determination issued by MMS is binding on MMS and delegated States with respect to the
specific situation addressed in the determination unless the MMS (for MMS-issued value determinations)
or the Assistant Secretary modifies or rescinds it.
(1) A value determination by MMS is not an appealable decision or order under 30 CFR part 290 subpart
B.
(2) If you receive an order requiring you to pay royalty on the same basis as the value determination,
you may appeal that order under 30 CFR part 290 subpart B.
(e) In making a value determination, MMS or the Assistant Secretary may use any of the applicable
valuation criteria in this subpart.
(f) A change in an applicable statute or regulation on which any value determination is based takes
precedence over the value determination, regardless of whether the MMS or the Assistant Secretary
modifies or rescinds the value determination.
(g) The MMS or the Assistant Secretary generally will not retroactively modify or rescind a value
determination issued under paragraph (d) of this section, unless:
(1) There was a misstatement or omission of material facts; or
(2) The facts subsequently developed are materially different from the facts on which the guidance was
based.
(h) MMS may make requests and replies under this section available to the public, subject to the
confidentiality requirements under §206.108.

§ 206.108 Does MMS protect information I provide?
Certain information you submit to MMS regarding valuation of oil, including transportation allowances,
may be exempt from disclosure. To the extent applicable laws and regulations permit, MMS will keep
confidential any data you submit that is privileged, confidential, or otherwise exempt from disclosure. All
requests for information must be submitted under the Freedom of Information Act regulations of the
Department of the Interior at 43 CFR part 2.

§ 206.109 When may I take a transportation allowance in determining value?
(a) Transportation allowances permitted when value is based on gross proceeds. MMS will allow a
deduction for the reasonable, actual costs to transport oil from the lease to the point off the lease under
§§206.110 or 206.111, as applicable. This paragraph applies when:
(1) You value oil under §206.102 based on gross proceeds from a sale at a point off the lease, unit, or
communitized area where the oil is produced, and
(2) The movement to the sales point is not gathering.
(b) Transportation allowances and other adjustments that apply when value is based on NYMEX prices

or ANS spot prices. If you value oil using NYMEX prices or ANS spot prices under §206.103, MMS will
allow an adjustment for certain location and quality differentials and certain costs associated with
transporting oil as provided under §206.112.
(c) Limits on transportation allowances. (1) Except as provided in paragraph (c)(2) of this section, your
transportation allowance may not exceed 50 percent of the value of the oil as determined under
§206.102 or §206.103 of this subpart. You may not use transportation costs incurred to move a
particular volume of production to reduce royalties owed on production for which those costs were not
incurred.
(2) You may ask MMS to approve a transportation allowance in excess of the limitation in paragraph (c)
(1) of this section. You must demonstrate that the transportation costs incurred were reasonable, actual,
and necessary. Your application for exception (using Form MMS–4393, Request to Exceed Regulatory
Allowance Limitation) must contain all relevant and supporting documentation necessary for MMS to
make a determination. You may never reduce the royalty value of any production to zero.
(d) Allocation of transportation costs. You must allocate transportation costs among all products
produced and transported as provided in §§206.110 and 206.111. You must express transportation
allowances for oil as dollars per barrel.
(e) Liability for additional payments. If MMS determines that you took an excessive transportation
allowance, then you must pay any additional royalties due, plus interest under 30 CFR 218.54. You also
could be entitled to a credit with interest under applicable rules if you understated your transportation
allowance. If you take a deduction for transportation on Form MMS–2014 by improperly netting the
allowance against the sales value of the oil instead of reporting the allowance as a separate entry, MMS
may assess you an amount under §206.116.
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24976, May 5, 2004]

§ 206.110 How do I determine a transportation allowance under an arm's-length
transportation contract?
(a) If you or your affiliate incur transportation costs under an arm's-length transportation contract, you
may claim a transportation allowance for the reasonable, actual costs incurred as more fully explained in
paragraph (b) of this section, except as provided in paragraphs (a)(1) and (a)(2) of this section and
subject to the limitation in §206.109(c). You must be able to demonstrate that your or your affiliate's
contract is at arm's length. You do not need MMS approval before reporting a transportation allowance
for costs incurred under an arm's-length transportation contract.
(1) If MMS determines that the contract reflects more than the consideration actually transferred either
directly or indirectly from you or your affiliate to the transporter for the transportation, MMS may require
that you calculate the transportation allowance under §206.111.
(2) You must calculate the transportation allowance under §206.111 if MMS determines that the
consideration paid under an arm's-length transportation contract does not reflect the reasonable value of
the transportation due to either:
(i) Misconduct by or between the parties to the arm's-length contract; or
(ii) Breach of your duty to market the oil for the mutual benefit of yourself and the lessor.
(A) MMS will not use this provision to simply substitute its judgment of the reasonable oil transportation
costs incurred by you or your affiliate under an arm's-length transportation contract.
(B) The fact that the cost you or your affiliate incur in an arm's length transaction is higher than other
measures of transportation costs, such as rates paid by others in the field or area, is insufficient to
establish breach of the duty to market unless MMS finds additional evidence that you or your affiliate
acted unreasonably or in bad faith in transporting oil from the lease.
(b) You may deduct any of the following actual costs you (including your affiliates) incur for transporting
oil. You may not use as a deduction any cost that duplicates all or part of any other cost that you use
under this paragraph.
(1) The amount that you pay under your arm's-length transportation contract or tariff.
(2) Fees paid (either in volume or in value) for actual or theoretical line losses.

(3) Fees paid for administration of a quality bank.
(4) The cost of carrying on your books as inventory a volume of oil that the pipeline operator requires
you to maintain, and that you do maintain, in the line as line fill. You must calculate this cost as follows:
(i) Multiply the volume that the pipeline requires you to maintain, and that you do maintain, in the pipeline
by the value of that volume for the current month calculated under §206.102 or §206.103, as applicable;
and
(ii) Multiply the value calculated under paragraph (b)(4)(i) of this section by the monthly rate of return,
calculated by dividing the rate of return specified in §206.111(i)(2) by 12.
(5) Fees paid to a terminal operator for loading and unloading of crude oil into or from a vessel, vehicle,
pipeline, or other conveyance.
(6) Fees paid for short-term storage (30 days or less) incidental to transportation as required by a
transporter.
(7) Fees paid to pump oil to another carrier's system or vehicles as required under a tariff.
(8) Transfer fees paid to a hub operator associated with physical movement of crude oil through the hub
when you do not sell the oil at the hub. These fees do not include title transfer fees.
(9) Payments for a volumetric deduction to cover shrinkage when high-gravity petroleum (generally in
excess of 51 degrees API) is mixed with lower-gravity crude oil for transportation.
(10) Costs of securing a letter of credit, or other surety, that the pipeline requires you as a shipper to
maintain.
(c) You may not deduct any costs that are not actual costs of transporting oil, including but not limited to
the following:
(1) Fees paid for long-term storage (more than 30 days).
(2) Administrative, handling, and accounting fees associated with terminalling.
(3) Title and terminal transfer fees.
(4) Fees paid to track and match receipts and deliveries at a market center or to avoid paying title
transfer fees.
(5) Fees paid to brokers.
(6) Fees paid to a scheduling service provider.
(7) Internal costs, including salaries and related costs, rent/space costs, office equipment costs, legal
fees, and other costs to schedule, nominate, and account for sale or movement of production.
(8) Gauging fees.
(d) If your arm's-length transportation contract includes more than one liquid product, and the
transportation costs attributable to each product cannot be determined from the contract, then you must
allocate the total transportation costs to each of the liquid products transported.
(1) Your allocation must use the same proportion as the ratio of the volume of each product (excluding
waste products with no value) to the volume of all liquid products (excluding waste products with no
value).
(2) You may not claim an allowance for the costs of transporting lease production that is not royaltybearing.
(3) You may propose to MMS a cost allocation method on the basis of the values of the products
transported. MMS will approve the method unless it is not consistent with the purposes of the regulations
in this subpart.

(e) If your arm's-length transportation contract includes both gaseous and liquid products, and the
transportation costs attributable to each product cannot be determined from the contract, then you must
propose an allocation procedure to MMS.
(1) You may use your proposed procedure to calculate a transportation allowance until MMS accepts or
rejects your cost allocation. If MMS rejects your cost allocation, you must amend your Form MMS–2014
for the months that you used the rejected method and pay any additional royalty and interest due.
(2) You must submit your initial proposal, including all available data, within 3 months after first claiming
the allocated deductions on Form MMS–2014.
(f) If your payments for transportation under an arm's-length contract are not on a dollar-per-unit basis,
you must convert whatever consideration is paid to a dollar-value equivalent.
(g) If your arm's-length sales contract includes a provision reducing the contract price by a transportation
factor, do not separately report the transportation factor as a transportation allowance on Form MMS–
2014.
(1) You may use the transportation factor in determining your gross proceeds for the sale of the product.
(2) You must obtain MMS approval before claiming a transportation factor in excess of 50 percent of the
base price of the product.
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24976, May 5, 2004]

§ 206.111 How do I determine a transportation allowance if I do not have an arm'slength 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 §206.102 or §206.103, as
applicable; and
(B) Multiply the value calculated under paragraph (b)(6)(ii)(A) of this section by the monthly rate of
return, calculated by dividing the rate of return specified in §206.111(i)(2) by 12.
(iii) Fees paid to a non-affiliated terminal operator for loading and unloading of crude oil into or from a
vessel, vehicle, pipeline, or other conveyance.

(iv) Transfer fees paid to a hub operator associated with physical movement of crude oil through the hub
when you do not sell the oil at the hub. These fees do not include title transfer fees.
(v) A volumetric deduction to cover shrinkage when high-gravity petroleum (generally in excess of 51
degrees API) is mixed with lower-gravity crude oil for transportation.
(vi) Fees paid to a non-affiliated quality bank administrator for administration of a quality bank.
(7) You may not deduct any costs that are not actual costs of transporting oil, including but not limited to
the following:
(i) Fees paid for long-term storage (more than 30 days).
(ii) Administrative, handling, and accounting fees associated with terminalling.
(iii) Title and terminal transfer fees.
(iv) Fees paid to track and match receipts and deliveries at a market center or to avoid paying title
transfer fees.
(v) Fees paid to brokers.
(vi) Fees paid to a scheduling service provider.
(vii) Internal costs, including salaries and related costs, rent/space costs, office equipment costs, legal
fees, and other costs to schedule, nominate, and account for sale or movement of production.
(viii) Theoretical line losses.
(ix) Gauging fees.
(c) Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery
and installation of capital equipment) which are an integral part of the transportation system.
(d) Allowable operating expenses include:
(i) Operations supervision and engineering;
(ii) Operations labor;
(iii) Fuel;
(iv) Utilities;
(v) Materials;
(vi) Ad valorem property taxes;
(vii) Rent;
(viii) Supplies; and
(ix) Any other directly allocable and attributable operating expense which you can document.
(e) Allowable maintenance expenses include:
(i) Maintenance of the transportation system;
(ii) Maintenance of equipment;
(iii) Maintenance labor; and

(iv) Other directly allocable and attributable maintenance expenses which you can document.
(f) Overhead directly attributable and allocable to the operation and maintenance of the transportation
system is an allowable expense. State and Federal income taxes and severance taxes and other fees,
including royalties, are not allowable expenses.
(g) To compute depreciation, you may elect to use either a straight-line depreciation method based on
the life of equipment or on the life of the reserves which the transportation system services, or a unit-ofproduction method. After you make an election, you may not change methods without MMS approval.
You may not depreciate equipment below a reasonable salvage value.
(h) This paragraph describes the basis for your depreciation schedule.
(1) If you or your affiliate own a transportation system on June 1, 2000, you must base your depreciation
schedule used in calculating actual transportation costs for production after June 1, 2000, on your total
capital investment in the system (including your original purchase price or construction cost and
subsequent reinvestment).
(2) If you or your affiliate purchased the transportation system at arm's length before June 1, 2000, you
must incorporate depreciation on the schedule based on your purchase price (and subsequent
reinvestment) into your transportation allowance calculations for production after June 1, 2000,
beginning at the point on the depreciation schedule corresponding to that date. You must prorate your
depreciation for calendar year 2000 by claiming part-year depreciation for the period from June 1, 2000
until December 31, 2000. You may not adjust your transportation costs for production before June 1,
2000, using the depreciation schedule based on your purchase price.
(3) If you are the original owner of the transportation system on June 1, 2000, or if you purchased your
transportation system before March 1, 1988, you must continue to use your existing depreciation
schedule in calculating actual transportation costs for production in periods after June 1, 2000.
(4) If you or your affiliate purchase a transportation system at arm's length from the original owner after
June 1, 2000, you must base your depreciation schedule used in calculating actual transportation costs
on your total capital investment in the system (including your original purchase price and subsequent
reinvestment). You must prorate your depreciation for the year in which you or your affiliate purchased
the system to reflect the portion of that year for which you or your affiliate own the system.
(5) If you or your affiliate purchase a transportation system at arm's length after June 1, 2000, from
anyone other than the original owner, you must assume the depreciation schedule of the person from
whom you bought the system. Include in the depreciation schedule any subsequent reinvestment.
(i)(1) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated
capital balance as of the beginning of the period for which you are calculating the transportation
allowance by the rate of return provided in paragraph (i)(2) of this section.
(2) The rate of return is 1.3 times the industrial bond yield index for Standard & Poor's BBB bond rating.
Use the monthly average rate published in “Standard & Poor's Bond Guide” for the first month of the
reporting period for which the allowance applies. Calculate the rate at the beginning of each subsequent
transportation allowance reporting period.
(j)(1) After a transportation system has been depreciated at or below a value equal to ten percent of your
total capital investment, you may continue to include in the allowance calculation a cost equal to ten
percent of your total capital investment in the transportation system multiplied by a rate of return under
paragraph (i)(2) of this section.
(2) You may apply this paragraph to a transportation system that before June 1, 2000, was depreciated
at or below a value equal to ten percent of your total capital investment.
(k) Calculate the deduction for transportation costs based on your or your affiliate's cost of transporting
each product through each individual transportation system. Where more than one liquid product is
transported, allocate costs consistently and equitably to each of the liquid products transported. Your
allocation must use the same proportion as the ratio of the volume of each liquid product (excluding
waste products with no value) to the volume of all liquid products (excluding waste products with no
value).
(1) You may not take an allowance for transporting lease production that is not royalty-bearing.
(2) You may propose to MMS a cost allocation method on the basis of the values of the products

transported. MMS will approve the method if it is consistent with the purposes of the regulations in this
subpart.
(l)(1) Where you transport both gaseous and liquid products through the same transportation system,
you must propose a cost allocation procedure to MMS.
(2) You may use your proposed procedure to calculate a transportation allowance until MMS accepts or
rejects your cost allocation. If MMS rejects your cost allocation, you must amend your Form MMS–2014
for the months that you used the rejected method and pay any additional royalty and interest due.
(3) You must submit your initial proposal, including all available data, within 3 months after first claiming
the allocated deductions on Form MMS–2014.
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24977, May 5, 2004]

§ 206.112 What adjustments and transportation allowances apply when I value oil
production from my lease using NYMEX prices or ANS spot prices?
This section applies when you use NYMEX prices or ANS spot prices to calculate the value of
production under §206.103. As specified in this section, adjust the NYMEX price to reflect the difference
in value between your lease and Cushing, Oklahoma, or adjust the ANS spot price to reflect the
difference in value between your lease and the appropriate MMS-recognized market center at which the
ANS spot price is published (for example, Long Beach, California, or San Francisco, California).
Paragraph (a) of this section explains how you adjust the value between the lease and the market
center, and paragraph (b) of this section explains how you adjust the value between the market center
and Cushing when you use NYMEX prices. Paragraph (c) of this section explains how adjustments may
be made for quality differentials that are not accounted for through exchange agreements. Paragraph (d)
of this section gives some examples. References in this section to “you” include your affiliates as
applicable.
(a) To adjust the value between the lease and the market center:
(1)(i) For oil that you exchange at arm's length between your lease and the market center (or between
any intermediate points between those locations), you must calculate a lease-to-market center
differential by the applicable location and quality differentials derived from your arm's-length exchange
agreement applicable to production during the production month.
(ii) For oil that you exchange between your lease and the market center (or between any intermediate
points between those locations) under an exchange agreement that is not at arm's length, you must
obtain approval from MMS for a location and quality differential. Until you obtain such approval, you may
use the location and quality differential derived from that exchange agreement applicable to production
during the production month. If MMS prescribes a different differential, you must apply MMS's differential
to all periods for which you used your proposed differential. You must pay any additional royalties owed
resulting from using MMS's differential plus late payment interest from the original royalty due date, or
you may report a credit for any overpaid royalties plus interest under 30 U.S.C. 1721(h).
(2) For oil that you transport between your lease and the market center (or between any intermediate
points between those locations), you may take an allowance for the cost of transporting that oil between
the relevant points as determined under §206.110 or §206.111, as applicable.
(3) If you transport or exchange at arm's length (or both transport and exchange) at least 20 percent, but
not all, of your oil produced from the lease to a market center, determine the adjustment between the
lease and the market center for the oil that is not transported or exchanged (or both transported and
exchanged) to or through a market center as follows:
(i) Determine the volume-weighted average of the lease-to-market center adjustment calculated under
paragraphs (a)(1) and (a)(2) of this section for the oil that you do transport or exchange (or both
transport and exchange) from your lease to a market center.
(ii) Use that volume-weighted average lease-to-market center adjustment as the adjustment for the oil
that you do not transport or exchange (or both transport and exchange) from your lease to a market
center.
(4) If you transport or exchange (or both transport and exchange) less than 20 percent of the crude oil
produced from your lease between the lease and a market center, you must propose to MMS an
adjustment between the lease and the market center for the portion of the oil that you do not transport or
exchange (or both transport and exchange) to a market center. Until you obtain such approval, you may
use your proposed adjustment. If MMS prescribes a different adjustment, you must apply MMS's

adjustment to all periods for which you used your proposed adjustment. You must pay any additional
royalties owed resulting from using MMS's adjustment plus late payment interest from the original royalty
due date, or you may report a credit for any overpaid royalties plus interest under 30 U.S.C. 1721(h).
(5) You may not both take a transportation allowance and use a location and quality adjustment or
exchange differential for the same oil between the same points.
(b) For oil that you value using NYMEX prices, adjust the value between the market center and Cushing,
Oklahoma, as follows:
(1) If you have arm's-length exchange agreements between the market center and Cushing under which
you exchange to Cushing at least 20 percent of all the oil you own at the market center during the
production month, you must use the volume-weighted average of the location and quality differentials
from those agreements as the adjustment between the market center and Cushing for all the oil that you
produce from the leases during that production month for which that market center is used.
(2) If paragraph (b)(1) of this section does not apply, you must use the WTI differential published in an
MMS-approved publication for the market center nearest your lease, for crude oil most similar in quality
to your production, as the adjustment between the market center and Cushing. (For example, for light
sweet crude oil produced offshore of Louisiana, use the WTI differential for Light Louisiana Sweet crude
oil at St. James, Louisiana.) After you select an MMS-approved publication, you may not select a
different publication more often than once every 2 years, unless the publication you use is no longer
published or MMS revokes its approval of the publication. If you are required to change publications, you
must begin a new 2-year period.
(3) If neither paragraph (b)(1) nor (b)(2) of this section applies, you may propose an alternative
differential to MMS. Until you obtain such approval, you may use your proposed differential. If MMS
prescribes a different differential, you must apply MMS's differential to all periods for which you used
your proposed differential. You must pay any additional royalties owed resulting from using MMS's
differential plus late payment interest from the original royalty due date, or you may report a credit for
any overpaid royalties plus interest under 30 U.S.C. 1721(h).
(c)(1) If you adjust for location and quality differentials or for transportation costs under paragraphs (a)
and (b) of this section, also adjust the NYMEX price or ANS spot price for quality based on premiums or
penalties determined by pipeline quality bank specifications at intermediate commingling points or at the
market center if those points are downstream of the royalty measurement point approved by MMS or
BLM, as applicable. Make this adjustment only if and to the extent that such adjustments were not
already included in the location and quality differentials determined from your arm's-length exchange
agreements.
(2) If the quality of your oil as adjusted is still different from the quality of the representative crude oil at
the market center after making the quality adjustments described in paragraphs (a), (b) and (c)(1) of this
section, you may make further gravity adjustments using posted price gravity tables. If quality bank
adjustments do not incorporate or provide for adjustments for sulfur content, you may make sulfur
adjustments, based on the quality of the representative crude oil at the market center, of 5.0 cents per
one-tenth percent difference in sulfur content, unless MMS approves a higher adjustment.
(d) The examples in this paragraph illustrate how to apply the requirement of this section.
(1) Example. Assume that a Federal lessee produces crude oil from a lease near Artesia, New Mexico.
Further, assume that the lessee transports the oil to Roswell, New Mexico, and then exchanges the oil to
Midland, Texas. Assume the lessee refines the oil received in exchange at Midland. Assume that the
NYMEX price is $30.00/bbl, adjusted for the roll; that the WTI differential (Cushing to Midland) is
−$.10/bbl; that the lessee's exchange agreement between Roswell and Midland results in a location and
quality differential of −$.08/bbl; and that the lessee's actual cost of transporting the oil from Artesia to
Roswell is $.40/bbl. In this example, the royalty value of the oil is $30.00−$.10−$.08—$.40 = $29.42/bbl.
(2) Example. Assume the same facts as in the example in paragraph (1), except that the lessee
transports and exchanges to Midland 40 percent of the production from the lease near Artesia, and
transports the remaining 60 percent directly to its own refinery in Ohio. In this example, the 40 percent of
the production would be valued at $29.42/bbl, as explained in the previous example. In this example, the
other 60 percent also would be valued at $29.42/bbl.
(3) Example. Assume that a Federal lessee produces crude oil from a lease near Bakersfield, California.
Further, assume that the lessee transports the oil to Hynes Station, and then exchanges the oil to
Cushing which it further exchanges with oil it refines. Assume that the ANS spot price is $20.00/bbl, and
that the lessee's actual cost of transporting the oil from Bakersfield to Hynes Station is $.28/bbl. The
lessee must request approval from MMS for a location and quality adjustment between Hynes Station
and Long Beach. For example, the lessee likely would propose using the tariff on Line 63 from Hynes

Station to Long Beach as the adjustment between those points. Assume that adjustment to be $.72,
including the sulfur and gravity bank adjustments, and that MMS approves the lessee's request. In this
example, the preliminary (because the location and quality adjustment is subject to MMS review) royalty
value of the oil is $20.00−$.72−$.28 = $19.00/bbl. The fact that oil was exchanged to Cushing does not
change use of ANS spot prices for royalty valuation.
[69 FR 24978, May 5, 2004]

§ 206.113 How will MMS identify market centers?
MMS periodically will publish in theFederal Registera list of market centers. MMS will monitor market
activity and, if necessary, add to or modify the list of market centers and will publish such modifications
in theFederal Register.MMS will consider the following factors and conditions in specifying market
centers:
(a) Points where MMS-approved publications publish prices useful for index purposes;
(b) Markets served;
(c) Input from industry and others knowledgeable in crude oil marketing and transportation;
(d) Simplification; and
(e) Other relevant matters.

§ 206.114 What are my reporting requirements under an arm's-length transportation
contract?
You or your affiliate must use a separate entry on Form MMS–2014 to notify MMS of an allowance
based on transportation costs you or your affiliate incur. MMS may require you or your affiliate to submit
arm's-length transportation contracts, production agreements, operating agreements, and related
documents. Recordkeeping requirements are found at part 207 of this chapter.

§ 206.115 What are my reporting requirements under a non-arm's-length
transportation arrangement?
(a) You or your affiliate must use a separate entry on Form MMS–2014 to notify MMS of an allowance
based on transportation costs you or your affiliate incur.
(b) For new transportation facilities or arrangements, base your initial deduction on estimates of
allowable oil transportation costs for the applicable period. Use the most recently available operations
data for the transportation system or, if such data are not available, use estimates based on data for
similar transportation systems. Section 206.117 will apply when you amend your report based on your
actual costs.
(c) MMS may require you or your affiliate to submit all data used to calculate the allowance deduction.
Recordkeeping requirements are found at part 207 of this chapter.

§ 206.116 What interest applies if I improperly report a transportation allowance?
(a) If you or your affiliate deducts a transportation allowance on Form MMS–2014 that exceeds 50
percent of the value of the oil transported without obtaining MMS's prior approval under §206.109, you
must pay interest on the excess allowance amount taken from the date that amount is taken to the date
you or your affiliate files an exception request that MMS approves. If you do not file an exception
request, or if MMS does not approve your request, you must pay interest on the excess allowance
amount taken from the date that amount is taken until the date you pay the additional royalties owed.
(b) If you or your affiliate takes a deduction for transportation on Form MMS–2014 by improperly netting
an allowance against the oil instead of reporting the allowance as a separate entry, MMS may assess a
civil penalty under 30 CFR part 241.
[73 FR 15890, Mar. 26, 2008]

§ 206.117 What reporting adjustments must I make for transportation allowances?

(a) If your or your affiliate's actual transportation allowance is less than the amount you claimed on Form
MMS–2014 for each month during the allowance reporting period, you must pay additional royalties plus
interest computed under 30 CFR 218.54 from the date you took the deduction to the date you repay the
difference.
(b) If the actual transportation allowance is greater than the amount you claimed on Form MMS–2014 for
any month during the allowance form reporting period, you are entitled to a credit plus interest under
applicable rules.

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

§ 206.120 How are operating allowances determined?
MMS may use an operating allowance for the purpose of computing payment obligations when specified
in the notice of sale and the lease. MMS will specify the allowance amount or formula in the notice of
sale and in the lease agreement.
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e-CFR Data is current as of February 13, 2009
Title 30: Mineral Resources
PART 206—PRODUCT VALUATION
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Subpart D—Federal Gas
Source: 53 FR 1272, Jan. 15, 1988, unless otherwise noted.
§ 206.150 Purpose and scope.
(a) This subpart is applicable to all gas production from Federal oil and gas leases. The purpose of this
subpart is to establish the value of production for royalty purposes consistent with the mineral leasing
laws, other applicable laws and lease terms.
(b) If the regulations in this subpart are inconsistent with:
(1) A Federal statute;
(2) A settlement agreement between the United States and a lessee resulting from administrative or
judicial litigation;
(3) A written agreement between the lessee and the MMS Director establishing a method to determine
the value of production from any lease that MMS expects at least would approximate the value
established under this subpart; or
(4) An express provision of an oil and gas lease subject to this subpart; then the statute, settlement
agreement, written agreement, or lease provision will govern to the extent of the inconsistency.
(c) All royalty payments made to MMS are subject to audit and adjustment.
(d) The regulations in this subpart are intended to ensure that the administration of oil and gas leases is
discharged in accordance with the requirements of the governing mineral leasing laws and lease terms.
[61 FR 5464, Feb. 12, 1996, as amended at 70 FR 11877, Mar. 10, 2005]

§ 206.151 Definitions.
For purposes of this subpart:
Affiliate means a person who controls, is controlled by, or is under common control with another person.
For purposes of this subpart:
(1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of
ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10
percent constitutes a presumption of noncontrol that MMS may rebut.
(2) If there is ownership or common ownership of 10 through 50 percent of the voting securities or
instruments of ownership, or other forms of ownership, of another person, MMS will consider the
following factors in determining whether there is control under the circumstances of a particular case:

(i) The extent to which there are common officers or directors;
(ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership: The
percentage of ownership or common ownership, the relative percentage of ownership or common
ownership compared to the percentage(s) of ownership by other persons, whether a person is the
greatest single owner, or whether there is an opposing voting bloc of greater ownership;
(iii) Operation of a lease, plant, pipeline, or other facility;
(iv) The extent of participation by other owners in operations and day-to-day management of a lease,
plant, pipeline, or other facility; and
(v) Other evidence of power to exercise control over or common control with another person.
(3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or
marriage, are affiliates.
Allowance means a deduction in determining value for royalty purposes. Processing allowance means
an allowance for the reasonable, actual costs of processing gas determined under this subpart.
Transportation allowance means an allowance for the reasonable, actual costs of moving unprocessed
gas, residue gas, or gas plant products to a point of sale or delivery off the lease, unit area, or
communitized area, or away from a processing plant. The transportation allowance does not include
gathering costs.
Area means a geographic region at least as large as the defined limits of an oil and/or gas field, in which
oil and/or gas lease products have similar quality, economic, and legal characteristics.
Arm's-length contract means a contract or agreement between independent persons who are not
affiliates and who have opposing economic interests regarding that contract. To be considered arm's
length for any production month, a contract must satisfy this definition for that month, as well as when
the contract was executed.
Audit means a review, conducted in accordance with generally accepted accounting and auditing
standards, of royalty payment compliance activities of lessees or other interest holders who pay
royalties, rents, or bonuses on Federal leases.
BLM means the Bureau of Land Management of the Department of the Interior.
Compression means the process of raising the pressure of gas.
Condensate means liquid hydrocarbons (normally exceeding 40 degrees of API gravity) recovered at the
surface without resorting to processing. Condensate is the mixture of liquid hydrocarbons that results
from condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground
reservoir.
Contract means any oral or written agreement, including amendments or revisions thereto, between two
or more persons and enforceable by law that with due consideration creates an obligation.
Field means a geographic region situated over one or more subsurface oil and gas reservoirs
encompassing at least the outermost boundaries of all oil and gas accumulations known to be within
those reservoirs vertically projected to the land surface. Onshore fields are usually given names and
their official boundaries are often designated by oil and gas regulatory agencies in the respective States
in which the fields are located. Outer Continental Shelf (OCS) fields are named and their boundaries are
designated by MMS.
Gas means any fluid, either combustible or noncombustible, hydrocarbon or nonhydrocarbon, which is
extracted from a reservoir and which has neither independent shape nor volume, but tends to expand
indefinitely. It is a substance that exists in a gaseous or rarefied state under standard temperature and
pressure conditions.
Gas plant products means separate marketable elements, compounds, or mixtures, whether in liquid,
gaseous, or solid form, resulting from processing gas, excluding residue gas.
Gathering means the movement of lease production to a central accumulation and/or treatment point on
the lease, unit or communitized area, or to a central accumulation or treatment point off the lease, unit or
communitized area as approved by BLM or MMS OCS operations personnel for onshore and OCS

leases, respectively.
Gross proceeds (for royalty payment purposes) means the total monies and other consideration
accruing to an oil and gas lessee for the disposition of the gas, residue gas, and gas plant products
produced. Gross proceeds includes, but is not limited to, payments to the lessee for certain services
such as dehydration, measurement, and/or gathering to the extent that the lessee is obligated to perform
them at no cost to the Federal Government. Tax reimbursements are part of the gross proceeds
accruing to a lessee even though the Federal royalty interest may be exempt from taxation. Monies and
other consideration, including the forms of consideration identified in this paragraph, to which a lessee is
contractually or legally entitled but which it does not seek to collect through reasonable efforts are also
part of gross proceeds.
Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or
approved by the United States under a mineral leasing law that authorizes exploration for, development
or extraction of, or removal of lease products—or the land area covered by that authorization, whichever
is required by the context.
Lease products means any leased minerals attributable to, originating from, or allocated to Outer
Continental Shelf or onshore Federal leases.
Lessee means any person to whom the United States issues a lease, and any person who has been
assigned an obligation to make royalty or other payments required by the lease. This includes any
person who has an interest in a lease as well as an operator or payor who has no interest in the lease
but who has assumed the royalty payment responsibility.
Like-quality lease products means lease products which have similar chemical, physical, and legal
characteristics.
Marketable condition means lease products which are sufficiently free from impurities and otherwise in a
condition that they will be accepted by a purchaser under a sales contract typical for the field or area.
Marketing affiliate means an affiliate of the lessee whose function is to acquire only the lessee's
production and to market that production.
Minimum royalty means that minimum amount of annual royalty that the lessee must pay as specified in
the lease or in applicable leasing regulations.
Net-back method (or work-back method) means a method for calculating market value of gas at the
lease. Under this method, costs of transportation, processing, or manufacturing are deducted from the
proceeds received for the gas, residue gas or gas plant products, and any extracted, processed, or
manufactured products, or from the value of the gas, residue gas or gas plant products, and any
extracted, processed, or manufactured products, at the first point at which reasonable values for any
such products may be determined by a sale pursuant to an arm's-length contract or comparison to other
sales of such products, to ascertain value at the lease.
Net output means the quantity of residue gas and each gas plant product that a processing plant
produces.
Net profit share (for applicable Federal leases) means the specified share of the net profit from
production of oil and gas as provided in the agreement.
Netting means the deduction of an allowance from the sales value by reporting a net sales value,
instead of correctly reporting the deduction as a separate entry on Form MMS–2014.
Outer Continental Shelf (OCS) means all submerged lands lying seaward and outside of the area of land
beneath navigable waters as defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of
which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and
control.
Person means any individual, firm, corporation, association, partnership, consortium, or joint venture
(when established as a separate entity).
Posted price means the price, net of all adjustments for quality and location, specified in publicly
available price bulletins or other price notices available as part of normal business operations for
quantities of unprocessed gas, residue gas, or gas plant products in marketable condition.
Processing means any process designed to remove elements or compounds (hydrocarbon and

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

§ 206.152 Valuation standards—unprocessed gas.
(a)(1) This section applies to the valuation of all gas that is not processed and all gas that is processed
but is sold or otherwise disposed of by the lessee pursuant to an arm's-length contract prior to
processing (including all gas where the lessee's arm's-length contract for the sale of that gas prior to
processing provides for the value to be determined on the basis of a percentage of the purchaser's
proceeds resulting from processing the gas). This section also applies to processed gas that must be
valued prior to processing in accordance with §206.155 of this part. Where the lessee's contract includes
a reservation of the right to process the gas and the lessee exercises that right, §206.153 of this part
shall apply instead of this section.
(2) The value of production, for royalty purposes, of gas subject to this subpart shall be the value of gas
determined under this section less applicable allowances.
(b)(1)(i) The value of gas sold under an arm's-length contract is the gross proceeds accruing to the
lessee except as provided in paragraphs (b)(1)(ii), (iii), and (iv) of this section. The lessee shall have the
burden of demonstrating that its contract is arm's-length. The value which the lessee reports, for royalty
purposes, is subject to monitoring, review, and audit. For purposes of this section, gas which is sold or
otherwise transferred to the lessee's marketing affiliate and then sold by the marketing affiliate pursuant
to an arm's-length contract shall be valued in accordance with this paragraph based upon the sale by
the marketing affiliate. Also, where the lessee's arm's-length contract for the sale of gas prior to
processing provides for the value to be determined based upon a percentage of the purchaser's
proceeds resulting from processing the gas, the value of production, for royalty purposes, shall never be
less than a value equivalent to 100 percent of the value of the residue gas attributable to the processing
of the lessee's gas.
(ii) In conducting reviews and audits, MMS will examine whether the contract reflects the total
consideration actually transferred either directly or indirectly from the buyer to the seller for the gas. If
the contract does not reflect the total consideration, then the MMS may require that the gas sold
pursuant to that contract be valued in accordance with paragraph (c) of this section. Value may not be
less than the gross proceeds accruing to the lessee, including the additional consideration.
(iii) If the MMS determines that the gross proceeds accruing to the lessee pursuant to an arm's-length
contract do not reflect the reasonable value of the production because of misconduct by or between the
contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the
production for the mutual benefit of the lessee and the lessor, then MMS shall require that the gas
production be valued pursuant to paragraph (c)(2) or (c)(3) of this section, and in accordance with the
notification requirements of paragraph (e) of this section. When MMS determines that the value may be
unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written
information justifying the lessee's value.

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

that difference computed pursuant to 30 CFR 218.54. If the lessee is entitled to a credit, MMS will
provide instructions for the taking of that credit.
(g) The lessee may request a value determination from MMS. In that event, the lessee shall propose to
MMS a value determination method, and may use that method in determining value for royalty purposes
until MMS issues its decision. The lessee shall submit all available data relevant to its proposal. The
MMS shall expeditiously determine the value based upon the lessee's proposal and any additional
information MMS deems necessary. In making a value determination MMS may use any of the valuation
criteria authorized by this subpart. That determination shall remain effective for the period stated therein.
After MMS issues its determination, the lessee shall make the adjustments in accordance with
paragraph (f) of this section.
(h) Notwithstanding any other provision of this section, under no circumstances shall the value of
production for royalty purposes be less than the gross proceeds accruing to the lessee for lease
production, less applicable allowances.
(i) The lessee must place gas in marketable condition and market the gas for the mutual benefit of the
lessee and the lessor at no cost to the Federal Government. Where the value established under this
section is determined by a lessee's gross proceeds, that value will be increased to the extent that the
gross proceeds have been reduced because the purchaser, or any other person, is providing certain
services the cost of which ordinarily is the responsibility of the lessee to place the gas in marketable
condition or to market the gas.
(j) Value shall be based on the highest price a prudent lessee can receive through legally enforceable
claims under its contract. If there is no contract revision or amendment, and the lessee fails to take
proper or timely action to receive prices or benefits to which it is entitled, it must pay royalty at a value
based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and
signed by all parties to an arm's-length contract. If the lessee makes timely application for a price
increase or benefit allowed under its contract but the purchaser refuses, and the lessee takes
reasonable measures, which are documented, to force purchaser compliance, the lessee will owe no
additional royalties unless or until monies or consideration resulting from the price increase or additional
benefits are received. This paragraph shall not be construed to permit a lessee to avoid its royalty
payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a
quantity of gas.
(k) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation,
monitoring, or other like process that results in a redetermination by MMS of value under this section
shall be considered final or binding as against the Federal Government or its beneficiaries until the audit
period is formally closed.
(l) Certain information submitted to MMS to support valuation proposals, including transportation or
extraordinary cost allowances, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C.
§552, or other Federal law. Any data specified by law to be privileged, confidential, or otherwise exempt
will be maintained in a confidential manner in accordance with applicable law and regulations. All
requests for information about determinations made under this subpart are to be submitted in
accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR
part 2.
[53 FR 1272, Jan. 15, 1988, as amended at 56 FR 46530, Sept. 13, 1991; 61 FR 5464, Feb. 12, 1996;
62 FR 65761, 65762, Dec. 16, 1997]

§ 206.153 Valuation standards—processed gas.
(a)(1) This section applies to the valuation of all gas that is processed by the lessee and any other gas
production to which this subpart applies and that is not subject to the valuation provisions of §206.152 of
this part. This section applies where the lessee's contract includes a reservation of the right to process
the gas and the lessee exercises that right.
(2) The value of production, for royalty purposes, of gas subject to this section shall be the combined
value of the residue gas and all gas plant products determined pursuant to this section, plus the value of
any condensate recovered downstream of the point of royalty settlement without resorting to processing
determined pursuant to §206.102 of this part, less applicable transportation allowances and processing
allowances determined pursuant to this subpart.
(b)(1)(i) The value of residue gas or any gas plant product sold under an arm's-length contract is the
gross proceeds accruing to the lessee, except as provided in paragraphs (b)(1)(ii), (iii), and (iv) of this
section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value
that the lessee reports for royalty purposes is subject to monitoring, review, and audit. For purposes of
this section, residue gas or any gas plant product which is sold or otherwise transferred to the lessee's

marketing affiliate and then sold by the marketing affiliate pursuant to an arm's-length contract shall be
valued in accordance with this paragraph based upon the sale by the marketing affiliate.
(ii) In conducting these reviews and audits, MMS will examine whether or not the contract reflects the
total consideration actually transferred either directly or indirectly from the buyer to the seller for the
residue gas or gas plant product. If the contract does not reflect the total consideration, then the MMS
may require that the residue gas or gas plant product sold pursuant to that contract be valued in
accordance with paragraph (c) of this section. Value may not be less than the gross proceeds accruing
to the lessee, including the additional consideration.
(iii) If the MMS determines that the gross proceeds accruing to the lessee pursuant to an arm's-length
contract do not reflect the reasonable value of the residue gas or gas plant product because of
misconduct by or between the contracting parties, or because the lessee otherwise has breached its
duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS
shall require that the residue gas or gas plant product be valued pursuant to paragraph (c)(2) or (c)(3) of
this section, and in accordance with the notification requirements of paragraph (e) of this section. When
MMS determines that the value may be unreasonable, MMS will notify the lessee and give the lessee an
opportunity to provide written information justifying the lessee's value.
(iv) How to value over-delivered volumes under a cash-out program. This paragraph applies to situations
where a pipeline purchases gas from a lessee according to a cash-out program under a transportation
contract. For all over-delivered volumes, the royalty value is the price the pipeline is required to pay for
volumes within the tolerances for over-delivery specified in the transportation contract. Use the same
value for volumes that exceed the over-delivery tolerances even if those volumes are subject to a lower
price under the transportation contract. However, if MMS determines that the price specified in the
transportation contract for over-delivered volumes is unreasonably low, the lessee must value all overdelivered volumes under paragraph (c)(2) or (c)(3) of this section.
(2) Notwithstanding the provisions of paragraph (b)(1) of this section, the value of residue gas sold
pursuant to a warranty contract shall be determined by MMS, and due consideration will be given to all
valuation criteria specified in this section. The lessee must request a value determination in accordance
with paragraph (g) of this section for gas sold pursuant to a warranty contract; provided, however, that
any value determination for a warranty contract in effect on the effective date of these regulations shall
remain in effect until modified by MMS.
(3) MMS may require a lessee to certify that its arm's-length contract provisions include all of the
consideration to be paid by the buyer, either directly or indirectly, for the residue gas or gas plant
product.
(c) The value of residue gas or any gas plant product which is not sold pursuant to an arm's-length
contract shall be the reasonable value determined in accordance with the first applicable of the following
methods:
(1) The gross proceeds accruing to the lessee pursuant to a sale under its non-arm's-length contract (or
other disposition other than by an arm's-length contract), provided that those gross proceeds are
equivalent to the gross proceeds derived from, or paid under, comparable arm's-length contracts for
purchases, sales, or other dispositions of like quality residue gas or gas plant products from the same
processing plant (or, if necessary to obtain a reasonable sample, from nearby plants). In evaluating the
comparability of arm's-length contracts for the purposes of these regulations, the following factors shall
be considered: price, time of execution, duration, market or markets served, terms, quality of residue gas
or gas plant products, volume, and such other factors as may be appropriate to reflect the value of the
residue gas or gas plant products;
(2) A value determined by consideration of other information relevant in valuing like-quality residue gas
or gas plant products, including gross proceeds under arm's-length contracts for like-quality residue gas
or gas plant products from the same gas plant or other nearby processing plants, posted prices for
residue gas or gas plant products, prices received in spot sales of residue gas or gas plant products,
other reliable public sources of price or market information, and other information as to the particular
lease operation or the saleability of such residue gas or gas plant products; or
(3) A net-back method or any other reasonable method to determine value.
(d)(1) Notwithstanding any other provisions of this section, except paragraph (h) of this section, if the
maximum price permitted by Federal law at which any residue gas or gas plant products may be sold is
less than the value determined pursuant to this section, then MMS shall accept such maximum price as
the value. For the purposes of this section, price limitations set by any State or local government shall
not be considered as a maximum price permitted by Federal law.
(2) The limitation prescribed by paragraph (d)(1) of this section shall not apply to residue gas sold

pursuant to a warranty contract and valued pursuant to paragraph (b)(2) of this section.
(e)(1) Where the value is determined pursuant to paragraph (c) of this section, the lessee shall retain all
data relevant to the determination of royalty value. Such data shall be subject to review and audit, and
MMS will direct a lessee to use a different value if it determines upon review or audit that the reported
value is inconsistent with the requirements of these regulations.
(2) Any Federal lessee will make available upon request to the authorized MMS or State
representatives, to the Office of the Inspector General of the Department of the Interior, or other persons
authorized to receive such information, arm's-length sales and volume data for like-quality residue gas
and gas plant products sold, purchased or otherwise obtained by the lessee from the same processing
plant or from nearby processing plants.
(3) A lessee shall notify MMS if it has determined any value pursuant to paragraph (c)(2) or (c)(3) of this
section. The notification shall be by letter to the MMS Associate Director for Minerals Revenue
Management or his/her designee. The letter shall identify the valuation method to be used and contain a
brief description of the procedure to be followed. The notification required by this paragraph is a onetime notification due no later than the end of the month following the month the lessee first reports
royalties on a Form MMS–2014 using a valuation method authorized by paragraph (c)(2) or (c)(3) of this
section, and each time there is a change in a method under paragraph (c)(2) or (c)(3) of this section.
(f) If MMS determines that a lessee has not properly determined value, the lessee shall pay the
difference, if any, between royalty payments made based upon the value it has used and the royalty
payments that are due based upon the value established by MMS. The lessee shall also pay interest
computed on that difference pursuant to 30 CFR 218.54. If the lessee is entitled to a credit, MMS will
provide instructions for the taking of that credit.
(g) The lessee may request a value determination from MMS. In that event, the lessee shall propose to
MMS a value determination method, and may use that method in determining value for royalty purposes
until MMS issues its decision. The lessee shall submit all available data relevant to its proposal. The
MMS shall expeditiously determine the value based upon the lessee's proposal and any additional
information MMS deems necessary. In making a value determination, MMS may use any of the
valuation criteria authorized by this subpart. That determination shall remain effective for the period
stated therein. After MMS issues its determination, the lessee shall make the adjustments in accordance
with paragraph (f) of this section.
(h) Notwithstanding any other provision of this section, under no circumstances shall the value of
production for royalty purposes be less than the gross proceeds accruing to the lessee for residue gas
and/or any gas plant products, less applicable transportation allowances and processing allowances
determined pursuant to this subpart.
(i) The lessee must place residue gas and gas plant products in marketable condition and market the
residue gas and gas plant products for the mutual benefit of the lessee and the lessor at no cost to the
Federal Government. Where the value established under this section is determined by a lessee's gross
proceeds, that value will be increased to the extent that the gross proceeds have been reduced because
the purchaser, or any other person, is providing certain services the cost of which ordinarily is the
responsibility of the lessee to place the residue gas or gas plant products in marketable condition or to
market the residue gas and gas plant products.
(j) Value shall be based on the highest price a prudent lessee can receive through legally enforceable
claims under its contract. Absent contract revision or amendment, if the lessee fails to take proper or
timely action to receive prices or benefits to which it is entitled it must pay royalty at a value based upon
that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all
parties to an arm's-length contract. If the lessee makes timely application for a price increase or benefit
allowed under its contract but the purchaser refuses, and the lessee takes reasonable measures, which
are documented, to force purchaser compliance, the lessee will owe no additional royalties unless or
until monies or consideration resulting from the price increase or additional benefits are received. This
paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations
where a purchaser fails to pay, in whole or in part, or timely, for a quantity of residue gas or gas plant
product.
(k) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation,
monitoring, or other like process that results in a redetermination by MMS of value under this section
shall be considered final or binding against the Federal Government or its beneficiaries until the audit
period is formally closed.
(l) Certain information submitted to MMS to support valuation proposals, including transportation
allowances, processing allowances or extraordinary cost allowances, is exempted from disclosure by the
Freedom of Information Act, 5 U.S.C. 552, or other Federal law. Any data specified by law to be

privileged, confidential, or otherwise exempt, will be maintained in a confidential manner in accordance
with applicable law and regulations. All requests for information about determinations made under this
part are to be submitted in accordance with the Freedom of Information Act regulation of the Department
of the Interior, 43 CFR part 2.
[53 FR 1272, Jan. 15, 1988, as amended at 56 FR 46530, Sept. 13, 1991; 61 FR 5465, Feb. 12, 1996;
62 FR 65762, Dec. 16, 1997]

§ 206.154 Determination of quantities and qualities for computing royalties.
(a)(1) Royalties shall be computed on the basis of the quantity and quality of unprocessed gas at the
point of royalty settlement approved by BLM or MMS for onshore and OCS leases, respectively.
(2) If the value of gas determined pursuant to §206.152 of this subpart is based upon a quantity and/or
quality that is different from the quantity and/or quality at the point of royalty settlement, as approved by
BLM or MMS, that value shall be adjusted for the differences in quantity and/or quality.
(b)(1) For residue gas and gas plant products, the quantity basis for computing royalties due is the
monthly net output of the plant even though residue gas and/or gas plant products may be in temporary
storage.
(2) If the value of residue gas and/or gas plant products determined pursuant to §206.153 of this subpart
is based upon a quantity and/or quality of residue gas and/or gas plant products that is different from
that which is attributable to a lease, determined in accordance with paragraph (c) of this section, that
value shall be adjusted for the differences in quantity and/or quality.
(c) The quantity of the residue gas and gas plant products attributable to a lease shall be determined
according to the following procedure:
(1) When the net output of the processing plant is derived from gas obtained from only one lease, the
quantity of the residue gas and gas plant products on which computations of royalty are based is the net
output of the plant.
(2) When the net output of a processing plant is derived from gas obtained from more than one lease
producing gas of uniform content, the quantity of the residue gas and gas plant products allocable to
each lease shall be in the same proportions as the ratios obtained by dividing the amount of gas
delivered to the plant from each lease by the total amount of gas delivered from all leases.
(3) When the net output of a processing plant is derived from gas obtained from more than one lease
producing gas of nonuniform content, the quantity of the residue gas allocable to each lease will be
determined by multiplying the amount of gas delivered to the plant from the lease by the residue gas
content of the gas, and dividing the arithmetical product thus obtained by the sum of the similar
arithmetical products separately obtained for all leases from which gas is delivered to the plant, and then
multiplying the net output of the residue gas by the arithmetic quotient obtained. The net output of gas
plant products allocable to each lease will be determined by multiplying the amount of gas delivered to
the plant from the lease by the gas plant product content of the gas, and dividing the arithmetical product
thus obtained by the sum of the similar arithmetical products separately obtained for all leases from
which gas is delivered to the plant, and then multiplying the net output of each gas plant product by the
arithmetic quotient obtained.
(4) A lessee may request MMS approval of other methods for determining the quantity of residue gas
and gas plant products allocable to each lease. If approved, such method will be applicable to all gas
production from Federal leases that is processed in the same plant.
(d)(1) No deductions may be made from the royalty volume or royalty value for actual or theoretical
losses. Any actual loss of unprocessed gas that may be sustained prior to the royalty settlement
metering or measurement point will not be subject to royalty provided that such loss is determined to
have been unavoidable by BLM or MMS, as appropriate.
(2) Except as provided in paragraph (d)(1) of this section and 30 CFR 202.151(c), royalties are due on
100 percent of the volume determined in accordance with paragraphs (a) through (c) of this section.
There can be no reduction in that determined volume for actual losses after the quantity basis has been
determined or for theoretical losses that are claimed to have taken place. Royalties are due on 100
percent of the value of the unprocessed gas, residue gas, and/or gas plant products as provided in this
subpart, less applicable allowances. There can be no deduction from the value of the unprocessed gas,
residue gas, and/or gas plant products to compensate for actual losses after the quantity basis has been
determined, or for theoretical losses that are claimed to have taken place.

[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5465, Feb. 12, 1996]

§ 206.155 Accounting for comparison.
(a) Except as provided in paragraph (b) of this section, where the lessee (or a person to whom the
lessee has transferred gas pursuant to a non-arm's-length contract or without a contract) processes the
lessee's gas and after processing the gas the residue gas is not sold pursuant to an arm's-length
contract, the value, for royalty purposes, shall be the greater of (1) the combined value, for royalty
purposes, of the residue gas and gas plant products resulting from processing the gas determined
pursuant to §206.153 of this subpart, plus the value, for royalty purposes, of any condensate recovered
downstream of the point of royalty settlement without resorting to processing determined pursuant to
§206.102 of this subpart; or (2) the value, for royalty purposes, of the gas prior to processing determined
in accordance with §206.152 of this subpart.
(b) The requirement for accounting for comparison contained in the terms of leases will govern as
provided in §206.150(b) of this subpart. When accounting for comparison is required by the lease terms,
such accounting for comparison shall be determined in accordance with paragraph (a) of this section.
[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5465, Feb. 12, 1996]

§ 206.156 Transportation allowances—general.
(a) Where the value of gas has been determined pursuant to §206.152 or §206.153 of this subpart at a
point (e.g., sales point or point of value determination) off the lease, MMS shall allow a deduction for the
reasonable actual costs incurred by the lessee to transport unprocessed gas, residue gas, and gas plant
products from a lease to a point off the lease including, if appropriate, transportation from the lease to a
gas processing plant off the lease and from the plant to a point away from the plant.
(b) Transportation costs must be allocated among all products produced and transported as provided in
§206.157.
(c)(1) Except as provided in paragraph (c)(3) of this section, for unprocessed gas valued in accordance
with §206.152 of this subpart, the transportation allowance deduction on the basis of a sales type code
may not exceed 50 percent of the value of the unprocessed gas determined under §206.152 of this
subpart.
(2) Except as provided in paragraph (c)(3) of this section, for gas production valued in accordance with
§206.153 of this subpart, the transportation allowance deduction on the basis of a sales type code may
not exceed 50 percent of the value of the residue gas or gas plant product determined under §206.153
of this subpart. For purposes of this section, natural gas liquids will be considered one product.
(3) Upon request of a lessee, MMS may approve a transportation allowance deduction in excess of the
limitations prescribed by paragraphs (c)(1) and (c)(2) of this section. The lessee must demonstrate that
the transportation costs incurred in excess of the limitations prescribed in paragraphs (c)(1) and (c)(2) of
this section were reasonable, actual, and necessary. An application for exception (using Form MMS–
4393, Request to Exceed Regulatory Allowance Limitation) must contain all relevant and supporting
documentation necessary for MMS to make a determination. Under no circumstances may the value for
royalty purposes under any sales type code be reduced to zero.
(d) If, after a review or audit, MMS determines that a lessee has improperly determined a transportation
allowance authorized by this subpart, then the lessee must pay any additional royalties, plus interest,
determined in accordance with 30 CFR 218.54, or will be entitled to a credit, with interest. If the lessee
takes a deduction for transportation on Form MMS–2014 by improperly netting the allowance against the
sales value of the unprocessed gas, residue gas, and gas plant products instead of reporting the
allowance as a separate entry, MMS may assess a civil penalty under 30 CFR part 241.
[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5465, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999;
73 FR 15890, Mar. 26, 2008]

§ 206.157 Determination of transportation allowances.
(a) Arm's-length transportation contracts. (1)(i) For transportation costs incurred by a lessee under an
arm's-length contract, the transportation allowance shall be the reasonable, actual costs incurred by the
lessee for transporting the unprocessed gas, residue gas and/or gas plant products under that contract,
except as provided in paragraphs (a)(1)(ii) and (a)(1)(iii) of this section, subject to monitoring, review,
audit, and adjustment. The lessee shall have the burden of demonstrating that its contract is arm'slength. MMS' prior approval is not required before a lessee may deduct costs incurred under an arm's-

length contract. Such allowances shall be subject to the provisions of paragraph (f) of this section. The
lessee must claim a transportation allowance by reporting it as a separate entry on the Form MMS–
2014.
(ii) In conducting reviews and audits, MMS will examine whether or not the contract reflects more than
the consideration actually transferred either directly or indirectly from the lessee to the transporter for the
transportation. If the contract reflects more than the total consideration, then the MMS may require that
the transportation allowance be determined in accordance with paragraph (b) of this section.
(iii) If the MMS determines that the consideration paid pursuant to an arm's-length transportation
contract does not reflect the reasonable value of the transportation because of misconduct by or
between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to
market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that
the transportation allowance be determined in accordance with paragraph (b) of this section. When MMS
determines that the value of the transportation may be unreasonable, MMS will notify the lessee and
give the lessee an opportunity to provide written information justifying the lessee's transportation costs.
(2)(i) If an arm's-length transportation contract includes more than one product in a gaseous phase and
the transportation costs attributable to each product cannot be determined from the contract, the total
transportation costs shall be allocated in a consistent and equitable manner to each of the products
transported in the same proportion as the ratio of the volume of each product (excluding waste products
which have no value) to the volume of all products in the gaseous phase (excluding waste products
which have no value). Except as provided in this paragraph, no allowance may be taken for the costs of
transporting lease production which is not royalty bearing without MMS approval.
(ii) Notwithstanding the requirements of paragraph (i), the lessee may propose to MMS a cost allocation
method on the basis of the values of the products transported. MMS shall approve the method unless it
determines that it is not consistent with the purposes of the regulations in this part.
(3) If an arm's-length transportation contract includes both gaseous and liquid products and the
transportation costs attributable to each cannot be determined from the contract, the lessee shall
propose an allocation procedure to MMS. The lessee may use the transportation allowance determined
in accordance with its proposed allocation procedure until MMS issues its determination on the
acceptability of the cost allocation. The lessee shall submit all relevant data to support its proposal. MMS
shall then determine the gas transportation allowance based upon the lessee's proposal and any
additional information MMS deems necessary. The lessee must submit the allocation proposal within 3
months of claiming the allocated deduction on the Form MMS–2014.
(4) Where the lessee's payments for transportation under an arm's-length contract are not based on a
dollar per unit, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the
purposes of this section.
(5) Where an arm's-length sales contract price or a posted price includes a provision whereby the listed
price is reduced by a transportation factor, MMS will not consider the transportation factor to be a
transportation allowance. The transportation factor may be used in determining the lessee's gross
proceeds for the sale of the product. The transportation factor may not exceed 50 percent of the base
price of the product without MMS approval.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-arm's-length transportation contract or has
no contract, including those situations where the lessee performs transportation services for itself, the
transportation allowance will be based upon the lessee's reasonable actual costs as provided in this
paragraph. All transportation allowances deducted under a non-arm's-length or no contract situation are
subject to monitoring, review, audit, and adjustment. The lessee must claim a transportation allowance
by reporting it as a separate entry on the Form MMS–2014. When necessary or appropriate, MMS may
direct a lessee to modify its estimated or actual transportation allowance deduction.
(2) The transportation allowance for non-arm's-length or no-contract situations shall be based upon the
lessee's actual costs for transportation during the reporting period, including operating and maintenance
expenses, overhead, and either depreciation and a return on undepreciated capital investment in
accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the initial depreciable
investment in the transportation system multiplied by a rate of return in accordance with paragraph (b)(2)
(iv)(B) of this section. Allowable capital costs are generally those costs for depreciable fixed assets
(including costs of delivery and installation of capital equipment) which are an integral part of the
transportation system.
(i) Allowable operating expenses include: Operations supervision and engineering; operations labor;
fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and
attributable operating expense which the lessee can document.

(ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of
equipment; maintenance labor; and other directly allocable and attributable maintenance expenses
which the lessee can document.
(iii) Overhead directly attributable and allocable to the operation and maintenance of the transportation
system is an allowable expense. State and Federal income taxes and severance taxes and other fees,
including royalties, are not allowable expenses.
(iv) A lessee may use either depreciation or a return on depreciable capital investment. After a lessee
has elected to use either method for a transportation system, the lessee may not later elect to change to
the other alternative without approval of the MMS.
(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method
based on the life of equipment or on the life of the reserves which the transportation system services, or
a unit of production method. After an election is made, the lessee may not change methods without
MMS approval. A change in ownership of a transportation system shall not alter the depreciation
schedule established by the original transporter/lessee for purposes of the allowance calculation. With or
without a change in ownership, a transportation system shall be depreciated only once. Equipment shall
not be depreciated below a reasonable salvage value.
(B) The MMS shall allow as a cost an amount equal to the allowable initial capital investment in the
transportation system multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this
section. No allowance shall be provided for depreciation. This alternative shall apply only to
transportation facilities first placed in service after March 1, 1988.
(v) The rate of return must be 1.3 times the industrial rate associated with Standard & Poor's BBB rating.
The BBB rate must be the monthly average rate as published in Standard & Poor's Bond Guide for the
first month for which the allowance is applicable. The rate must be redetermined at the beginning of
each subsequent calendar year.
(3)(i) The deduction for transportation costs shall be determined on the basis of the lessee's cost of
transporting each product through each individual transportation system. Where more than one product
in a gaseous phase is transported, the allocation of costs to each of the products transported shall be
made in a consistent and equitable manner in the same proportion as the ratio of the volume of each
product (excluding waste products which have no value) to the volume of all products in the gaseous
phase (excluding waste products which have no value). Except as provided in this paragraph, the lessee
may not take an allowance for transporting a product which is not royalty bearing without MMS approval.
(ii) Notwithstanding the requirements of paragraph (b)(3)(i), the lessee may propose to the MMS a cost
allocation method on the basis of the values of the products transported. MMS shall approve the method
unless it determines that it is not consistent with the purposes of the regulations in this part.
(4) Where both gaseous and liquid products are transported through the same transportation system,
the lessee shall propose a cost allocation procedure to MMS. The lessee may use the transportation
allowance determined in accordance with its proposed allocation procedure until MMS issues its
determination on the acceptability of the cost allocation. The lessee shall submit all relevant data to
support its proposal. MMS shall then determine the transportation allowance based upon the lessee's
proposal and any additional information MMS deems necessary. The lessee must submit the allocation
proposal within 3 months of claiming the allocated deduction on the Form MMS–2014.
(5) You may apply for an exception from the requirement to compute actual costs under paragraphs (b)
(1) through (b)(4) of this section.
(i) The MMS will grant the exception if:
(A) The transportation system has a tariff filed with the Federal Energy Regulatory Commission (FERC)
or a state regulatory agency, that FERC or the state regulatory agency has permitted to become
effective, and
(B) Third parties are paying prices, including discounted prices, under the tariff to transport gas on the
system under arm's-length transportation contracts.
(ii) If MMS approves the exception, you must calculate your transportation allowance for each production
month based on the lesser of the volume-weighted average of the rates paid by the third parties under
arm's-length transportation contracts during that production month or the non-arm's-length payment by
the lessee to the pipeline.
(iii) If during any production month there are no prices paid under the tariff by third parties to transport

gas on the system under arm's-length transportation contracts, you may use the volume-weighted
average of the rates paid by third parties under arm's-length transportation contracts in the most recent
preceding production month in which the tariff remains in effect and third parties paid such rates, for up
to five successive production months. You must use the non-arm's-length payment by the lessee to the
pipeline if it is less than the volume-weighted average of the rates paid by third parties under arm'slength contracts.
(c) Reporting requirements —(1) Arm's-length contracts. (i) You must use a separate entry on Form
MMS–2014 to notify MMS of a transportation allowance.
(ii) The MMS may require you to submit arm's-length transportation contracts, production agreements,
operating agreements, and related documents. Recordkeeping requirements are found at part 207 of
this chapter.
(iii) You may not use a transportation allowance that was in effect before March 1, 1988. You must use
the provisions of this subpart to determine your transportation allowance.
(2) Non-arm's-length or no contract. (i) You must use a separate entry on Form MMS–2014 to notify
MMS of a transportation allowance.
(ii) For new transportation facilities or arrangements, base your initial deduction on estimates of
allowable gas transportation costs for the applicable period. Use the most recently available operations
data for the transportation system or, if such data are not available, use estimates based on data for
similar transportation systems. Paragraph (e) of this section will apply when you amend your report
based on your actual costs.
(iii) The MMS may require you to submit all data used to calculate the allowance deduction.
Recordkeeping requirements are found at part 207 of this chapter.
(iv) If you are authorized under paragraph (b)(5) of this section to use an exception to the requirement to
calculate your actual transportation costs, you must follow the reporting requirements of paragraph (c)(1)
of this section.
(v) You may not use a transportation allowance that was in effect before March 1, 1988. You must use
the provisions of this subpart to determine your transportation allowance.
(d) Interest and assessments. (1) If a lessee deducts a transportation allowance on its Form MMS–2014
that exceeds 50 percent of the value of the gas transported without obtaining prior approval of MMS
under §206.156, the lessee shall pay interest on the excess allowance amount taken from the date such
amount is taken to the date the lessee files an exception request with MMS.
(2) If a lessee erroneously reports a transportation allowance which results in an underpayment of
royalties, interest shall be paid on the amount of that underpayment.
(3) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.54.
(e) Adjustments. (1) If the actual transportation allowance is less than the amount the lessee has taken
on Form MMS–2014 for each month during the allowance reporting period, the lessee shall be required
to pay additional royalties due plus interest computed under 30 CFR 218.54 from the allowance
reporting period when the lessee took the deduction to the date the lessee repays the difference to
MMS. If the actual transportation allowance is greater than the amount the lessee has taken on Form
MMS–2014 for each month during the allowance reporting period, the lessee shall be entitled to a credit
without interest.
(2) For lessees transporting production from onshore Federal leases, the lessee must submit a corrected
Form MMS–2014 to reflect actual costs, together with any payment, in accordance with instructions
provided by MMS.
(3) For lessees transporting gas production from leases on the OCS, if the lessee's estimated
transportation allowance exceeds the allowance based on actual costs, the lessee must submit a
corrected Form MMS–2014 to reflect actual costs, together with its payment, in accordance with
instructions provided by MMS. If the lessee's estimated transportation allowance is less than the
allowance based on actual costs, the refund procedure will be specified by MMS.
(f) Allowable costs in determining transportation allowances. You may include, but are not limited to
(subject to the requirements of paragraph (g) of this section), the following costs in determining the
arm's-length transportation allowance under paragraph (a) of this section or the non-arm's-length

transportation allowance under paragraph (b) of this section. You may not use any cost as a deduction
that duplicates all or part of any other cost that you use under this paragraph.
(1) Firm demand charges paid to pipelines. You may deduct firm demand charges or capacity
reservation fees paid to a pipeline, including charges or fees for unused firm capacity that you have not
sold before you report your allowance. If you receive a payment from any party for release or sale of firm
capacity after reporting a transportation allowance that included the cost of that unused firm capacity, or
if you receive a payment or credit from the pipeline for penalty refunds, rate case refunds, or other
reasons, you must reduce the firm demand charge claimed on the Form MMS–2014 by the amount of
that payment. You must modify the Form MMS–2014 by the amount received or credited for the affected
reporting period, and pay any resulting royalty and late payment interest due;
(2) Gas supply realignment (GSR) costs. The GSR costs result from a pipeline reforming or terminating
supply contracts with producers to implement the restructuring requirements of FERC Orders in 18 CFR
part 284;
(3) Commodity charges. The commodity charge allows the pipeline to recover the costs of providing
service;
(4) Wheeling costs. Hub operators charge a wheeling cost for transporting gas from one pipeline to
either the same or another pipeline through a market center or hub. A hub is a connected manifold of
pipelines through which a series of incoming pipelines are interconnected to a series of outgoing
pipelines;
(5) Gas Research Institute (GRI) fees. The GRI conducts research, development, and commercialization
programs on natural gas related topics for the benefit of the U.S. gas industry and gas customers. GRI
fees are allowable provided such fees are mandatory in FERC-approved tariffs;
(6) Annual Charge Adjustment (ACA) fees. FERC charges these fees to pipelines to pay for its operating
expenses;
(7) Payments (either volumetric or in value) for actual or theoretical losses. However, theoretical losses
are not deductible in non-arm's-length transportation arrangements unless the transportation allowance
is based on arm's-length transportation rates charged under a FERC- or state regulatory-approved tariff
under paragraph (b)(5) of this section. If you receive volumes or credit for line gain, you must reduce
your transportation allowance accordingly and pay any resulting royalties and late payment interest due;
(8) Temporary storage services. This includes short duration storage services offered by market centers
or hubs (commonly referred to as “parking” or “banking”), or other temporary storage services provided
by pipeline transporters, whether actual or provided as a matter of accounting. Temporary storage is
limited to 30 days or less; and
(9) Supplemental costs for compression, dehydration, and treatment of gas. MMS allows these costs
only if such services are required for transportation and exceed the services necessary to place
production into marketable condition required under §§206.152(i) and 206.153(i) of this part.
(10) Costs of surety. You may deduct the costs of securing a letter of credit, or other surety, that the
pipeline requires you as a shipper to maintain under an arm's-length transportation contract.
(g) Nonallowable costs in determining transportation allowances. Lessees may not include the following
costs in determining the arm's-length transportation allowance under paragraph (a) of this section or the
non-arm's-length transportation allowance under paragraph (b) of this section:
(1) Fees or costs incurred for storage. This includes storing production in a storage facility, whether on
or off the lease, for more than 30 days;
(2) Aggregator/marketer fees. This includes fees you pay to another person (including your affiliates) to
market your gas, including purchasing and reselling the gas, or finding or maintaining a market for the
gas production;
(3) Penalties you incur as shipper. These penalties include, but are not limited to:
(i) Over-delivery cash-out penalties. This includes the difference between the price the pipeline pays you
for over-delivered volumes outside the tolerances and the price you receive for over-delivered volumes
within the tolerances;
(ii) Scheduling penalties. This includes penalties you incur for differences between daily volumes

delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point;
(iii) Imbalance penalties. This includes penalties you incur (generally on a monthly basis) for differences
between volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or
delivery point; and
(iv) Operational penalties. This includes fees you incur for violation of the pipeline's curtailment or
operational orders issued to protect the operational integrity of the pipeline;
(4) Intra-hub transfer fees. These are fees you pay to hub operators for administrative services (e.g., title
transfer tracking) necessary to account for the sale of gas within a hub;
(5) Fees paid to brokers. This includes fees paid to parties who arrange marketing or transportation, if
such fees are separately identified from aggregator/marketer fees;
(6) Fees paid to scheduling service providers. This includes fees paid to parties who provide scheduling
services, if such fees are separately identified from aggregator/marketer fees;
(7) Internal costs. This includes salaries and related costs, rent/space costs, office equipment costs,
legal fees, and other costs to schedule, nominate, and account for sale or movement of production; and
(8) Other nonallowable costs. Any cost you incur for services you are required to provide at no cost to
the lessor.
(h) Other transportation cost determinations. Use this section when calculating transportation costs to
establish value using a netback procedure or any other procedure that requires deduction of
transportation costs.
[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45762, Nov. 14, 1988; 61 FR 5465, Feb. 12, 1996;
62 FR 65762, Dec. 16, 1997; 70 FR 11878, Mar. 10, 2005; 73 FR 15891, Mar. 26, 2008]

§ 206.158 Processing allowances—general.
(a) Where the value of gas is determined pursuant to §206.153 of this subpart, a deduction shall be
allowed for the reasonable actual costs of processing.
(b) Processing costs must be allocated among the gas plant products. A separate processing allowance
must be determined for each gas plant product and processing plant relationship. Natural gas liquids
(NGL's) shall be considered as one product.
(c)(1) Except as provided in paragraph (d)(2) of this section, the processing allowance shall not be
applied against the value of the residue gas. Where there is no residue gas MMS may designate an
appropriate gas plant product against which no allowance may be applied.
(2) Except as provided in paragraph (c)(3) of this section, the processing allowance deduction on the
basis of an individual product shall not exceed 662/3percent of the value of each gas plant product
determined in accordance with §206.153 of this subpart (such value to be reduced first for any
transportation allowances related to postprocessing transportation authorized by §206.156 of this
subpart).
(3) Upon request of a lessee, MMS may approve a processing allowance in excess of the limitation
prescribed by paragraph (c)(2) of this section. The lessee must demonstrate that the processing costs
incurred in excess of the limitation prescribed in paragraph (c)(2) of this section were reasonable, actual,
and necessary. An application for exception (using Form MMS–4393, Request to Exceed Regulatory
Allowance Limitation) shall contain all relevant and supporting documentation for MMS to make a
determination. Under no circumstances shall the value for royalty purposes of any gas plant product be
reduced to zero.
(d)(1) Except as provided in paragraph (d)(2) of this section, no processing cost deduction shall be
allowed for the costs of placing lease products in marketable condition, including dehydration,
separation, compression, or storage, even if those functions are performed off the lease or at a
processing plant. Where gas is processed for the removal of acid gases, commonly referred to as
“sweetening,” no processing cost deduction shall be allowed for such costs unless the acid gases
removed are further processed into a gas plant product. In such event, the lessee shall be eligible for a
processing allowance as determined in accordance with this subpart. However, MMS will not grant any
processing allowance for processing lease production which is not royalty bearing.

(2)(i) If the lessee incurs extraordinary costs for processing gas production from a gas production
operation, it may apply to MMS for an allowance for those costs which shall be in addition to any other
processing allowance to which the lessee is entitled pursuant to this section. Such an allowance may be
granted only if the lessee can demonstrate that the costs are, by reference to standard industry
conditions and practice, extraordinary, unusual, or unconventional.
(ii) Prior MMS approval to continue an extraordinary processing cost allowance is not required. However,
to retain the authority to deduct the allowance the lessee must report the deduction to MMS in a form
and manner prescribed by MMS.
(e) If MMS determines that a lessee has improperly determined a processing allowance authorized by
this subpart, then the lessee must pay any additional royalties, plus interest determined under 30 CFR
218.54, or will be entitled to a credit with interest. If the lessee takes a deduction for processing on Form
MMS–2014 by improperly netting the allowance against the sales value of the gas plant products instead
of reporting the allowance as a separate entry, MMS may assess a civil penalty under 30 CFR part 241.
[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5466, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999;
73 FR 15891, Mar. 26, 2008]

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

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

based upon industry data for similar gas processing plants.
(iii) Upon request by MMS, the lessee shall submit all data used to prepare the allowance deduction.
The data shall be provided within a reasonable period of time, as determined by MMS.
(iv) If the lessee is authorized to use the volume weighted average prices charged other persons as its
processing allowance in accordance with paragraph (b)(4) of this section, it shall follow the reporting
requirements of paragraph (c)(1) of this section.
(d) Interest. (1) If a lessee deducts a processing allowance on its Form MMS–2014 that exceeds
662/3percent of the value of the gas processed without obtaining prior approval of MMS under
§206.158, the lessee shall pay interest on the excess allowance amount taken from the date such
amount is taken to the date the lessee files an exception request with MMS.
(2) If a lessee erroneously reports a processing allowance which results in an underpayment of royalties,
interest shall be paid on the amount of that underpayment.
(3) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.54.
(e) Adjustments. (1) If the actual processing allowance is less than the amount the lessee has taken on
Form MMS–2014 for each month during the allowance reporting period, the lessee shall pay additional
royalties due plus interest computed under 30 CFR 218.54 from the allowance reporting period when the
lessee took the deduction to the date the lessee repays the difference to MMS. If the actual processing
allowance is greater than the amount the lessee has taken on Form MMS–2014 for each month during
the allowance reporting period, the lessee shall be entitled to a credit with interest.
(2) For lessees processing production from onshore Federal leases, the lessee must submit a corrected
Form MMS–2014 to reflect actual costs, together with any payment, in accordance with instructions
provided by MMS.
(3) For lessees processing gas production from leases on the OCS, if the lessee's estimated processing
allowance exceeds the allowance based on actual costs, the lessee must submit a corrected Form
MMS–2014 to reflect actual costs, together with its payment, in accordance with instructions provided by
MMS. If the lessee's estimated costs were less than the actual costs, the refund procedure will be
specified by MMS.
(f) Other processing cost determinations. The provisions of this section shall apply to determine
processing costs when establishing value using a net back valuation procedure or any other procedure
that requires deduction of processing costs.
[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45762, Nov. 14, 1988; 61 FR 5466, Feb. 12, 1996;
64 FR 43288, Aug. 10, 1999; 73 FR 15891, Mar. 26, 2008]

§ 206.160 Operating allowances.
Notwithstanding any other provisions in these regulations, an operating allowance may be used for the
purpose of computing payment obligations when specified in the notice of sale and the lease. The
allowance amount or formula shall be specified in the notice of sale and in the lease agreement.
[61 FR 3804, Feb. 2, 1996]
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§ 210.155 What reports must I submit for Federal onshore stripper oil properties?
(a) General. Operators who have been granted a reduced royalty rate by the Bureau of Land
Management (BLM) under 43 CFR 3103.4–2 must submit Form MMS–4377, Stripper Royalty
Rate Reduction Notification, under 43 CFR 3103.4–2(b)(3).