Title 30—Mineral Resources--Volume 3

§ 1201.100 Responsibilities of the Director for Office of Natural Resources Revenue.

The Director is responsible for the collection of certain rents, royalties, and other payments; for the receipt of sales and production reports; for determining royalty liability; for maintaining accounting records; for any audits of the royalty payments and obligations; and for any and all other functions relating to royalty management on Federal and Indian oil and gas leases.

[47 FR 47768, Oct. 27, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, and further redesignated and amended at 75 FR 61066, Oct. 4, 2010]

§ 1202.51 Scope and definitions.

(a) This subpart is applicable to Federal and Indian (Tribal and allotted) oil and gas leases (except leases on the Osage Indian Reservation, Osage County, Oklahoma) and OCS sulfur leases.

(b) The definitions in § 1206.20 of this chapter are applicable to subparts B, C, D, and J of this part.

[53 FR 1217, Jan. 15, 1988, as amended at 64 FR 43513, Aug. 10, 1999; 81 FR 43369, July 1, 2016; 82 FR 36953, Aug. 7, 2017; 85 FR 62019, Oct. 1, 2020]

§ 1202.52 Royalties.

(a) Royalties on oil, gas, and OCS sulfur shall be at the royalty rate specified in the lease, unless the Secretary, pursuant to the provisions of the applicable mineral leasing laws, reduces, or in the case of OCS leases, reduces or eliminates, the royalty rate or net profit share set forth in the lease.

(b) For purposes of this subpart, the use of the term royalty(ies) includes the term net profit share(s).

§ 1202.53 Minimum royalty.

For leases that provide for minimum royalty payments, the lessee shall pay the minimum royalty as specified in the lease.

§ 1202.100 Royalty on oil.

(a) Royalties due on oil production from leases subject to the requirements of this part, including condensate separated from gas without processing, shall be at the royalty rate established by the terms of the lease. Royalty shall be paid in value unless the Office of Natural Resources Revenue (ONRR) requires payment in-kind. When paid in value, the royalty due shall be the value, for royalty purposes, determined pursuant to part 1206 of this title multiplied by the royalty rate in the lease.

(b)(1) All oil (except oil unavoidably lost or used on, or for the benefit of, the lease, including that oil used off-lease for the benefit of the lease when such off-lease use is permitted by the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) or BLM, as appropriate) produced from a Federal or Indian lease to which this part applies is subject to royalty.

(2) When oil is used on, or for the benefit of, the lease at a production facility handling production from more than one lease with the approval of the BSEE or BLM, as appropriate, or at a production facility handling unitized or communitized production, only that proportionate share of each lease's production (actual or allocated) necessary to operate the production facility may be used royalty-free.

(3) Where the terms of any lease are inconsistent with this section, the lease terms shall govern to the extent of that inconsistency.

(c) If BLM determines that oil was avoidably lost or wasted from an onshore lease, or that oil was drained from an onshore lease for which compensatory royalty is due, or if BSEE determines that oil was avoidably lost or wasted from an offshore lease, then the value of that oil shall be determined in accordance with 30 CFR part 1206.

(d) If a lessee receives insurance compensation for unavoidably lost oil, royalties are due on the amount of that compensation. This paragraph shall not apply to compensation through 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 1206. In applying the requirements of 30 CFR part 1206, the circumstances involved in the actual disposition of the portion of the production to which the lessee was entitled but did not take shall be considered as controlling in arriving at the value, for royalty purposes, of that portion as though the person actually selling or disposing of the production were the lessee of the Federal or Indian lease.

(2) If a Federal or Indian lessee takes less than its proportionate share of agreement production, upon request of the lessee ONRR may authorize a royalty valuation method different from that required by paragraph (e)(1) of this section, but consistent with the purposes of these regulations, for any volumes not taken by the lessee but for which royalties are due.

(3) For purposes of this subchapter, all persons actually taking volumes in excess of their proportionate share of production in any month under a unitization or communitization agreement shall be deemed to have taken ratably from all persons actually taking less than their proportionate share of the agreement production for that month.

(4) If a lessee takes less than its proportionate share of agreement production for any month but royalties are paid on the full volume of its proportionate share in accordance with the provisions of this section, no additional royalty will be owed for that lease for prior periods when the lessee subsequently takes more than its proportionate share to balance its account or when the lessee is paid a sum of money by the other agreement participants to balance its account.

(f) For production from Federal and Indian leases which are committed to federally-approved unitization or communitization agreements, upon request of a lessee ONRR may establish the value of production pursuant to a method other than the method required by the regulations in this title if: (1) The proposed method for establishing value is consistent with the requirements of the applicable statutes, lease terms, and agreement terms; (2) persons with an interest in the agreement, including, to the extent practical, royalty interests, are given notice and an opportunity to comment on the proposed valuation method before it is authorized; and (3) to the extent practical, persons with an interest in a Federal or Indian lease committed to the agreement, including royalty interests, must agree to use the proposed method for valuing production from the agreement for royalty purposes.

[53 FR 1217, Jan. 15, 1988, as amended at 78 FR 30200, May 22, 2013]

§ 1202.101 Standards for reporting and paying royalties.

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

[53 FR 1217, Jan. 15, 1988]

§ 1202.150 Royalty on gas.

(a) Royalties due on gas production from leases subject to the requirements of this subpart, except helium produced from Federal leases, shall be at the rate established by the terms of the lease. Royalty shall be paid in value unless ONRR requires payment in kind. When paid in value, the royalty due shall be the value, for royalty purposes, determined pursuant to 30 CFR part 1206 of this title multiplied by the royalty rate in the lease.

(b)(1) All gas (except gas unavoidably lost or used on, or for the benefit of, the lease, including that gas used off-lease for the benefit of the lease when such off-lease use is permitted by the BSEE or BLM, as appropriate) produced from a Federal lease to which this subpart applies is subject to royalty.

(2) When gas is used on, or for the benefit of, the lease at a production facility handling production from more than one lease with the approval of BSEE or BLM, as appropriate, or at a production facility handling unitized or communitized production, only that proportionate share of each lease's production (actual or allocated) necessary to operate the production facility may be used royalty free.

(3) Where the terms of any lease are inconsistent with this subpart, the lease terms shall govern to the extent of that inconsistency.

(c) If BLM determines that gas was avoidably lost or wasted from an onshore lease, or that gas was drained from an onshore lease for which compensatory royalty is due, or if BSEE determines that gas was avoidably lost or wasted from an OCS lease, then the value of that gas shall be determined in accordance with 30 CFR part 1206.

(d) If a lessee receives insurance compensation for unavoidably lost gas, royalties are due on the amount of that compensation. This paragraph shall not apply to compensation through 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 1206. In applying the requirements of 30 CFR part 1206, the circumstances involved in the actual disposition of the portion of the production to which the lessee was entitled but did not take shall be considered as controlling in arriving at the value for royalty purposes of that portion, as if the person actually selling or disposing of the production were the lessee of the Federal lease.

(2) If a Federal lessee takes less than its proportionate share of agreement production, upon request of the lessee ONRR may authorize a royalty valuation method different from that required by paragraph (e)(1) of this section, but consistent with the purpose of these regulations, for any volumes not taken by the lessee but for which royalties are due.

(3) For purposes of this subchapter, all persons actually taking volumes in excess of their proportionate share of production in any month under a unitization or communitization agreement shall be deemed to have taken ratably from all persons actually taking less than their proportionate share of the agreement production for that month.

(4) If a lessee takes less than its proportionate share of agreement production for any month but royalties are paid on the full volume of its proportionate share in accordance with the provisions of this section, no additional royalty will be owed for that lease for prior periods at the time the lessee subsequently takes more than its proportionate share to balance its account or when the lessee is paid a sum of money by the other agreement participants to balance its account.

(f) For production from Federal leases which are committed to federally-approved unitization or communitization agreements, upon request of a lessee ONRR may establish the value of production pursuant to a method other than the method required by the regulations in this title if: (1) The proposed method for establishing value is consistent with the requirements of the applicable statutes, lease terms and agreement terms; (2) to the extent practical, persons with an interest in the agreement, including royalty interests, are given notice and an opportunity to comment on the proposed valuation method before it is authorized; and (3) to the extent practical, persons with an interest in a Federal lease committed to the agreement, including royalty interests, must agree to use the proposed method for valuing production from the agreement for royalty purposes.

[53 FR 1271, Jan. 15, 1988, as amended at 64 FR 43513, Aug. 10, 1999; 78 FR 30200, May 22, 2013]

§ 1202.151 Royalty on processed gas.

(a)(1) A royalty, as provided in the lease, shall be paid on the value of:

(i) Any condensate recovered downstream of the point of royalty settlement without resorting to processing; and

(ii) Residue gas and all gas plant products resulting from processing the gas produced from a lease subject to this subpart.

(2) ONRR shall authorize a processing allowance for the reasonable, actual costs of processing the gas produced from Federal leases. Processing allowances shall be determined in accordance with 30 CFR part 1206 subpart D for gas production from Federal leases and 30 CFR part 1206 subpart E for gas production from Indian leases.

(b) A reasonable amount of residue gas shall be allowed royalty free for operation of the processing plant, but no allowance shall be made for boosting residue gas or other expenses incidental to marketing, except as provided in 30 CFR part 1206. In those situations where a processing plant processes gas from more than one lease, only that proportionate share of each lease's residue gas necessary for the operation of the processing plant shall be allowed royalty free.

(c) No royalty is due on residue gas, or any gas plant product resulting from processing gas, which is reinjected into a reservoir within the same lease, unit area, or communitized area, when the reinjection is included in a plan of development or operations and the plan has received BLM or Bureau of Ocean Energy Management (BOEM) approval for onshore or offshore operations, respectively, until such time as they are finally produced from the reservoir for sale or other disposition off-lease.

[53 FR 1217, Jan. 15, 1988, as amended at 61 FR 5490, Feb. 12, 1996; 64 FR 43513, Aug. 10, 1999; 78 FR 30200, May 22, 2013]

§ 1202.152 Standards for reporting and paying royalties on gas.

(a)(1) If you are responsible for reporting production or royalties, you must:

(i) Report gas volumes and British thermal unit (Btu) heating values, if applicable, under the same degree of water saturation;

(ii) Report gas volumes in units of 1,000 cubic feet (mcf); and

(iii) Report gas volumes and Btu heating value at a standard pressure base of 14.73 pounds per square inch absolute (psia) and a standard temperature base of 60 °F.

(2) The frequency and method of Btu measurement as set forth in the lessee's contract shall be used to determine Btu heating values for reporting purposes. However, the lessee shall measure the Btu value at least semiannually by recognized standard industry testing methods even if the lessee's contract provides for less frequent measurement.

(b)(1) Residue gas and gas plant product volumes shall be reported as specified in this paragraph.

(2) Carbon dioxide (CO2), nitrogen (N2), helium (He), residue gas, and any other gas marketed as a separate product shall be reported by using the same standards specified in paragraph (a) of this section.

(3) Natural gas liquids (NGL) volumes shall be reported in standard U.S. gallons (231 cubic inches) at 60 °F.

(4) Sulfur (S) volumes shall be reported in long tons (2,240 pounds).

[53 FR 1271, Jan. 15, 1988, as amended at 63 FR 26367, May 12, 1998]

§ 1202.250 Overriding royalty interest.

The regulations governing overriding royalty interests, production payments, or similar interests created under Federal coal leases are in 43 CFR group 3400.

[54 FR 1522, Jan. 13, 1989]

§ 1202.350 Scope and definitions.

(a) This subpart is applicable to all geothermal resources produced from Federal geothermal leases issued pursuant to the Geothermal Steam Act of 1970, as amended (30 U.S.C. 1001 et seq.).

(b) The definitions in § 1206.351 are applicable to this subpart.

[56 FR 57275, Nov. 8, 1991, as amended at 78 FR 30200, May 22, 2013]

§ 1202.351 Royalties on geothermal resources.

(a)(1) Royalties on geothermal resources, including byproducts, or on electricity produced using geothermal resources, will be at the royalty rate(s) specified in the lease, unless the Secretary of the Interior temporarily waives, suspends, or reduces that rate(s). Royalties are determined under 30 CFR part 1206, subpart H.

(2) Fees in lieu of royalties on geothermal resources are prescribed in 30 CFR part 1206, subpart H.

(3) Except for the amount credited against royalties for in-kind deliveries of electricity to a State or county under § 1218.306, you must pay royalties and direct use fees in money.

(b)(1) Except as specified in paragraph (b)(2) of this section, royalties or fees are due on—

(i) All geothermal resources produced from a lease and that are sold or used by the lessee or are reasonably susceptible to sale or use by the lessee, or

(ii) All proceeds derived from the sale of electricity produced using geothermal resources produced from a lease.

(2) For purposes of this subparagraph, the terms “Class I lease,” “Class II lease,” and “Class III lease” have the same meanings prescribed in § 1206.351.

(i) For Class I leases, ONRR will allow free of royalty—

(A) Geothermal resources that are unavoidably lost or reinjected before use on or off the lease, as determined by the Bureau of Land Management (BLM), or that are reasonably necessary to generate plant parasitic electricity or electricity for Federal lease operations; and

(B) A reasonable amount of commercially demineralized water necessary for power plant operations or otherwise used on or for the benefit of the lease.

(ii) For Class II and Class III leases where the lessee uses geothermal resources for commercial production or generation of electricity, or where geothermal resources are sold at arm's length for the commercial production or generation of electricity, ONRR will allow free of royalty or direct use fees geothermal resources that are:

(A) Unavoidably lost or reinjected before use on or off the lease, as determined by BLM;

(B) Reasonably necessary for the lessee to generate plant parasitic electricity or electricity for Federal lease operations, as approved by BLM; or

(C) Otherwise used for Federal lease operations related to commercial production or generation of electricity, as approved by BLM.

(iii) For Class II and Class III leases where the lessee uses the geothermal resources for a direct use or in a direct use facility, as defined in § 1206.351, resources that are used to generate electricity for Federal lease operations or that are otherwise used for Federal lease operations are subject to direct use fees, except for geothermal resources that are unavoidably lost or reinjected before use on or off the lease, as determined by BLM.

(3) Royalties on byproducts are due at the time the recovered byproduct is used, sold, or otherwise finally disposed of. Byproducts produced and added to stockpiles or inventory do not require payment of royalty until the byproducts are sold, utilized, or otherwise finally disposed of. The ONRR may ask BLM to increase the lease bond to protect the lessor's interest when BLM determines that stockpiles or inventories become excessive.

(c) If BLM determines that geothermal resources (including byproducts) were avoidably lost or wasted from the lease, or that geothermal resources (including byproducts) were drained from the lease for which compensatory royalty (or compensatory fees in lieu of compensatory royalty) are due, the value of those geothermal resources, or the royalty or fees owed, will be determined under 30 CFR part 1206, subpart H.

(d) If a lessee receives insurance or other compensation for unavoidably lost geothermal resources (including byproducts), royalties at the rates specified in the lease (or fees in lieu of royalties) are due on the amount of, or as a result of, that compensation. This paragraph will not apply to compensation through self-insurance.

[72 FR 24458, May 2, 2007]

§ 1202.352 Minimum royalty.

In no event shall the lessee's annual royalty payments for any producing lease be less than the minimum royalty established by the lease.

§ 1202.353 Measurement standards for reporting and paying royalties and direct use fees.

(a) For geothermal resources used to generate electricity, you must report the quantity on which royalty is due on Form ONRR-2014 (Report of Sales and Royalty Remittance) as follows:

(1) For geothermal resources for which royalty is calculated under § 1206.352(a), you must report quantities in:

(i) Thousands of pounds to the nearest whole thousand pounds if the contract for the geothermal resources specifies delivery in terms of weight; or

(ii) Millions of Btu to the nearest whole million Btu if the sales contract for the geothermal resources specifies delivery in terms of heat or thermal energy.

(2) For geothermal resources for which royalty is calculated under § 1206.352(b), you must report the quantities in kilowatt-hours to the nearest whole kilowatt-hour.

(b) For geothermal resources used in direct use processes, you must report the quantity on which a royalty or direct use fee is due on Form ONRR-2014 in:

(1) Millions of Btu to the nearest whole million Btu if valuation is in terms of heat or thermal energy used or displaced;

(2) Millions of gallons to the nearest million gallons of geothermal fluid produced if valuation or fee calculation is in terms of volume;

(3) Millions of pounds to the nearest million pounds of geothermal fluid produced if valuation or fee calculation is in terms of mass; or

(4) Any other measurement unit ONRR approves for valuation and reporting purposes.

(c) For byproducts, you must report the quantity on which royalty is due on Form ONRR-2014 consistent with ONRR-established reporting standards.

(d) For commercially demineralized water, you must report the quantity on which royalty is due on Form ONRR-2014 in hundreds of gallons to the nearest hundred gallons.

(e) You need not report the quality of geothermal resources, including byproducts, to ONRR. However, you must maintain quality measurements for audit purposes. Quality measurements include, but are not limited to:

(1) Temperatures and chemical analyses for fluid geothermal resources; and

(2) Chemical analyses, weight percent, or other purity measurements for byproducts.

[72 FR 24458, May 2, 2007, as amended at 78 FR 30200, May 22, 2013]

§ 1202.550 How do I determine the royalty due on gas production?

If you produce gas from an Indian lease subject to this subpart, you must determine and pay royalties on gas production as specified in this section.

(a) Royalty rate. You must calculate your royalty using the royalty rate in the lease.

(b) Payment in value or in kind. You must pay royalty in value unless:

(1) The Tribal lessor requires payment in kind; or

(2) You have a lease on allotted lands and ONRR requires payment in kind.

(c) Royalty calculation. You must use the following calculations to determine royalty due on the production from or attributable to your lease.

(1) When paid in value, the royalty due is the unit value of production for royalty purposes, determined under 30 CFR part 1206, multiplied by the volume of production multiplied by the royalty rate in the lease.

(2) When paid in kind, the royalty due is the volume of production multiplied by the royalty rate.

(d) Reduced royalty rate. The Indian lessor and the Secretary may approve a request for a royalty rate reduction. In your request you must demonstrate economic hardship.

(e) Reporting and paying. You must report and pay royalties as provided in part 1218 of this title.

§ 1202.551 How do I determine the volume of production for which I must pay royalty if my lease is not in an approved Federal unit or communitization agreement (AFA)?

(a) You are liable for royalty on your entitled share of gas production from your Indian lease, except as provided in §§ 1202.555, 1202.556, and 1202.557.

(b) You and all other persons paying royalties on the lease must report and pay royalties based on your takes. If another person takes some of your entitled share but does not pay the royalties owed, you are liable for those royalties.

(c) You and all other persons paying royalties on the lease may ask ONRR for permission to report and pay royalties based on your entitlements. In that event, ONRR will provide valuation instructions consistent with this part and part 1206 of this title.

§ 1202.552 How do I determine how much royalty I must pay if my lease is in an approved Federal unit or communitization agreement (AFA)?

You must pay royalties each month on production allocated to your lease under the terms of an AFA. To determine the volume and the value of your production, you must follow these three steps:

(a) You must determine the volume of your entitled share of production allocated to your lease under the terms of an AFA. This may include production from more than one AFA.

(b) You must value the production you take using 30 CFR part 1206. If you take more than your entitled share of production, see § 1202.553 for information on how to value this production. If you take less than your entitled share of production, see § 1202.554 for information on how to value production you are entitled to but do not take.

§ 1202.553 How do I value my production if I take more than my entitled share?

If you take more than your entitled share of production from a lease in an AFA for any month, you must determine the weighted-average value of all of the production that you take using the procedures in 30 CFR part 1206, and use that value for your entitled share of production.

§ 1202.554 How do I value my production that I do not take if I take less than my entitled share?

If you take none or only part of your entitled production from a lease in an AFA for any month, use this section to value the production that you are entitled to but do not take.

(a) If you take a significant volume of production from your lease during the month, you must determine the weighted average value of the production that you take using 30 CFR part 1206, and use that value for the production that you do not take.

(b) If you do not take a significant volume of production from your lease during the month, you must use paragraph (c) or (d) of this section, whichever applies.

(c) In a month where you do not take production or take an insignificant volume, and if you would have used § 1206.172(b) to value the production if you had taken it, you must determine the value of production not taken for that month under § 1206.172(b) as if you had taken it.

(d) If you take none of your entitled share of production from a lease in an AFA, and if that production cannot be valued under § 1206.172(b), then you must determine the value of the production that you do not take using the first of the following methods that applies:

(1) The weighted average of the value of your production (under 30 CFR part 1206) in that month from other leases in the same AFA.

(2) The weighted average of the value of your production (under 30 CFR part 1206) in that month from other leases in the same field or area.

(3) The weighted average of the value of your production (under 30 CFR part 1206) during the previous month for production from leases in the same AFA.

(4) The weighted average of the value of your production (under 30 CFR part 1206) during the previous month for production from other leases in the same field or area.

(5) The latest major portion value that you received from ONRR calculated under § 1206.174 for the same ONRR-designated area.

(e) You may take less than your entitled share of AFA production for any month, but pay royalties on the full volume of your entitled share under this section. If you do, you will owe no additional royalty for that lease for that month when you later take more than your entitled share to balance your account. The provisions of this paragraph (e) also apply when the other AFA participants pay you money to balance your account.

§ 1202.555 What portion of the gas that I produce is subject to royalty?

(a) All gas produced from or allocated to your Indian lease is subject to royalty except the following:

(1) Gas that is unavoidably lost.

(2) Gas that is used on, or for the benefit of, the lease.

(3) Gas that is used off-lease for the benefit of the lease when the Bureau of Land Management (BLM) approves such off-lease use.

(4) Gas used as plant fuel as provided in § 1206.179(e).

(b) You may use royalty-free only that proportionate share of each lease's production (actual or allocated) necessary to operate the production facility when you use gas for one of the following purposes:

(1) On, or for the benefit of, the lease at a production facility handling production from more than one lease with BLM's approval.

(2) At a production facility handling unitized or communitized production.

(c) If the terms of your lease are inconsistent with this subpart, your lease terms will govern to the extent of that inconsistency.

§ 1202.556 How do I determine the value of avoidably lost, wasted, or drained gas?

If BLM determines that a volume of gas was avoidably lost or wasted, or a volume of gas was drained from your Indian lease for which compensatory royalty is due, then you must determine the value of that volume of gas under 30 CFR part 1206.

§ 1202.557 Must I pay royalty on insurance compensation for unavoidably lost gas?

If you receive insurance compensation for unavoidably lost gas, you must pay royalties on the amount of that compensation. This paragraph does not apply to compensation through self-insurance.

§ 1202.558 What standards do I use to report and pay royalties on gas?

(a) You must report gas volumes as follows:

(1) Report gas volumes and Btu heating values, if applicable, under the same degree of water saturation. Report gas volumes and Btu heating value at a standard pressure base of 14.73 psia and a standard temperature of 60 degrees Fahrenheit. Report gas volumes in units of 1,000 cubic feet (Mcf).

(2) You must use the frequency and method of Btu measurement stated in your contract to determine Btu heating values for reporting purposes. However, you must measure the Btu value at least semi-annually by recognized standard industry testing methods even if your contract provides for less frequent measurement.

(b) You must report residue gas and gas plant product volumes as follows:

(1) Report carbon dioxide (CO2), nitrogen (N2), helium (He), residue gas, and any gas marketed as a separate product by using the same standards specified in paragraph (a) of this section.

(2) Report natural gas liquid (NGL) volumes in standard U.S. gallons (231 cubic inches) at 60 degrees F.

(3) Report sulfur (S) volumes in long tons (2,240 pounds).

§ 1203.250 Advance royalty.

Provisions for the payment of advance royalty in lieu of continued operation are contained at 43 CFR 3483.4.

[54 FR 1522, Jan. 13, 1989]

§ 1203.251 Reduction in royalty rate or rental.

An application for reduction in coal royalty rate or rental shall be filed and processed in accordance with 43 CFR group 3400.

[54 FR 1522, Jan. 13, 1989]

§ 1204.1 What is the purpose of this part?

This part explains how you as a lessee or designee of a Federal onshore or Outer Continental Shelf (OCS) oil and gas lease may obtain prepayment or accounting and auditing relief for production from certain marginal properties. This part does not apply to production from Indian leases, even if the Indian lease is within an agreement that qualifies as a marginal property.

§ 1204.2 What definitions apply to this part?

Agreement means a federally approved communitization agreement or unit participating area.

Barrels of oil equivalent (BOE) means the combined equivalent production of oil and gas stated in barrels of oil. Each barrel of oil production is equal to one BOE. Also, each 6,000 cubic feet of gas production is equal to one BOE.

Base period means the 12-month period from July 1 through June 30 immediately preceding the calendar year for which you take or request marginal property relief. For example, if you request relief for calendar year 2006, your base period is July 1, 2004, through June 30, 2005.

Combined equivalent production means the total of all oil and gas production for the marginal property, stated in BOE.

Designee means the person designated by a lessee under § 1218.52 to make all or part of the royalty or other payments due on a lease on the lessee's behalf.

Producing wells means only those producing oil or gas wells that contribute to the sum of BOE used in the calculation under § 1204.4(c). Producing wells do not include injection or water wells. Wells with multiple zones commingled downhole are considered as a single well.

Property means a lease, a portion of a lease, or an agreement that may be a marginal property if it meets the qualification requirements of § 1204.4.

State concerned (State) means the State that receives a statutorily prescribed portion of the royalties from a Federal onshore or OCS lease.

§ 1204.3 What alternatives are available for marginal properties?

If you have production from a marginal property, ONRR and the State may allow you the following options:

(a) Prepay royalty. ONRR and the State may allow you to make a lump-sum advance payment of royalties instead of monthly royalty payments for the remainder of the lease term. See subpart B for prepayment of royalty requirements.

(b) Take accounting and auditing relief. ONRR and the State may allow various accounting and auditing relief options to encourage you to continue to produce and develop your marginal property. See subpart C for accounting and auditing relief requirements.

§ 1204.4 What is a marginal property under this part?

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

If your lease is . . . | Then . . . | And . . .

(1) Not in an agreement | The lease must qualify as a marginal property under paragraph (b) of this section

(2) Entirely or partly committed to one agreement | The entire agreement must qualify as a marginal property under paragraph (b) of this section | 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.

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

(4) Partly committed to an agreement and you have production from the part of the lease that is not committed to the agreement | The part of the lease that is not committed to the agreement must qualify separately as a marginal property under paragraph (b) of this section

(b) To qualify as a marginal property for a calendar year, the combined equivalent production of the property during the base period must equal an average daily well production of less than 15 barrels of oil equivalent (BOE) per well per day calculated under paragraph (c) of this section.

(c) To determine the average daily well production for a property, divide the sum of the BOE for all producing wells on the property during the base period by the sum of the number of days that each of those wells actually produced during the base period. If the property is an agreement, your calculation under this paragraph must include all wells included in the agreement, even if they are not on a Federal onshore or OCS lease.

§ 1204.5 What statutory requirements must I meet to obtain royalty prepayment or accounting and auditing relief?

(a) ONRR and the State may allow royalty prepayment or accounting and auditing relief for your marginal property production if ONRR and the State jointly determine that the prepayment or accounting and auditing relief is in the best interests of the Federal Government and the State to:

(1) Promote production;

(2) Reduce the administrative costs of ONRR and the State; and

(3) Increase net receipts to the Federal Government and the State.

(b) At any time, if ONRR and the State determine that either prepayment or accounting and auditing relief no longer meets the criteria in paragraph (a) of this section, ONRR, with the State's concurrence, may discontinue any prepayment or accounting and auditing relief options granted for production from any marginal property.

(1) ONRR will provide you written notice of the decision to discontinue relief.

(i) If you took the cumulative reports and payments relief option under § 1204.202, your relief will terminate at the end of the calendar year in which you received the notice.

(ii) If you were approved for prepayment relief under subpart B of this part or other relief under § 1204.203, ONRR's notice will tell you when your relief terminates.

(2) ONRR's decision to discontinue relief is not subject to administrative appeal.

§ 1204.6 May I appeal if ONRR denies my request for prepayment or other relief?

If ONRR denies your request for prepayment relief under subpart B of this part or other relief under § 1204.203, you may appeal under 30 CFR part 1290.

§ 1204.200 What is the purpose of this subpart?

This subpart explains how you as a lessee or designee may obtain accounting and auditing relief for your Federal onshore or OCS lease production from a marginal property. The two types of accounting and auditing relief that you can receive under this subpart are cumulative reports and payment relief (explained in § 1204.202) and other accounting and auditing relief appropriate for your property (explained in § 1204.203).

§ 1204.201 Who may obtain accounting and auditing relief?

(a) You may obtain accounting and auditing relief under this subpart:

(1) If you are a lessee or a designee for a Federal lease with production from a property that qualifies as a marginal property under § 1204.4;

(2) If you meet any additional requirements for specific types of relief under this subpart; and

(3) Only for the fractional interest in production from the marginal property for which you report and pay royalty. You may obtain relief even if the other lessees or designees for your lease or agreement do not request relief.

(b) You may not obtain one or both of the relief options specified in this subpart on any portion of production from a marginal property if:

(1) The marginal property covers multiple States; and

(2) One of the States determines under § 1204.208 that it will not allow the relief option you seek.

§ 1204.202 What is the cumulative royalty reports and payments relief option?

(a) The cumulative royalty reports and payments relief option allows you to submit one royalty report and payment annually for production during a calendar year. You are eligible for this option only if the total volume produced from the marginal property (not just your share of the production) is 1,000 BOE or less during the base period.

(b) To use the cumulative royalty reports and payments relief option, you must do all of the following:

(1) Notify ONRR in writing by January 31 of the calendar year for which you begin taking your relief. See § 1204.205(a) for what your notification must contain;

(2) Submit your royalty report and payment in accordance with 30 CFR 1218.51(g) by the end of February of the year following the calendar year for which you reported annually, unless you have an estimated payment on file. If you have an estimated payment on file, you must submit your royalty report and payment by the end of March of the year following the calendar year for which you reported annually;

(3) Use the sales month prior to the month that you submit your annual report and payment under paragraph (b)(2) of this section on your Report of Sales and Royalty Remittance, Form ONRR-2014, for the entire previous calendar year's production for which you are paying annually. (For example, for a report in February use January as your sales month, and for a report in March use February as your sales month, to report production for the entire previous calendar year for which you are paying annually);

(4) Report one line of cumulative royalty information on Form ONRR-2014 for the calendar year, the same as if it were a monthly report; and

(5) Report allowances on Form ONRR-2014 on the same annual basis as the royalties for your marginal property production.

(c) If you do not pay your royalty by the date due in paragraph (b) of this section, you will owe late payment interest determined under 30 CFR 1218.54 from the date your payment was due under this section until the date ONRR receives it.

(d) If you take relief you are not qualified for, you may be liable for civil penalties. Also you must:

(1) Pay ONRR late payment interest determined under § 1218.54 from the date your payment was due until the date ONRR receives it; and

(2) Amend your Form ONRR-2014 to reflect the required monthly reporting.

(e) If you dispose of your ownership interest in a marginal property for which you have taken relief under this section (or if you are a designee who reports and pays royalty for a lessee who has disposed of its ownership interest), you must:

(1) Report and pay royalties for the portion of the calendar year for which you had an ownership interest; and

(2) Make the report and payment by the end of the month after you dispose of the ownership interest in the marginal property. If you do not report and pay timely, you will owe interest determined under § 1218.54 from the date the payment was due under this section.

[69 FR 55088, Sept. 13, 2004, as amended at 78 FR 30200, May 22, 2013]

§ 1204.203 What is the other relief option?

(a) Under this relief option, you may request any type of accounting and auditing relief that is appropriate for production from your marginal property, provided it is not prohibited under § 1204.204 and meets the statutory requirements of § 1204.5. Examples of relief options you could request are:

(1) To report and pay royalties using a valuation method other than that required under 30 CFR part 1206 that approximates royalties payable under that part 1206; and

(2) To reduce your royalty audit burden. However, ONRR will not consider any request that eliminates ONRR's or the States' right to audit.

(b) You must request approval from ONRR under § 1204.205(b), and receive approval under § 1204.206 before taking relief under this option.

§ 1204.204 What accounting and auditing relief will ONRR not allow?

ONRR will not approve your request for accounting and auditing relief under this subpart if your request:

(a) Prohibits ONRR or the State from conducting any form of audit;

(b) Permanently relieves you from making future royalty reports or payments;

(c) Provides for less frequent royalty reports and payments than annually;

(d) Provides for you to submit royalty reports and payments at separate times;

(e) Impairs ONRR's ability to properly or efficiently account for or distribute royalties;

(f) Requests relief for a lease under which the Federal Government takes its royalties in kind;

(g) Alters production reporting requirements;

(h) Alters lease operation or safety requirements;

(i) Conflicts with rent, minimum royalty, or lease requirements; or

(j) Requests relief for production from a marginal property located in whole or in part in a State that has determined that it will not allow such relief under § 1204.208.

§ 1204.205 How do I obtain accounting and auditing relief?

(a) To take cumulative reports and payments relief under § 1204.202, you must notify ONRR in writing by January 31 of the calendar year for which you begin taking your relief.

(1) Your notification must contain:

(i) Your company name, ONRR-assigned payor code, address, phone number, and contact name; and

(ii) The specific ONRR lease number and agreement number, if applicable.

(2) You may file a single notification for multiple marginal properties.

(b) To obtain other relief under § 1204.203, you must file a written request for relief with ONRR.

(1) Your request must contain:

(i) Your company name, ONRR-assigned payor code, address, phone number, and contact name;

(ii) The ONRR lease number and agreement number, if applicable; and

(iii) A complete and detailed description of the specific accounting or auditing relief you seek.

(2) You may file a single request for multiple marginal properties if you are requesting the same relief for all properties.

§ 1204.206 What will ONRR do when it receives my request for other relief?

When ONRR receives your request for other relief under § 1204.205(b), it will notify you in writing as follows:

(a) If your request for relief is complete, ONRR may either approve, deny, or modify your request in writing after consultation with any State required under § 1204.207(b).

(1) If ONRR approves your request for relief, ONRR will notify you of the effective date of your accounting or auditing relief and other specifics of the relief approved.

(2) If ONRR denies your relief request, ONRR will notify you of the reasons for denial and your appeal rights under § 1204.6.

(3) If ONRR modifies your relief request, ONRR will notify you of the modifications.

(i) You have 60 days from your receipt of ONRR's notice to either accept or reject any modification(s) in writing.

(ii) If you reject the modification(s) or fail to respond to ONRR's notice, ONRR will deny your relief request. ONRR will notify you in writing of the reasons for denial and your appeal rights under § 1204.6.

(b) If your request for relief is not complete, ONRR will notify you in writing that your request is incomplete and identify any missing information.

(1) You must submit the missing information within 60 days of your receipt of ONRR's notice that your request is incomplete.

(2) After you submit all required information, ONRR may approve, deny, or modify your request for relief under paragraph (a) of this section.

(3) If you do not submit all required information within 60 days of your receipt of ONRR's notice that your request is incomplete, ONRR will deny your relief request. ONRR will notify you in writing of the reasons for denial and your appeal rights under § 1204.6.

(4) You may submit a new request for relief under this subpart at any time after ONRR returns your incomplete request.

[69 FR 55088, Sept. 13, 2004, as amended at 78 FR 30200, May 22, 2013]

§ 1204.207 Who will approve, deny, or modify my request for accounting and auditing relief?

(a) If there is not a State concerned for your marginal property, only ONRR will decide whether to approve, deny, or modify your relief request.

(b) If there is a State concerned for your marginal property that has determined in advance under § 1204.208 that it will allow either or both of the relief options under this subpart, ONRR will decide whether to approve, deny, or modify your relief request after consulting with the State concerned.

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

§ 1204.208 May a State decide that it will or will not allow one or both of the relief options under this subpart?

(a) A State may decide in advance that it will or will not allow one or both of the relief options specified in this subpart for a particular calendar year. If a State decides that it will not consent to one or both of the relief options, ONRR will not grant that type of marginal property relief.

(b) To help States decide whether to allow one or both of the relief options specified in this subpart, for each calendar year ONRR will send States a Report of Marginal Properties by October 1 preceding the calendar year.

(c) If a State decides under paragraph (a) of this section that it will or will not allow one or both of the relief options in this subpart during the next calendar year, within 30 days of the State's receipt of the Report of Marginal Properties under paragraph (b) of this section, the State must:

(1) Notify the Director for Office of Natural Resources Revenue, in writing, of its intent to allow or not allow one or both of the relief options under this subpart; and

(2) Specify in its notice of intent to ONRR which relief option(s) it will allow or not allow.

(d) If a State decides in advance under paragraph (a) of this section that it will not allow one or both of the relief options specified in this subpart, it may decide for subsequent calendar years that it will allow one or both of the relief options in this subpart. If it so decides, within 30 days of the State's receipt of the Report of Marginal Properties under paragraph (b) of this section, the State must:

(1) Notify the Director for Office of Natural Resources Revenue, in writing, of its intent to allow one or both of the relief options allowed under this subpart during the next calendar year; and

(2) Specify in its notice of intent to ONRR which relief option(s) it will allow.

(e) If a State does not notify ONRR under paragraph (c) or (d) of this section, the State will be deemed to have decided not to allow either of the relief options under this subpart for the next calendar year.

(f) ONRR will publish a notice of the State's intent to allow or not allow certain relief options under this section in the Federal Register no later than 30 days before the beginning of the applicable calendar year.

§ 1204.209 What if a property ceases to qualify for relief obtained under this subpart?

(a) A marginal property must qualify for relief under this subpart for each calendar year based on production during the base period for that calendar year. The notice or request you provided to ONRR under § 1204.205 for the first calendar year that the property qualified for relief remains effective for successive calendar years if the property continues to qualify.

(b) If a property is no longer eligible for relief for any reason during a calendar year other than the reason under § 1204.210 or paragraph (c) of this section, the relief for the property terminates as of December 31 of that calendar year. You must notify ONRR in writing by December 31 that the relief for the property has terminated.

(c) If you dispose of your interest in a marginal property during the calendar year, your relief terminates as of the end of the sales month in which you disposed of the property. Report and pay royalties for your production using the procedures in § 1204.202(e).

§ 1204.210 What if a property is approved as part of a nonqualifying agreement?

If the Bureau of Land Management (BLM) or BOEM retroactively approves a marginal property that qualified for relief for inclusion as part of an agreement that does not qualify for relief under this subpart, the property no longer qualifies for relief under this subpart then:

(a) ONRR will not retroactively rescind the marginal property relief for production from your property under § 1204.211;

(b) Your marginal property relief terminates as of December 31 of the calendar year that you receive the BLM or BOEM approval of your marginal property as part of a nonqualifying agreement; and

(c) For the calendar year in which you receive the BLM or BOEMRE approval, and for any previous period affected by the approval, the volumes on which you report and pay royalty for your lease must be amended to reflect all volumes produced on or allocated to your lease under the nonqualifying agreement as modified by BLM or BOEM. Report and pay royalties for your production using the procedures in § 1204.202(b).

(d) If you owe additional royalties based on the retroactive agreement approval and do not pay your royalty by the date due in § 1204.202(b), you will owe late payment interest determined under § 1218.54 from the date your payment was due under § 1204.202 (b)(2) until the date ONRR receives it.

[69 FR 55088, Sept. 13, 2004, as amended at 78 FR 30200, May 22, 2013]

§ 1204.211 When may ONRR rescind relief for a property?

(a) ONRR may retroactively rescind the relief for your property if ONRR determines that your property was not eligible for the relief obtained under this subpart because:

(1) You did not submit a notice or request for relief under § 1204.205;

(2) You submitted erroneous information in the notice or request for relief you provided to ONRR under § 1204.205 or in your royalty or production reports; or

(3) Your property is no longer eligible for relief because production increased, but you failed to provide the notice required under § 1204.209(b).

(b) ONRR may rescind relief for your property if ONRR decides to take royalty in kind.

§ 1204.212 What if I took relief for which I was ineligible?

If you took relief under this subpart for a period for which you were not eligible, you:

(a) May owe additional royalties and late payment interest determined under § 1218.54 from the date your additional payments were due until the date ONRR receives them; and

(b) May be subject to civil penalties.

§ 1204.213 May I obtain relief for a property that benefits from other Federal or State incentive programs?

You may obtain accounting and auditing relief for production from a marginal property under this subpart even if the property benefits from other Federal or State production incentive programs.

§ 1204.214 Is minimum royalty due on a property for which I took relief?

(a) If you took cumulative royalty reports and payment relief on a property under this subpart, minimum royalty is still due for that property by the date prescribed in your lease and in the amount prescribed therein.

(b) If you pay minimum royalty on production from a marginal property during a calendar year for which you are taking cumulative royalty reports and payment relief, and:

(1) The annual payment you owe under this subpart is greater than the minimum royalty you paid, you must pay the difference between the minimum royalty you paid and your annual payment due under this subpart; or

(2) The annual payment you owe under this subpart is less than the minimum royalty you paid, you are not entitled to a credit because you must pay at least the minimum royalty amount on your lease each year.

§ 1204.215 Are the information collection requirements in this subpart approved by the Office of Management and Budget (OMB)?

OMB approved the information collection requirements contained in this subpart under 44 U.S.C. 3501 et seq. ONRR identifies the approved OMB control number in 30 CFR 1210.10.

[78 FR 30200, May 22, 2013]

§ 1206.10 Has the Office of Management and Budget (OMB) approved the information collection requirements in this part?

OMB has approved the information collection requirement contained in this part under 44 U.S.C. 3501 et seq. See 30 CFR part 1210 for details concerning the estimated reporting burden and how to comment on the accuracy of the burden estimate.

§ 1206.20 What definitions apply to this part?

The definitions in this section do not apply to subparts F and J of this part.

Affiliate means a person who controls, is controlled by, or is under common control with another person. For the 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 non-control that ONRR may rebut.

(2) If there is ownership or common ownership of 10 through 50 percent of the voting securities or instruments of ownership, or other forms of ownership, of another person, ONRR will consider each of the following factors to determine if 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, if a person is the greatest single owner, or if there is an opposing voting bloc of greater ownership.

(iii) Operation of a lease, plant, pipeline, or other facility.

(iv) The extent of others owners' participation in operations and day-to-day management of a lease, plant, or other facility.

(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.

Area means a geographic region at least as large as the limits of an oil and/or gas field, in which oil and/or gas lease products have similar quality and economic characteristics. Area boundaries are not officially designated and the areas are not necessarily named.

Arm's-length-contract means a contract or agreement 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 an examination, conducted under the generally accepted Governmental Auditing Standards, of royalty reporting and payment compliance activities of lessees, designees or other persons who pay royalties, rents, or bonuses on Federal leases or Indian leases.

BIA means the Bureau of Indian Affairs of the Department of the Interior.

BLM means the Bureau of Land Management of the Department of the Interior.

BOEM means the Bureau of Ocean Energy Management of the Department of the Interior.

BSEE means the Bureau of Safety and Environmental Enforcement of the Department of the Interior.

Compression means the process of raising the pressure of gas.

Condensate means liquid hydrocarbons (normally exceeding 40 degrees of API gravity) recovered at the surface without processing. Condensate is the mixture of liquid hydrocarbons resulting from condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground reservoir.

Constraint means a reduction in, or elimination of, gas flow, deliveries, or sales required by the delivery system.

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 whom 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 (such as 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.

FERC means Federal Energy Regulatory Commission.

Field means a geographic region situated over one or more subsurface oil and gas reservoirs and encompassing at least the outermost boundaries of all oil and gas accumulations known within those reservoirs, vertically projected to the land surface. State oil and gas regulatory agencies usually name onshore fields and designate their official boundaries. BOEM names and designates boundaries of OCS fields.

Gas means any fluid, either combustible or non-combustible, hydrocarbon or non-hydrocarbon, 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 or treatment point on the lease, unit, or communitized area, or to a central accumulation or treatment point off of the lease, unit, or communitized area that BLM or BSEE approves for onshore and offshore leases, respectively, including any movement of bulk production from the wellhead to a platform offshore.

Geographic region means, for Federal gas, an area 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 and economic characteristics.

Gross proceeds means the total monies and other consideration accruing for the disposition of any of the following:

(1) Oil. Gross proceeds also include, but are not limited to, the following examples:

(i) Payments for services such as dehydration, marketing, measurement, or gathering which the lessee must perform at no cost to the Federal Government.

(ii) The value of services, such as salt water disposal, that the producer normally performs but that the buyer performs on the producer's behalf.

(iii) Reimbursements for harboring or terminalling fees, royalties, and any other reimbursements.

(iv) Tax reimbursements, even though the Federal royalty interest may be exempt from taxation.

(v) Payments made to reduce or buy down the purchase price of oil produced in later periods by allocating such payments over the production whose price that the payment reduces and including the allocated amounts as proceeds for the production as it occurs.

(vi) Monies and all other consideration to which a seller is contractually or legally entitled but does not seek to collect through reasonable efforts.

(2) Gas, residue gas, and gas plant products. Gross proceeds also include, but are not limited to, the following examples:

(i) Payments for services such as dehydration, marketing, measurement, or gathering that the lessee must perform at no cost to the Federal Government.

(ii) Reimbursements for royalties, fees, and any other reimbursements.

(iii) Tax reimbursements, even though the Federal royalty interest may be exempt from taxation.

(iv) Monies and all other consideration to which a seller is contractually or legally entitled, but does not seek to collect through reasonable efforts.

Index means:

(1) For gas, the calculated composite price ($/MMBtu) of spot market sales that a publication that meets ONRR-established criteria for acceptability at the index pricing point publishes

(2) For oil, the calculated composite price ($/barrel) of spot market sales that a publication that meets ONRR-established criteria for acceptability at the index pricing point publishes.

Index pricing point means any point on a pipeline for which there is an index, which ONRR-approved publications may refer to as a trading location.

Index zone means a field or an area with an active spot market and published indices applicable to that field or an area that is acceptable to ONRR under § 1206.141(d)(1).

Indian Tribe means any Indian Tribe, band, nation, pueblo, community, rancheria, colony, or other group of Indians for which any minerals or interest in minerals is held in trust by the United States or is subject to Federal restriction against alienation.

Individual Indian mineral owner means any Indian for whom minerals or an interest in minerals is held in trust by the United States or who holds title subject to Federal restriction against alienation.

Keepwhole contract means a processing agreement under which the processor delivers to the lessee a quantity of gas after processing equivalent to the quantity of gas that the processor received from the lessee prior to processing, normally based on heat content, less gas used as plant fuel and gas unaccounted for and/or lost. This includes, but is not limited to, agreements under which the processor retains all NGLs that it recovered from the lessee's gas.

Lease means any contract, profit-sharing arrangement, joint venture, or other agreement issued or approved by the United States under any mineral leasing law, including the Indian Mineral Development Act, 25 U.S.C. 2101-2108, that authorizes exploration for, extraction of, or removal of lease products. Depending on the context, lease may also refer to the land area that the authorization covers.

Lease products mean any leased minerals, attributable to, originating from, or allocated to a lease or produced in association with a lease.

Lessee means any person to whom the United States, an Indian Tribe, and/or individual Indian mineral owner issues a lease, and any person who has been assigned all or a part of record title, operating rights, or an obligation to make royalty or other payments required by the lease. Lessee includes any person who has an interest in a lease.

Like quality means similar chemical and physical characteristics.

Location differential means an amount paid or received (whether in money or in barrels of oil) under an exchange agreement that results from differences in location between oil delivered in exchange and oil received in the exchange. A location differential may represent all or part of the difference between the price received for oil delivered and the price paid for oil received under a buy/sell exchange agreement.

Market center means a major point that ONRR recognizes for oil sales, refining, or transshipment. Market centers generally are locations where ONRR-approved publications publish oil spot prices.

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 for Federal oil and gas.

Mine means an underground or surface excavation or series of excavations and the surface or underground support facilities that contribute directly or indirectly to mining, production, preparation, and handling of lease products.

Misconduct means any failure to perform a duty owed to the United States under a statute, regulation, or lease, or unlawful or improper behavior, regardless of the mental state of the lessee or any individual employed by or associated with the lessee.

Net output means the quantity of gas residue gas and each gas plant product that a processing plant produces.

Netting means reducing the reported sales value to account for an allowance instead of reporting the allowance as a separate entry on the Report of Sales and Royalty Remittance (Form ONRR-2014) or the Solid Minerals Production and Royalty Report (Form ONRR-4430).

NGLs means Natural Gas Liquids.

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) First, 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.

(2) Second, divide the sum by the number of days on which those prices are published (excluding weekends and holidays).

Oil means a mixture of hydrocarbons that existed in the liquid phase in natural underground reservoirs, remains liquid at atmospheric pressure after passing through surface separating facilities, and is marketed or used as a liquid. Condensate recovered in lease separators or field facilities is oil.

ONRR means the Office of Natural Resources Revenue of the Department of the Interior.

ONRR-approved commercial price bulletin means a publication that ONRR approves for determining NGLs prices.

ONRR-approved publication means:

(1) For oil, a publication that ONRR approves for determining ANS spot prices or WTI differentials.

(2) For gas, a publication that ONRR approves for determining index pricing points.

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.

Payor means any person who reports and pays royalties under a lease, regardless of whether that person also is a lessee.

Person means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity).

Processing means any process designed to remove elements or compounds (hydrocarbon and non-hydrocarbon) 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. The use of a Joule-Thomson (JT) unit to remove NGLs from gas is considered processing regardless of where the JT unit is located, provided that you market the NGLs as NGLs.

Processing allowance means a deduction in determining royalty value for the reasonable, actual costs the lessee incurs for processing gas.

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.

Residue gas means that hydrocarbon gas consisting principally of methane resulting from processing gas.

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 December. December was the prompt month (for year 2011) from October 21 through November 18. January was the first month following the month of production, and February was the second month following the month of production. P0, therefore, is the average of the daily NYMEX settlement prices for deliveries during December published for each business day between October 21 and November 18. P1 is the average of the daily NYMEX settlement prices for deliveries during January published for each business day between October 21 and November 18. P2 is the average of the daily NYMEX settlement prices for deliveries during February published for each business day between October 21 and November 18. In this example, assume that P0 = $95.08 per bbl, P1 = $95.03 per bbl, and P2 = $94.93 per bbl. In this example (a declining market), Roll = .6667 × ($95.08−$95.03) + .3333 × ($95.08−$94.93) = $0.03 + $0.05 = $0.08. 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 November. November was the prompt month (for year 2012) from September 21 through October 22. December was the first month following the month of production, and January was the second month following the month of production. P0, therefore, is the average of the daily NYMEX settlement prices for deliveries during November published for each business day between September 21 and October 22. P1 is the average of the daily NYMEX settlement prices for deliveries during December published for each business day between September 21 and October 22. P2 is the average of the daily NYMEX settlement prices for deliveries during January published for each business day between September 21 and October 22. In this example, assume that P0 = $91.28 per bbl, P1 = $91.65 per bbl, and P2 = $92.10 per bbl. In this example (a rising market), Roll = .6667 × ($91.28−$91.65) + .3333 × ($91.28−$92.10) = (−$0.25) + (−$0.27) = (−$0.52). 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, gas, or gas plant product to the buyer and does not retain any related rights, such as the right to buy back similar quantities of oil, gas, or gas plant product from the buyer elsewhere;

(2) The buyer pays money or other consideration for the oil, gas, or gas plant product; and

(3) The parties' intent is for a sale of the oil, gas, or gas plant product to occur.

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 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.

(3) There is no obligation or implied intent to continue to sell in subsequent periods.

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 website, www.cmegroup.com, in which case, the NYMEX definition will apply.

Transportation allowance means a deduction in determining royalty value for the reasonable, actual costs that the lessee incurs for moving:

(1) Oil to a point of sale or delivery off of the lease, unit area, or communitized area. The transportation allowance does not include gathering costs.

(2) Unprocessed gas, residue gas, or gas plant products to a point of sale or delivery off of the lease, unit area, or communitized area, or away from a processing plant. 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.

[85 FR 62019, Oct. 1, 2020, as amended at 88 FR 47005, July 21, 2023]

§ 1206.50 What is the purpose of this subpart?

(a) This subpart applies to all oil produced from Indian (Tribal and allotted) oil and gas leases (except leases on the Osage Indian Reservation, Osage County, Oklahoma). This subpart does not apply to Federal leases, including Federal leases for which revenues are shared with Alaska Native Corporations. This subpart:

(1) Explains how you as a lessee must calculate the value of production for royalty purposes consistent with Indian mineral leasing laws, other applicable laws, and lease terms.

(2) Ensures the United States discharges its trust responsibilities for administering Indian oil and gas leases under the governing Indian mineral leasing laws, treaties, and lease terms.

(b) If you dispose of or report 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 the regulations in this subpart are inconsistent with:

(1) A Federal statute;

(2) A settlement agreement between the United States, Indian lessor, and a lessee resulting from administrative or judicial litigation;

(3) A written agreement between the Indian lessor, lessee, and the ONRR Director establishing a method to determine the value of production from any lease that ONRR expects at least would approximate the value established under this subpart; or

(4) An express provision of an oil and gas lease subject to this subpart then the statute, settlement agreement, written agreement, or lease provision will govern to the extent of the inconsistency.

(d) ONRR or Indian Tribes, which have a cooperative agreement with ONRR to audit under 30 U.S.C. 1732, may audit, or perform other compliance reviews, and require a lessee to adjust royalty payments and reports.

§ 1206.51 What definitions apply to this subpart?

For purposes of this subpart:

Affiliate means a person who controls, is controlled by, or is under common control with another person.

(1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10 percent constitutes a presumption of non-control that ONRR may rebut.

(2) If there is ownership or common ownership of 10 through 50 percent of the voting securities or instruments of ownership, or other forms of ownership, of another person, ONRR will consider the following factors in determining whether there is control in a particular case:

(i) The extent to which there are common officers or directors;

(ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership:

(A) The percentage of ownership or common ownership;

(B) The relative percentage of ownership or common ownership compared to the percentage(s) of ownership by other persons;

(C) Whether a person is the greatest single owner; and

(D) Whether there is an opposing voting bloc of greater ownership;

(iii) Operation of a lease, plant, or other facility;

(iv) The extent of participation by other owners in operations and day-to-day management of a lease, plant, or other facility; and

(v) Other evidence of power to exercise control over or common control with another person.

(3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or marriage, are affiliates.

Area means a geographic region at least as large as the defined limits of an oil and/or gas field in which oil and/or gas lease products have similar quality, economic, and legal characteristics.

Arm's-length contract means a contract or agreement between independent persons who are not affiliates and who have opposing economic interests regarding that contract. To be considered arm's-length for any production month, a contract must satisfy this definition for that month, as well as when the contract was executed.

Audit means a review, conducted under the generally accepted Governmental Auditing Standards, of royalty reporting and payment activities of lessees, designees, or other persons who pay royalties, rents, or bonuses on Indian leases.

BLM means the Bureau of Land Management of the Department of the Interior.

Condensate means liquid hydrocarbons (generally exceeding 40 degrees of API gravity) recovered at the surface without resorting to processing. Condensate is the mixture of liquid hydrocarbons that results from condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground reservoir.

Contract means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.

Designated area means an area that ONRR designates for purposes of calculating Location and Crude Type Differentials applied to an IBMP value. ONRR will post designated areas on our Web site at www.onrr.gov. ONRR will monitor the market activity in the designated areas and, if necessary, hold a technical conference to review, modify, or add a particular designated area. ONRR will post any change to the designated areas on our Web site at www.onrr.gov. Criteria to determine any future changes to designated areas include, but are not limited to: Markets served, examples include refineries and/or market centers, such as Cushing, OK; access to markets, examples include access to similar infrastructure, such as pipelines, rail lines, and trucking; and/or similar geography, examples include no challenging geographical divides, large rivers, and/or mountains.

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, as well as other consideration(s). Exchange agreements:

(1) May or may not specify prices for the oil involved;

(2) Frequently specify dollar amounts reflecting location, quality, or other differentials;

(3) Include buy/sell agreements, which specify prices to be paid at each exchange point and may appear to be two separate sales within the same agreement or in separate agreements; and

(4) May include, but are not limited to, exchanges of produced oil for specific types of oil (e.g. WTI); exchanges of produced oil for other oil at other locations (location trades); exchanges of produced oil for other grades of oil (grade trades); and multi-party exchanges.

Field means a geographic region situated over one or more subsurface oil and gas reservoirs encompassing at least the outermost boundaries of all oil and gas accumulations known to be within those reservoirs vertically projected to the land surface. Onshore fields usually are given names, and their official boundaries are often designated by oil and gas regulatory agencies in the respective States in which the fields are located.

Gathering means the movement of lease production to a central accumulation or treatment point on the lease, unit, or communitized area or to a central accumulation or treatment point off of the lease, unit, or communitized area, as BLM operations personnel approve.

Gross proceeds means the total monies and other consideration accruing for the disposition of oil produced. Gross proceeds also include, but are not limited to, the following examples:

(1) Payments for services, such as dehydration, marketing, measurement, or gathering that the lessee must perform—at no cost to the lessor—in order to put the production into marketable condition;

(2) The value of services to put the production into marketable condition, such as salt water disposal, that the lessee normally performs but that the buyer performs on the lessee's behalf

(3) Reimbursements for harboring or terminalling fees;

(4) Tax reimbursements, even though the Indian royalty interest may be exempt from taxation;

(5) Payments made to reduce or buy down the purchase price of oil to be produced in later periods by allocating those payments over the production whose price the payment reduces and including the allocated amounts as proceeds for the production as it occurs; and

(6) Monies and all other consideration to which a seller is contractually or legally entitled but does not seek to collect through reasonable efforts.

IBMP means the Index-Based Major Portion value calculated under § 1206.54.

Indian Tribe means any Indian Tribe, band, nation, pueblo, community, rancheria, colony, or other group of Indians for which any minerals or interest in minerals is held in trust by the United States or that is subject to Federal restriction against alienation.

Individual Indian mineral owner means any Indian for whom minerals or an interest in minerals is held in trust by the United States or who holds title subject to Federal restriction against alienation.

Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States under an Indian mineral leasing law that authorizes exploration for, development or extraction of, or removal of lease products. Depending on the context, lease may also refer to the land area that the authorization covers.

Lease products means any leased minerals attributable to, originating from, or allocated to Indian leases.

Lessee means any person to whom the United States, a Tribe, or individual Indian mineral owner issues a lease and any person who has been assigned an obligation to make royalty or other payments required by the lease. Lessee includes:

(1) Any person who has an interest in a lease (including operating rights owners).

(2) An operator, purchaser, or other person with no lease interest who reports and/or makes royalty payments to ONRR or the lessor on the lessee's behalf.

Lessor means an Indian Tribe or individual Indian mineral owner who has entered into a lease.

Like-quality oil means oil that has similar chemical and physical characteristics.

Location and Crude Type Differential (LCTD) means the difference in value between the NYMEX Calendar Monthly Average (CMA) and the value that approximates the monthly Major Portion Price for any given month, designated area, and crude oil type.

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.

Major Portion Price means the highest price paid or offered at the time of production for the major portion of oil produced from the same designated area for the same crude oil type.

Marketable condition means lease products that are sufficiently free from impurities and otherwise in a condition that they will be accepted by a purchaser under a sales contract typical for the field or area.

Net means to reduce the reported sales value to account for transportation instead of reporting a transportation allowance as a separate entry on Form ONRR-2014.

NYMEX Calendar Month Average Price means the average of the New York Mercantile Exchange (NYMEX) daily settlement prices for light sweet oil delivered at Cushing, Oklahoma, calculated as follows:

(1) Sum the prices published for each day during the calendar month of production (excluding weekends and holidays) for oil to be delivered in the nearest month of delivery for which NYMEX futures prices are published corresponding to each such day.

(2) Divide the sum by the number of days on which those prices are published (excluding weekends and holidays).

Oil means a mixture of hydrocarbons that existed in the liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities and is marketed or used as such. Condensate recovered in lease separators or field facilities is considered to be oil.

ONRR means the Office of Natural Resources Revenue of the Department of the Interior.

Operating rights owner, also known as a working interest owner, means any person who owns operating rights in a lease subject to this subpart. A record title owner is the owner of operating rights under a lease until the operating rights have been transferred from record title (see Bureau of Land Management regulations at 43 CFR 3100.0-5(d)).

Person means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity).

Processing means any process designed to remove elements or compounds (hydrocarbon and non-hydrocarbon) from gas, including absorption, adsorption, or refrigeration. Field processes that normally take place on or near the lease, such as natural pressure reduction, mechanical separation, heating, cooling, dehydration, and compression, are not considered processing. The changing of pressures and/or temperatures in a reservoir is not considered processing.

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.

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). ONRR reserves the option of terminating the use of the roll when ONRR believes that the roll is no longer a common industry practice. ONRR also retains the option to redefine how to calculate the roll to comport with changes in industry practice. To terminate or otherwise redefine how to calculate the roll, ONRR will explain its rationale for terminating or redefining how to calculate the roll by publishing a notice in the Federal Register, to provide an opportunity for comment.

(1) Example 1: Prices in out months are lower going forward. The month of production for which you must determine royalty value is December 2012. December was the prompt month from October 23 through November 20. January was the first month following the month of production, and February was the second month following the month of production. P0, therefore, is the average of the daily NYMEX settlement prices for deliveries during December published for each business day between October 23 and November 20. P1 is the average of the daily NYMEX settlement prices for deliveries during January published for each business day between October 23 and November 20. P2 is the average of the daily NYMEX settlement prices for deliveries during February published for each business day between October 23 and November 20. In this example, assume that P0 = $95.08 per bbl; P1 = $95.03 per bbl; and P2 = $94.93 per bbl. In this example (a declining market), Roll = .6667 × ($95.08−$95.03) + .3333 × ($95.08−$94.93) = $0.03 + $0.05 = $0.08. 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 November 2012. November was the prompt month from September 21 through October 22. December was the first month following the month of production, and January was the second month following the month of production. P0, therefore, is the average of the daily NYMEX settlement prices for deliveries during November published for each business day between September 21 and October 22. P1 is the average of the daily NYMEX settlement prices for deliveries during December published for each business day between September 21 and October 22. P2 is the average of the daily NYMEX settlement prices for deliveries during January published for each business day between September 21 and October 22. In this example, assume that P0 = $91.28 per bbl; P1 = $91.65 per bbl; and P2 = $92.10 per bbl. In this example (a rising market), Roll = .6667 × ($91.28−$91.65) + .3333 × ($91.28−$92.10) = (−$0.25) + (−$0.27) = (−$0.52). 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.

(3) The parties' intent is for a sale of the oil to occur.

Sales type code means the contract type or general disposition (e.g. arm's-length or non-arm's-length) of production from the lease. The sales type code applies to the sales contract, or other disposition, and not to the arm's-length or non-arm's-length nature of a transportation allowance.

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 of the lease, unit area, or communitized area. The transportation allowance does not include gathering costs.

WTI means West Texas Intermediate.

You means a lessee, operator, or other person who pays royalties under this subpart.

§ 1206.52 How do I calculate royalty value for oil that I or my affiliate sell(s) or exchange(s) under an arm's-length contract?

(a) The value of production for royalty purposes for your lease is the higher of either the value determined under this section or the IBMP value calculated under § 1206.54. The value of oil under this section for royalty purposes is the gross proceeds accruing to you or your affiliate under the arm's-length contract, less applicable allowances determined under § 1206.56 or § 1206.57. You must use this paragraph (a) to value oil when:

(1) You sell under an arm's-length sales contract.

(2) You sell or transfer to your affiliate or another person under a non-arm's-length contract and that affiliate or person, or another affiliate of either of them, then sells the oil under an arm's-length contract.

(b) If you have multiple arm's-length contracts to sell oil produced from a lease that is valued under paragraph (a) of this section, the value of the oil is the higher of the volume-weighted average of the values established under this section for all contracts for the sale of oil produced from that lease or the IBMP value calculated under § 1206.54.

(c) If ONRR determines that the gross proceeds accruing to you or your affiliate does not reflect the reasonable value of the production due to either:

(1) Misconduct by or between the parties to the arm's-length contract; or

(2) Breach of your duty to market the oil for the mutual benefit of yourself and the lessor, ONRR will establish a value based on other relevant matters.

(i) ONRR will not use this provision to simply substitute its judgment of the market value of the oil for the proceeds received by the seller under an arm's-length sales contract.

(ii) The fact that the price received by the seller under an arm's-length contract is less than other measures of market price is insufficient to establish breach of the duty to market unless ONRR finds additional evidence that the seller acted unreasonably or in bad faith in the sale of oil produced from the lease.

(d) You have the burden of demonstrating that your or your affiliate's contract is arm's-length.

(e) ONRR may require you to certify that the provisions in your or your affiliate's contract include all of the consideration that the buyer paid to you or your affiliate, either directly or indirectly, for the oil.

(f) You must base value on the highest price that you or your affiliate can receive through legally enforceable claims under the oil sales contract.

(1) Absent contract revision or amendment, if you or your affiliate fail(s) to take proper or timely action to receive prices or benefits to which you or your affiliate are entitled, you must pay royalty based upon that obtainable price or benefit.

(2) If you or your affiliate make timely application for a price increase or benefit allowed under your or your affiliate's contract—but the purchaser refuses—and you or your affiliate take reasonable documented measures to force purchaser compliance, you will not owe additional royalties unless or until you or your affiliate receive additional monies or consideration resulting from the price increase. You may not construe this paragraph (f)(2) to permit you to avoid your royalty payment obligation in situations where a purchaser fails to pay, in whole or in part, or in a timely manner, for a quantity of oil.

(g)(1) You or your affiliate must make all contracts, contract revisions, or amendments in writing, and all parties to the contract must sign the contract, contract revisions, or amendments.

(2) This provision applies notwithstanding any other provisions in this title 30 of the Code of Federal Regulations to the contrary.

(h) If you or your affiliate enter(s) into an arm's-length exchange agreement, or multiple sequential arm's-length exchange agreements, then you must value your oil under this paragraph (h).

(1) If you or your affiliate exchange(s) oil at arm's length for WTI or equivalent oil at Cushing, Oklahoma, you must value the oil using the NYMEX price, adjusted for applicable location and quality differentials under paragraph (h)(3) of this section and any transportation costs under paragraph (h)(4) of this section and §§ 1206.56 and 1206.57 or § 1206.58.

(2) If you do not exchange oil for WTI or equivalent oil at Cushing, but exchange it at arm's length for oil at another location and following the arm's-length exchange(s) you or your affiliate sell(s) the oil received in the exchange(s) under an arm's-length contract, then you must use the gross proceeds under your or your affiliate's arm's-length sales contract after the exchange(s) occur(s), adjusted for applicable location and quality differentials under paragraph (h)(3) of this section and any transportation costs under paragraph (h)(4) of this section and §§ 1206.56 and 1206.57 or § 1206.58.

(3) You must adjust your gross proceeds for any location or quality differential, or other adjustments, that you received or paid under the arm's-length exchange agreement(s). If ONRR determines that any exchange agreement does not reflect reasonable location or quality differentials, ONRR may adjust the differentials that you used based on relevant information. You may not otherwise use the price or differential specified in an arm's-length exchange agreement to value your production.

(4) If you value oil under this paragraph (h), ONRR will allow a deduction, under §§ 1206.56 and 1206.57 or § 1206.58, for the reasonable, actual costs to transport the oil:

(i) From the lease to a point where oil is given in exchange.

(ii) If oil is not exchanged to Cushing, Oklahoma, from the point where oil is received in exchange to the point where the oil received in exchange is sold.

(5) If you or your affiliate exchange(s) your oil at arm's length, and neither paragraph (h)(1) nor (2) of this section applies, ONRR will establish a value for the oil based on relevant matters. After ONRR establishes the value, you must report and pay royalties and any late payment interest owed based on that value.

§ 1206.53 How do I calculate royalty value for oil that I or my affiliate do(es) not sell under an arm's-length contract?

(a) The value of production for royalty purposes for your lease is the higher of either the value determined under this section or the IBMP value calculated under § 1206.54. The unit value of your oil not sold under an arm's-length contract under this section for royalty purposes is the volume-weighted average of the gross proceeds paid or received by you or your affiliate, including your refining affiliate, for purchases or sales under arm's-length contracts.

(1) When calculating that unit value, use only purchases or sales of other like-quality oil produced from the field (or the same area if you do not have sufficient arm's-length purchases or sales of oil produced from the field) during the production month.

(2) You may adjust the gross proceeds determined under paragraph (a) of this section for transportation costs under paragraph (c) of this section and §§ 1206.56 and 1206.57 or § 1206.58 before including those proceeds in the volume-weighted average calculation.

(3) If you have purchases away from the field(s) and cannot calculate a price in the field because you cannot determine the seller's cost of transportation that would be allowed under paragraph (c) of this section and §§ 1206.56 and 1206.57 or § 1206.58, you must not include those purchases in your volume-weighted average calculation.

(b) Before calculating the volume-weighted average, you must normalize the quality of the oil in your or your affiliate's arm's-length purchases or sales to the same gravity as that of the oil produced from the lease. Use applicable gravity adjustment tables for the field (or the same general area for like-quality oil if you do not have gravity adjustment tables for the specific field) to normalize for gravity, as shown in the example below.

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

10,000 bbl | 24.5° | $34.70/bbl | Purchased in the field.

8,000 bbl | 24.0° | $34.00/bbl | Purchased at the refinery after the third-party producer transported it to the refinery, and the lessee does not know the transportation costs.

9,000 bbl | 23.0° | $33.25/bbl | Purchased in the field.

4,000 bbl | 22.0° | $33.00/bbl | Purchased in the field.

(2) Example 2. Because the lessee does not know the costs that the seller of the 8,000 bbl incurred to transport that volume to the refinery, that volume will not be included in the volume-weighted average price calculation. Further assume that the gravity adjustment scale provides for a deduction of $0.02 per 1/10 degree API gravity below 34°. Normalized to 23.5° (the gravity of the oil being valued under this section), the prices of each of the volumes that the refiner purchased that are included in the volume-weighted average calculation are as follows:

10,000 bbl | 24.5° | $34.50/bbl | (1.0° difference over 23.5° = $0.20 deducted).

9,000 bbl | 23.0° | $33.35/bbl | (0.5° difference under 23.5° = $0.10 added).

4,000 bbl | 22.0° | $33.30/bbl | (1.5° difference under 23.5° = $0.30 added).

(3) Example 3. The volume-weighted average price is ((10,000 bbl × $34.50/bbl) + (9,000 bbl × $33.35/bbl) + (4,000 bbl × $33.30/bbl)) / 23,000 bbl = $33.84/bbl. That price will be the value of the oil produced from the lease and refined prior to an arm's-length sale under this section.

(c) If you value oil under this section, ONRR will allow a deduction, under §§ 1206.56 and 1206.57 or § 1206.58, for the reasonable, actual costs:

(1) That you incur to transport oil that you or your affiliate sell(s), which is included in the volume-weighted average price calculation, from the lease to the point where the oil is sold.

(2) That the seller incurs to transport oil that you or your affiliate purchase(s), which is included in the volume-weighted average cost calculation, from the property where it is produced to the point where you or your affiliate purchase(s) it. You may not deduct any costs of gathering as part of a transportation deduction or allowance.

(d) If paragraphs (a) and (b) of this section result in an unreasonable value for your production as a result of circumstances regarding that production, ONRR's Director may establish an alternative valuation method.

§ 1206.54 How do I fulfill the lease provision regarding valuing production on the basis of the major portion of like-quality oil?

(a) This section applies to any Indian leases that contain a major portion provision for determining value for royalty purposes. This section also applies to any Indian leases that provide that the Secretary may establish value for royalty purposes. The value of production for royalty purposes for your lease is the higher of either the value determined under this section or the gross proceeds you calculated under § 1206.52 or § 1206.53.

(b) You must submit a monthly Form ONRR-2014 using the higher of the IBMP value determined under this section or your gross proceeds under § 1206.52 or § 1206.53. Your Form ONRR-2014 must meet the requirements of 30 CFR 1210.61.

(c) ONRR will determine the monthly IBMP value for each designated area and crude oil type and post those values on our Web site at www.onrr.gov. The monthly IBMP value by designated area and crude oil type is calculated as follows:

(1) For Indian leases located in Oklahoma:

(2) For all other Indian leases:

(d) ONRR will calculate the initial LCTD for each designated area (the same designated areas posted on its Web site at www.onrr.gov) and crude oil type using the following formula:

(1) For the first full production month after July 1, 2015, ONRR will calculate the monthly Major Portion Prices using data reported on the Form ONRR-2014 for the previous 12 production months prior to July 1, 2015 (Previous Twelve Months). To the extent that ONRR does not have data on the Form ONRR-2014 regarding the crude oil type for the entire previous twelve months, ONRR will assume the crude oil type is the same for those months for which ONRR does not have data as the months for which the crude oil type was reported on the Form ONRR-2014 for the same leases and/or agreements.

(i) ONRR will array the calculated prices net of transportation by month from highest to lowest price for each designated area and crude oil type. For each month, ONRR will calculate the Major Portion Price as that price at which 25 percent plus 1 barrel (by volume) of the oil (starting from the highest) is sold.

(ii) To calculate the average of the monthly Major Portion Prices for the previous 12 months, ONRR will add the monthly Major Portion Prices calculated in paragraph (d)(1)(i) of this section and divide by 12.

(2) For every month following the first full production month after July 1, 2015, ONRR will monitor the LCTD using data reported on the Form ONRR-2014 for the month ending two months before the current production month.

(i) ONRR will use the oil sales volume that lessees report on Form ONRR-2014 to monitor and, if necessary, to modify the LCTD used in the IBMP value.

(ii) ONRR will monitor oil sales volumes not reported under the sales type code OINX, as provided in 30 CFR 1210.61(a) and (b), on the Form ONRR-2014 on a monthly basis by designated area and crude oil type.

(iii) If the monthly oil sales volumes not reported under the sales type code OINX varies more than ± 3 percent from 25 percent of the total reported oil sales volume for the month, then ONRR will revise the LCTD prospectively starting with the following month.

(A) If monthly oil sales volumes not reported under the sales type code OINX on Form ONRR-2014 by the designated area and crude oil type fall below 22 percent, ONRR will increase the LCTD by 10 percent every month until the monthly oil sales volumes reported under the sales type code for gross proceeds on Form ONRR-2014 fall within the ± 3 percent range. In Example 1, assume that the IBMP value is $81.06 and the LCTD for the designated area is 14.28 percent. In the table below, the Percent of Volume not reported as OINX is less than 22 percent, which triggers a modification to the LCTD. ONRR will adjust the LCTD upward by 10 percent (14.28 percent × 1.10). Therefore, for the next month, the LCTD will be 15.71 percent. In the following month, the IBMP value will equal the next month's NYMEX CMA multiplied by (1 − 0.1571). ONRR will continue to make adjustments in subsequent months until monthly sales volumes not reported as OINX fall within 22-28 percent of the total monthly sales volume.

Example 1—Differential Adjustment When ARMS Sales Volume for the Current Month Falls Below 22% of Total Monthly Sales Volume

Lease | Sales volume | Unit price | Sales type code | Cumulative volume | Percent of volume

1 | 220 | 81.95 | ARMS | 220 | 9.02

2 | 275 | 81.71 | ARMS | 495 | 20.29

3 | 400 | 81.06 | OINX | 895 | 36.68

4 | 425 | 81.06 | OINX | 1,320 | 54.10

5 | 370 | 81.06 | OINX | 1,690 | 69.26

6 | 400 | 81.06 | OINX | 2,090 | 85.66

7 | 350 | 81.06 | OINX | 2,440 | 100.00

2,440

(B) If monthly oil sales volumes not reported under the sales type code OINX on Form ONRR-2014 by designated area and crude oil type exceed 28 percent, then ONRR will decrease the LCTD by 10 percent every month until the monthly oil sales volumes reported under the sales type code for gross proceeds on Form ONRR-2014 fall within the ± 3 percent range. In Example 2, assume that the IBMP value is $81.06 and the LCTD is 14.28 percent. As noted in the table below, however, the Percent of Volume not reported as OINX is 32.69 percent, exceeding the 28 percent threshold, which triggers a modification to the LCTD. ONRR will adjust the LCTD downward by 10 percent (14.28 percent × 0.90). Therefore, for the next month, the LCTD will be 12.85 percent. In the following month, the IBMP will equal the next month's NYMEX CMA multiplied by (1−0.1285). ONRR will continue to make adjustments in subsequent months until monthly sales volumes reported as ARMS fall within 22-28 percent of the total monthly sales volume.

Example 2—Differential Adjustment When ARMS Sales Volume Not Reported as OINX for the Current Month Exceeds 28% of Total Monthly Sales Volume

Lease | Sales volume | Unit price | Sales type code | Cumulative volume | Percent of volume

1 | 230 | 81.95 | ARMS | 230 | 11.06

2 | 275 | 81.71 | ARMS | 505 | 24.28

3 | 175 | 81.45 | ARMS | 680 | 32.69

4 | 250 | 81.06 | OINX | 930 | 44.71

5 | 425 | 81.06 | OINX | 1,355 | 65.14

6 | 325 | 81.06 | OINX | 1,680 | 80.77

7 | 400 | 81.06 | OINX | 2,080 | 100.00

2,080

(e) In designated areas where there is insufficient data reported to ONRR on Form ONRR-2014 to determine a differential for a specific crude oil type, ONRR will use its discretion to determine an appropriate IBMP value.

§ 1206.55 What are my responsibilities to place production into marketable condition and to market production?

(a) 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 Indian lessor unless the lease agreement provides otherwise.

(b) If you must use gross proceeds under an arm's-length contract or your affiliate's gross proceeds under an arm's-length exchange agreement to determine value under § 1206.52 or § 1206.53, 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 in order to place the oil in marketable condition or to market the oil.

§ 1206.56 What general transportation allowance requirements apply to me?

(a) ONRR will allow a deduction for the reasonable, actual costs to transport oil from the lease to the point off of the lease under § 1206.52 or § 1206.53, as applicable. You may not deduct transportation costs to reduce royalties where you did not incur any costs to move a particular volume of oil. ONRR will not grant a transportation allowance for transporting oil taken as Royalty-In-Kind (RIK).

(b)(1) Except as provided in paragraph (b)(2) of this section, your transportation allowance deduction on the basis of a sales type code may not exceed 50 percent of the value of the oil at the point of sale, as determined under § 1206.52. Transportation costs cannot be transferred between sales type codes or to other products.

(2) Upon your request, ONRR may approve a transportation allowance deduction in excess of the limitation prescribed by paragraph (b)(1) of this section. You must demonstrate that the transportation costs incurred in excess of the limitation prescribed in paragraph (b)(1) of this section were reasonable, actual, and necessary. An application for exception (using Form ONRR-4393, Request to Exceed Regulatory Allowance Limitation) must contain all relevant and supporting documentation necessary for ONRR to make a determination. Under no circumstances may the value, for royalty purposes, under any sales type code, be reduced to zero.

(c) You must express transportation allowances for oil in dollars per barrel. If you or your affiliate's payments for transportation under a contract are not on a dollar-per-barrel basis, you must convert whatever consideration you or your affiliate are paid to a dollar-per-barrel equivalent.

(d) You must allocate transportation costs among all products produced and transported as provided in § 1206.57.

(e) All transportation allowances are subject to monitoring, review, audit, and adjustment.

(f) If, after a review or audit, ONRR determines you have improperly determined a transportation allowance authorized by this subpart, then you must pay any additional royalties due plus late payment interest calculated under § 1218.54 of this chapter or report a credit for, or request a refund of, any overpaid royalties without interest under § 1218.53 of this chapter.

(g) You may not deduct any costs of gathering as part of a transportation deduction or allowance.

§ 1206.57 How do I determine a transportation allowance if I have an arm's-length transportation contract?

(a) Arm's-length transportation. (1) If you incur transportation costs under an arm's-length contract, your transportation allowance is the reasonable, actual costs that you incur to transport oil under that contract. You have the burden of demonstrating that your contract is arm's-length.

(2) You must submit to ONRR a copy of your arm's-length transportation contract(s) and all subsequent amendments to the contract(s) within 2 months of the date that ONRR receives your report, which claims the allowance on Form ONRR-2014.

(3) If ONRR determines that the consideration paid under an arm's-length transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then ONRR shall require that the transportation allowance be determined in accordance with paragraph (b) of this section. When ONRR determines that the value of the transportation may be unreasonable, ONRR will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's transportation costs.

(4)(i) If an arm's-length transportation contract includes more than one liquid product, and the transportation costs attributable to each product cannot be determined from the contract, then you must allocate the total transportation costs in a consistent and equitable manner to each of the liquid products transported in the same proportion as the ratio of the volume of each product (excluding waste products which have no value) to the volume of all liquid products (excluding waste products which have no value). Except as provided in this paragraph (a)(4)(i), you may not take an allowance for the costs of transporting lease production, which is not royalty-bearing, without ONRR's approval.

(ii) Notwithstanding the requirements of paragraph (a)(4)(i) of this section, you may propose to ONRR a cost allocation method on the basis of the values of the products transported. ONRR shall approve the method unless it determines that it is not consistent with the purposes of the regulations in this part.

(5) If an arm's-length transportation contract includes both gaseous and liquid products, and the transportation costs attributable to each product cannot be determined from the contract, you must propose an allocation procedure to ONRR.

(i) You may use the oil transportation allowance determined in accordance with its proposed allocation procedure until ONRR issues its determination on the acceptability of the cost allocation.

(ii) You must submit to ONRR all available data to support your proposal.

(iii) You must submit your initial proposal within 3 months after the last day of the month for which you request a transportation allowance, whichever is later (unless ONRR approves a longer period).

(iv) ONRR will determine the oil transportation allowance based on your proposal and any additional information that ONRR deems necessary.

(6) Where an arm's-length sales contract price includes a provision whereby the listed price is reduced by a transportation factor, ONRR will not consider the transportation factor to be a transportation allowance. You may use the transportation factor to determine your gross proceeds for the sale of the product. The transportation factor may not exceed 50 percent of the base price of the product without ONRR's approval.

(b) Reporting requirements. (1) If ONRR requests, you must submit all data used to determine your transportation allowance. You must provide the data within a reasonable period of time that ONRR will determine.

(2) You must report transportation allowances as a separate entry on Form ONRR-2014. ONRR may approve a different reporting procedure on allotted leases and with lessor approval on Tribal leases.

(3) ONRR may establish, in appropriate circumstances, reporting requirements that are different from the requirements of this section.

§ 1206.58 How do I determine a transportation allowance if I have a non-arm's-length transportation contract or have no contract?

(a) Non-arm's-length or no contract. (1) If you have a non-arm's-length transportation contract or no contract, including those situations where you or your affiliate perform(s) transportation services for you, the transportation allowance is based on your reasonable, actual costs as provided in this paragraph (a)(1).

(2) You must submit the actual cost information to support the allowance to ONRR on Form ONRR-4110, Oil Transportation Allowance Report, within 3 months after the end of the calendar year to which the allowance applies. However, ONRR may approve a longer time period. ONRR will monitor the allowance deductions to ensure that deductions are reasonable and allowable. When necessary or appropriate, ONRR may require you to modify your actual transportation allowance deduction.

(3) You must base a transportation allowance for non-arm's-length or no-contract situations on your actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment under paragraph (a)(3)(iv)(A) of this section, or a cost equal to the initial capital investment in the transportation system multiplied by a rate of return under paragraph (a)(3)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment), which are an integral part of the transportation system.

(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense that the lessee can document.

(ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses that the lessee can document.

(iii) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.

(iv) You may use either depreciation or a return on depreciable capital investment. After you have elected to use either method for a transportation system, you may not later elect to change to the other alternative without approval from ONRR.

(A) To compute depreciation, you may elect to use either a straight-line depreciation method, based on the life of equipment or on the life of the reserves, which the transportation system services, or on a unit-of-production method. After you make an election, you may not change methods without ONRR's approval. A change in ownership of a transportation system will not alter the depreciation schedule the original transporter/lessee established for the purposes of the allowance calculation. With or without a change in ownership, a transportation system can be depreciated only once. You may not depreciate equipment below a reasonable salvage value.

(B) ONRR will allow as a cost an amount equal to the initial capital investment in the transportation system multiplied by the rate of return determined under paragraph (a)(3)(v) of this section. No allowance will be provided for depreciation.

(v) The rate of return is the industrial rate associated with Standard and Poor's BBB rating. The rate of return you must use is the monthly average rate as published in Standard and Poor's Bond Guide for the first month of the reporting period for which the allowance is applicable and is effective during the reporting period. You must redetermine the rate at the beginning of each subsequent transportation allowance reporting period (which is determined under paragraph (b) of this section).

(4)(i) You must determine 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, you must allocate costs to each of the liquid products transported in the same proportion as the ratio of the volume of each liquid product (excluding waste products which have no value) to the volume of all liquid products (excluding waste products which have no value) and you must make such allocation in a consistent and equitable manner. Except as provided in this paragraph (a)(4)(i), you may not take an allowance for transporting lease production that is not royalty-bearing without ONRR's approval.

(ii) Notwithstanding the requirements of paragraph (a)(4)(i) of this section, you may propose to ONRR a cost allocation method on the basis of the values of the products transported. ONRR will approve the method unless we determine that it is not consistent with the purposes of the regulations in this part.

(5) Where both gaseous and liquid products are transported through the same transportation system, you must propose a cost allocation procedure to ONRR.

(i) You may use the oil transportation allowance determined in accordance with its proposed allocation procedure until ONRR issues our determination on the acceptability of the cost allocation.

(ii) You must submit to ONRR all available data to support your proposal.

(iii) You must submit your initial proposal within 3 months after the last day of the month for which you request a transportation allowance (unless ONRR approves a longer period).

(iv) ONRR will determine the oil transportation allowance based on your proposal and any additional information that ONRR deems necessary.

(6) You may apply to ONRR for an exception from the requirement that you compute actual costs under paragraphs (a)(1) through (5) of this section.

(i) ONRR will grant the exception only if you have a tariff for the transportation system the Federal Energy Regulatory Commission (FERC) has approved for Indian leases.

(ii) ONRR will deny the exception request if it determines that the tariff is excessive as compared to arm's-length transportation charges by pipelines, owned by the lessee or others, providing similar transportation services in that area.

(iii) If there are no arm's-length transportation charges, ONRR will deny the exception request if:

(A) No FERC cost analysis exists and the FERC has declined to investigate under ONRR timely objections upon filing.

(B) The tariff significantly exceeds the lessee's actual costs for transportation as determined under this section.

(b) Reporting requirements. (1) If ONRR requests, you must submit all data used to determine your transportation allowance. You must provide the data within a reasonable period of time that ONRR will determine.

(2) You must report transportation allowances as a separate entry on Form ONRR-2014. ONRR may approve a different reporting procedure on allotted leases and with lessor approval on Tribal leases.

(3) ONRR may require you to submit all of the data that you used to prepare your Form ONRR-4110. You must submit the data within a reasonable period of time that ONRR determines.

(4) ONRR may establish, in appropriate circumstances, reporting requirements that are different from the requirements of this section.

(5) If you are authorized to use your FERC-approved tariff as your transportation cost under paragraph (a)(6) of this section, you must follow the reporting requirements of § 1206.57(b).

(c) Notwithstanding any other provisions of this subpart, for other than arm's-length contracts, no cost will be allowed for oil transportation that results from payments (either volumetric or for value) for actual or theoretical losses. This section does not apply when the transportation allowance is based upon a FERC or State regulatory agency approved tariff.

(d) The provisions of this section will apply to determine transportation costs when establishing value using a netback valuation procedure or any other procedure that requires deduction of transportation costs.

§ 1206.59 What interest applies if I improperly report a transportation allowance?

(a) If you deduct a transportation allowance on Form ONRR-2014 without complying with the requirements of §§ 1206.56 and 1206.57 or § 1206.58, you must pay additional royalties due plus late payment interest calculated under § 1218.54 of this chapter.

(b) If you erroneously report a transportation allowance that results in an underpayment of royalties, you must pay any additional royalties due plus late payment interest calculated under § 1218.54 of this chapter.

§ 1206.60 What reporting adjustments must I make for transportation allowances?

(a) If your actual transportation allowance is less than the amount that you claimed on Form ONRR-2014 for each month during the allowance reporting period, you must pay additional royalties due, plus late payment interest calculated under § 1218.54 of this chapter from the first day of the first month that you were authorized to deduct a transportation allowance to the date that you repay the difference.

(b) If the actual transportation allowance is greater than the amount that you claimed on Form ONRR-2014 for any month during the period reported on the allowance form, you may report a credit for, or request a refund of, any overpaid royalties without interest under § 1218.53 of this chapter.

(c) If you make an adjustment under paragraph (a) or (b) of this section, then you must submit a corrected Form ONRR-2014 to reflect actual costs, together with any payment, using instructions that ONRR provides.

§ 1206.61 How will ONRR determine if my royalty payments are correct?

(a)(1) ONRR may monitor, review, and audit the royalties that you report, and, if ONRR determines that your reported value is inconsistent with the requirements of this subpart, ONRR may direct you to use a different measure of royalty value.

(2) If ONRR directs you to use a different royalty value, you must pay any additional royalties due plus late payment interest calculated under § 1218.54 of this chapter, or you may report a credit for, or request a refund of, any overpaid royalties without interest under § 1218.53 of this chapter.

(b) When the provisions in this subpart refer to gross proceeds, in conducting reviews and audits, ONRR will examine if your or your affiliate's contract reflects the total consideration actually transferred, either directly or indirectly, from the buyer to you or your affiliate for the oil. If ONRR determines that a contract does not reflect the total consideration, you must value the oil sold as the total consideration accruing to you or your affiliate.

§ 1206.62 How do I request a value determination?

(a) You may request a value determination from ONRR regarding any oil produced. Your request must:

(1) Be in writing.

(2) Identify specifically all leases involved, all interest owners of those leases, the designee(s), and the operator(s) for those leases.

(3) Completely explain all relevant facts. You must inform ONRR of any changes to relevant facts that occur before we respond to your request.

(4) Include copies of all relevant documents.

(5) Provide your analysis of the issue(s), including citations to all relevant precedents (including adverse precedents).

(6) Suggest your proposed valuation method.

(b) In response to your request, ONRR may:

(1) Request that the Assistant Secretary for Indian Affairs issue a valuation determination.

(2) Decide that ONRR will issue guidance.

(3) Inform you in writing that ONRR will not provide a determination or guidance. Situations in which ONRR typically will not provide any determination or guidance include, but are not limited to:

(i) Requests for guidance on hypothetical situations.

(ii) Matters that are the subject of pending litigation or administrative appeals.

(c)(1) A value determination that the Assistant Secretary for Indian Affairs signs is binding on both you and ONRR until the Assistant Secretary modifies or rescinds it.

(2) After the Assistant Secretary issues a value determination, you must make any adjustments to royalty payments that follow from the determination, and, if you owe additional royalties, you must pay the additional royalties due plus late payment interest calculated under § 1218.54 of this chapter.

(3) A value determination that the Assistant Secretary signs is the final action of the Department and is subject to judicial review under 5 U.S.C. 701-706.

(d) Guidance that ONRR issues is not binding on ONRR, the Indian lessor, or you with respect to the specific situation addressed in the guidance.

(1) Guidance and ONRR's decision whether or not to issue guidance or request an Assistant Secretary determination, or neither, under paragraph (b) of this section, are not appealable decisions or orders under 30 CFR part 1290.

(2) If you receive an order requiring you to pay royalty on the same basis as the guidance, you may appeal that order under 30 CFR part 1290.

(e) ONRR or the Assistant Secretary may use any of the applicable valuation criteria in this subpart to provide guidance or make a determination.

(f) A change in an applicable statute or regulation on which ONRR or the Assistant Secretary based any determination or guidance takes precedence over the determination or guidance, regardless of whether ONRR or the Assistant Secretary modifies or rescinds the determination or guidance.

(g) ONRR or the Assistant Secretary generally will not retroactively modify or rescind a value determination issued under paragraph (d) of this section, unless:

(1) There was a misstatement or omission of material facts.

(2) The facts subsequently developed are materially different from the facts on which the guidance was based.

(h) ONRR may make requests and replies under this section available to the public, subject to the confidentiality requirements under § 1206.65.

§ 1206.63 How do I determine royalty quantity and quality?

(a) You must calculate royalties based on the quantity and quality of oil as measured at the point of royalty settlement that BLM approves.

(b) If you determine the value of oil under § 1206.52, § 1206.53, or § 1206.54 based on a quantity and/or quality that is different from the quantity and/or quality at the point of royalty settlement that BLM approves for the lease, you must adjust that value for the differences in quantity and/or quality.

(c) You may not make any deductions from the royalty volume or royalty value for actual or theoretical losses incurred before the royalty settlement point unless BLM determines that any actual loss was unavoidable.

§ 1206.64 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 show:

(1) How you calculated the value that you reported, including all adjustments for location, quality, and transportation.

(2) How you complied with these rules.

(b) On request, you must make available sales, volume, and transportation data for production that you sold, purchased, or obtained from the field or area. You must make this data available to ONRR, Indian representatives, or other authorized persons.

(c) You can find recordkeeping requirements in §§ 1207.5, 1212.50, and 1212.51 of this chapter.

(d) ONRR, Indian representatives, or other authorized persons may review and audit your data, and ONRR will direct you to use a different value if they determine that the reported value is inconsistent with the requirements of this subpart.

§ 1206.65 Does ONRR protect information that I provide?

(a) Certain information that you or your affiliate submit(s) to ONRR regarding the valuation of oil, including transportation allowances, may be exempt from disclosure.

(b) To the extent that applicable laws and regulations permit, ONRR will keep confidential any data that you or your affiliate submit(s) that is privileged, confidential, or otherwise exempt from disclosure.

(c) You and others must submit all requests for information under the Freedom of Information Act regulations of the Department of the Interior at 43 CFR part 2.

§ 1206.100 What is the purpose of this subpart?

(a) This subpart applies to all oil produced from Federal oil and gas leases onshore and on the OCS. It explains how you, as a lessee, must calculate the value of production for royalty purposes consistent with 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 a(an): Federal statute; settlement agreement between the United States and a lessee resulting from administrative or judicial litigation; written agreement between the lessee and ONRR's Director establishing a method to determine the value of production from any lease that ONRR expects would at least approximate the value established under this subpart; express provision of an oil and gas lease subject to this subpart, then the statute, settlement agreement, written agreement, or lease provision will govern to the extent of the inconsistency.

(e) ONRR may audit, monitor, or review and adjust all royalty payments.

§ 1206.101 How do I calculate royalty value for oil I or my affiliate sell(s) under an arm's-length contract?

(a) The value of oil under this section for royalty purposes is the gross proceeds accruing to you or your affiliate under the arm's-length contract less applicable allowances determined under § 1206.111 or § 1206.112. This value does not apply if you exercise an option to use a different value provided in paragraph (c)(1) or (c)(2)(i) of this section or if ONRR decides to value your oil under § 1206.105. You must use this paragraph (a) to value oil when:

(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 (c)(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)(1) If you enter into an arm's-length exchange agreement, or multiple sequential arm's-length exchange agreements, and following the exchange(s) that you or your affiliate sell(s) the oil received in the exchange(s) under an arm's-length contract, then you may use either paragraph (a) of this section or § 1206.102 to value your production for royalty purposes. If you fail to make the election required under this paragraph, you may not make a retroactive election, and ONRR may decide your value under § 1206.105.

(i) If you use paragraph (a) of this section, 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, that you received or paid under the arm's-length exchange agreement(s). If ONRR determines that any arm's-length exchange agreement does not reflect reasonable location or quality differentials, ONRR may decide your value under § 1206.105. 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 paragraph (c)(1) of this section to use paragraph (a) of this section or § 1206.102, you must make the same election for all of your production from the same unit, communitization agreement, or lease (if the lease is not part of a unit or communitization agreement) sold under arm's-length contracts following arm's-length exchange agreements. You may not change your election more often than once every two 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 paragraph (a) of this section or § 1206.102 to value your production for royalty purposes.

(ii) When you elect under paragraph (c)(2)(i) of this section to use paragraph (a) of this section or § 1206.102, 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 two years.

§ 1206.102 How do I value oil not sold under an arm's-length contract?

This section explains how to value oil that you may not value under § 1206.101 or that you elect under § 1206.101(c)(1) to value under this section, unless ONRR decides to value your oil under 1206.105. First, determine if paragraph (a), (b), or (c) of this section applies to production from your lease, or if you may apply paragraph (d) or (e) of this section with ONRR's approval.

(a) Production from leases in California or Alaska. Value is the average of the daily mean ANS spot prices published in any ONRR-approved publication during the trading month most concurrent with the production month. For example, if the production month is June, calculate the average of the daily mean prices using the daily ANS spot prices published in the ONRR-approved publication for all of the business days in June.

(1) To calculate the daily mean spot price, you must average the daily high and low prices for the month in the selected publication.

(2) You must use only the days and corresponding spot prices for which such prices are published.

(3) You must adjust the value for applicable location and quality differentials, and you may adjust it for transportation costs, under § 1206.111.

(4) After you select an ONRR-approved publication, you may not select a different publication more often than once every two years, unless the publication you use is no longer published or ONRR revokes its approval of the publication. If you must change publications, you must begin a new two-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)(2) or (3) of this section to value all of your production from the same unit, communitization agreement, or lease (if the lease or a portion of the lease is not part of a unit or communitization agreement) that you cannot value under § 1206.101 or that you elect under § 1206.101(c)(1) to value under this section.

(1) You may elect to value your oil under either paragraph (b)(2) or (3) of this section. After you select either paragraph (b)(2) or (3) of this section, you may not change to the other method more often than once every two 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 two-year period.

(2) Value is the volume-weighted average of the gross proceeds accruing to the seller under your or your affiliate's 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 affiliate's 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 affiliate's arm's-length purchases or sales to the same gravity as that of the oil produced from the lease.

(3) Value is the NYMEX price (without the roll), adjusted for applicable location and quality differentials and transportation costs under § 1206.113.

(4) If you demonstrate to ONRR's satisfaction that paragraphs (b)(2) through (3) of this section result in an unreasonable value for your production as a result of circumstances regarding that production, ONRR's Director may establish an alternative valuation method.

(c) Production from leases not located in California, Alaska, or the Rocky Mountain Region.

(1) Value is the NYMEX price, plus the roll, adjusted for applicable location and quality differentials and transportation costs under § 1206.113.

(2) If ONRR's Director determines that the use of the roll no longer reflects prevailing industry practice in crude oil sales contracts or that the most common formula that industry uses to calculate the roll changes, ONRR may terminate or modify the use of the roll under paragraph (c)(1) of this section at the end of each two-year period as of January 1, 2017, through a notice published in the Federal Register not later than 60 days before the end of the two-year period. ONRR will explain the rationale for terminating or modifying the use of the roll in this notice.

(d) Unreasonable value. If ONRR determines that the NYMEX price or ANS spot price does not represent a reasonable royalty value in any particular case, ONRR may decide to value your oil under § 1206.105.

(e) Production delivered to your refinery and the NYMEX price or ANS spot price is an unreasonable value. If ONRR determines that the NYMEX price or ANS spot price does not represent a reasonable royalty value in any particular case, ONRR may decide to value your oil under § 1206.105.

§ 1206.103 What publications does ONRR approve?

(a) ONRR will periodically publish on www.onrr.gov a list of ONRR-approved 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.

(4) Publications independent from ONRR, other lessors, and lessees.

(b) Any publication may petition ONRR to be added to the list of acceptable publications.

(c) ONRR will specify the tables that you must use in the acceptable publications.

(d) ONRR may revoke its approval of a particular publication if we determine that the prices or differentials published in the publication do not accurately represent NYMEX prices or differentials or ANS spot market prices or differentials.

§ 1206.104 How will ONRR determine if my royalty payments are correct?

(a)(1) ONRR may monitor, review, and audit the royalties that you report, and, if ONRR determines that your reported value is inconsistent with the requirements of this subpart, ONRR may direct you to use a different measure of royalty value or decide your value under § 1206.105.

(2) If ONRR directs you to use a different royalty value, you must either pay any additional royalties due, plus late payment interest calculated under §§ 1218.54 and 1218.102 of this chapter), or report a credit for—or request a refund of—any overpaid royalties.

(b) When the provisions in this subpart refer to gross proceeds, in conducting reviews and audits, ONRR will examine if your or your affiliate's contract reflects the total consideration actually transferred, either directly or indirectly, from the buyer to you or to your affiliate for the oil. If ONRR determines that a contract does not reflect the total consideration, ONRR may decide your value under § 1206.105.

(c) ONRR may decide your value under § 1206.105 if ONRR determines that the gross proceeds accruing to you or your affiliate under a contract do not reflect reasonable consideration because:

(1) There is misconduct by or between the contracting parties; or

(2) You have breached your duty to market the oil for the mutual benefit of yourself and the lessor by selling your oil at a value that is unreasonably low. ONRR may consider a sales price to be unreasonably low if it is 10 percent less than the lowest reasonable measures of market price including—but not limited to—index prices and prices reported to ONRR for like quality oil; or

(3) ONRR cannot determine if you properly valued your oil under § 1206.101 or § 1206.102 for any reason including—but not limited to—your or your affiliate's failure to provide documents that ONRR requests under 30 CFR part 1212, subpart B.

(d) You have the burden of demonstrating that your or your affiliate's contract is arm's-length.

(e) ONRR may require you to certify that the provisions in your or your affiliate's contract include all of the consideration that the buyer paid to you or your affiliate, either directly or indirectly, for the oil.

(f)(1) Absent contract revision or amendment, if you or your affiliate fail(s) to take proper or timely action to receive prices or benefits to which you or your affiliate are entitled, you must pay royalty based upon that obtainable price or benefit.

(2) If you or your affiliate apply in a timely manner for a price increase or benefit allowed under your or your affiliate's contract, but the purchaser refuses and you or your affiliate take reasonable documented measures to force purchaser compliance, you will not owe additional royalties unless or until you or your affiliate receive additional monies or consideration resulting from the price increase. You may not construe this paragraph to permit you to avoid your royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or in a timely manner, for a quantity of oil.

(g)(1) You or your affiliate must make all contracts, contract revisions, or amendments in writing, and all parties to the contract must sign the contract, contract revisions, or amendments.

(2) If you or your affiliate fail(s) to comply with paragraph (g)(1) of this section, ONRR may determine your value under § 1206.105.

(3) This provision applies notwithstanding any other provisions in this title 30 to the contrary.

§ 1206.105 How will ONRR determine the value of my oil for royalty purposes?

If ONRR decides that we will value your oil for royalty purposes under § 1206.104, or any other provision in this subpart, then we will determine value, for royalty purposes, by considering any information that we deem relevant, which may include, but is not limited to, the following:

(a) The value of like-quality oil in the same field or nearby fields or areas

(b) The value of like-quality oil from the refinery or area

(c) Public sources of price or market information that ONRR deems reliable

(d) Information available and reported to ONRR, including but not limited to on form ONRR-2014 and the Oil and Gas Operations Report (Form ONRR-4054)

(e) Costs of transportation or processing if ONRR determines that they are applicable

(f) Any information that ONRR deems relevant regarding the particular lease operation or the salability of the oil

§ 1206.106 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 show both of the following:

(1) How you calculated the value that you reported, including all adjustments for location, quality, and transportation.

(2) How you complied with these rules.

(b) You can find recordkeeping requirements in parts 1207 and 1212 of this chapter.

(c) ONRR may review and audit your data, and ONRR will direct you to use a different value if we determine that the reported value is inconsistent with the requirements of this subpart.

§ 1206.107 What are my responsibilities to place production into marketable condition and to market production?

(a) 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.

(b) If you use gross proceeds under an arm's-length contract in determining value, you must increase those gross proceeds to the extent that the purchaser, or any other person, provides certain services that the seller normally would be responsible to perform to place the oil in marketable condition or to market the oil.

§ 1206.108 How do I request a valuation determination?

(a) You may request a valuation determination from ONRR regarding any oil produced. Your request must:

(1) Be in writing;

(2) Identify, specifically, all leases involved, all interest owners of those leases, the designee(s), and the operator(s) for those leases;

(3) Completely explain all relevant facts; you must inform ONRR of any changes to relevant facts that occur before we respond to your request;

(4) Include copies of all relevant documents;

(5) Provide your analysis of the issue(s), including citations to all relevant precedents (including adverse precedents); and

(6) Suggest your proposed valuation method.

(b) In response to your request, ONRR may:

(1) Request that the Assistant Secretary for Policy, Management and Budget issue a valuation determination;

(2) Decide that ONRR will issue guidance; or

(3) Inform you in writing that ONRR will not provide a determination or guidance. Situations in which ONRR typically will not provide any determination or guidance include, but are not limited to, the following:

(i) Requests for guidance on hypothetical situations

(ii) Matters that are the subject of pending litigation or administrative appeals

(c)(1) A valuation determination that the Assistant Secretary for Policy, Management and Budget signs is binding on both you and ONRR until the Assistant Secretary modifies or rescinds it.

(2) After the Assistant Secretary issues a valuation determination, you must make any adjustments to royalty payments that follow from the determination and, if you owe additional royalties, you must pay the additional royalties due, plus late payment interest calculated under §§ 1218.54 and 1218.102 of this chapter.

(3) A valuation determination that the Assistant Secretary signs is the final action of the Department and is subject to judicial review under 5 U.S.C. 701-706.

(d) Guidance that ONRR issues is not binding on ONRR, delegated States, or you with respect to the specific situation addressed in the guidance.

(1) Guidance and ONRR's decision whether or not to issue guidance or request an Assistant Secretary determination, or neither, under paragraph (b) of this section, are not appealable decisions or orders under 30 CFR part 1290.

(2) If you receive an order requiring you to pay royalty on the same basis as the guidance, you may appeal that order under 30 CFR part 1290.

(e) ONRR or the Assistant Secretary may use any of the applicable valuation criteria in this subpart to provide guidance or to make a determination.

(f) A change in an applicable statute or regulation on which ONRR or the Assistant Secretary based any determination or guidance takes precedence over the determination or guidance, regardless of whether ONRR or the Assistant Secretary modifies or rescinds the determination or guidance.

(g) ONRR or the Assistant Secretary generally will not retroactively modify or rescind a valuation determination issued under paragraph (d) of this section, unless:

(1) There was a misstatement or omission of material facts; or

(2) The facts subsequently developed are materially different from the facts on which the guidance was based.

(h) ONRR may make requests and replies under this section available to the public, subject to the confidentiality requirements under § 1206.109.

§ 1206.109 Does ONRR protect information that I provide?

(a) Certain information that you or your affiliate submit(s) to ONRR regarding valuation of oil, including transportation allowances, may be exempt from disclosure.

(b) To the extent that applicable laws and regulations permit, ONRR will keep confidential any data that you or your affiliate submit(s) that is privileged, confidential, or otherwise exempt from disclosure.

(c) You and others must submit all requests for information under the Freedom of Information Act regulations of the Department of the Interior at 43 CFR part 2.

§ 1206.110 What general transportation allowance requirements apply to me?

(a) ONRR will allow a deduction for the reasonable, actual costs to transport oil from the lease to the point off of the lease under § 1206.110, § 1206.111, or § 1206.112, as applicable. You may not deduct transportation costs that you incur to move a particular volume of production to reduce royalties that you owe on production for which you did not incur those costs. This paragraph applies when:

(1)(i) The movement to the sales point is not gathering;

(ii) For oil produced on the OCS, the movement of oil from the wellhead to the first platform is not transportation; and

(2) You value oil under § 1206.101 based on a sale at a point off of the lease, unit, or communitized area where the oil is produced; or

(3) You do not value your oil under § 1206.102(a)(3) or (b)(3).

(b) You must calculate the deduction for transportation costs based on your or your affiliate's cost of transporting each product through each individual transportation system. If your or your affiliate's transportation contract includes more than one liquid product, you must allocate costs consistently and equitably to each of the liquid products that are transported. Your allocation must use the same proportion as the ratio of the volume of each liquid product (excluding waste products with no value) to the volume of all liquid products (excluding waste products with no value).

(1) You may not take an allowance for transporting lease production that is not royalty-bearing.

(2) You may propose to ONRR a prospective cost allocation method based on the values of the liquid products transported. ONRR will approve the method if it is consistent with the purposes of the regulations in this subpart.

(3) You may use your proposed procedure to calculate a transportation allowance beginning with the production month following the month when ONRR received your proposed procedure until ONRR accepts or rejects your cost allocation. If ONRR rejects your cost allocation, you must amend your form ONRR-2014 for the months that you used the rejected method and pay any additional royalty due, plus late payment interest.

(c)(1) Where you or your affiliate transport(s) both gaseous and liquid products through the same transportation system, you must propose a cost allocation procedure to ONRR.

(2) You may use your proposed procedure to calculate a transportation allowance until ONRR accepts or rejects your cost allocation. If ONRR rejects your cost allocation, you must amend your form ONRR-2014 for the months when 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 three months after you first claim the allocated deductions on form ONRR-2014.

(d)(1) Your transportation allowance may not exceed 50 percent of the value of the oil, as determined under § 1206.101 of this subpart.

(2) If ONRR approved your request to take a transportation allowance in excess of the 50-percent limitation under former § 1206.109(c), that approval is terminated as of January 1, 2017.

(e) You must express transportation allowances for oil as a dollar-value equivalent. If your or your affiliate's payments for transportation under a contract are not on a dollar-per-unit basis, you must convert whatever consideration you or your affiliate are paid to a dollar-value equivalent.

(f) ONRR may determine your transportation allowance under § 1206.105 because:

(1) There is misconduct by or between the contracting parties;

(2) ONRR determines that the consideration that you or your affiliate paid under an arm's-length transportation contract does not reflect the reasonable cost of the transportation because you breached your duty to market the oil for the mutual benefit of yourself and the lessor by transporting your oil at a cost that is unreasonably high. We may consider a transportation allowance to be unreasonably high if it is 10 percent higher than the highest reasonable measures of transportation costs including, but not limited to, transportation allowances reported to ONRR and tariffs for gas, residue gas, or gas plant product transported through the same system; or

(3) ONRR cannot determine if you properly calculated a transportation allowance under § 1206.111 or § 1206.112 for any reason, including, but not limited to, your or your affiliate's failure to provide documents that ONRR requests under 30 CFR part 1212, subpart B.

(g) You do not need ONRR's approval before reporting a transportation allowance.

§ 1206.111 How do I determine a transportation allowance if I have an arm's-length transportation contract?

(a)(1) 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 § 1206.110(f) and subject to the limitation in § 1206.110(d).

(2) You must be able to demonstrate that your or your affiliate's contract is at arm's-length.

(3) You do not need ONRR's approval before reporting a transportation allowance for costs incurred under an arm's-length transportation contract.

(b) Subject to the requirements of paragraph (c) of this section, you may include, but are not limited to, the following costs to determine your transportation allowance under paragraph (a) 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 section including, but not limited to:

(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) Fees paid to a terminal operator for loading and unloading of crude oil into or from a vessel, vehicle, pipeline, or other conveyance.

(5) Fees paid for short-term storage (30 days or less) incidental to transportation as a transporter requires.

(6) Fees paid to pump oil to another carrier's system or vehicles as required under a tariff.

(7) 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.

(8) 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.

(9) Costs of securing a letter of credit, or other surety, that the pipeline requires you, as a shipper, to maintain.

(10) Hurricane surcharges that you or your affiliate actually pay(s).

(11) 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:

(i) First, multiply the volume that the pipeline requires you to maintain—and that you do maintain—in the pipeline by the value of that volume for the current month calculated under § 1206.101 or § 1206.102, as applicable.

(ii) Second, multiply the value calculated under paragraph (b)(11)(i) of this section by the monthly rate of return, calculated by dividing the rate of return specified in § 1206.112(i)(3) by 12.

(c) You may not include the following costs to determine your transportation allowance under paragraph (a) of this section:

(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 you have no written contract for the arm's-length transportation of oil, then ONRR will determine your transportation allowance under § 1206.105. You may not use this paragraph (d) if you or your affiliate perform(s) your own transportation.

(1) You must propose to ONRR a method to determine the allowance using the procedures in § 1206.108(a).

(2) You may use that method to determine your allowance until ONRR issues its determination.

§ 1206.112 How do I determine a transportation allowance if I do not have an arm's-length transportation contract?

(a) This section applies if you or your affiliate do(es) not have an arm's-length transportation contract, including situations where you or your affiliate provide your own transportation services. You must 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 may include the following:

(1) Capital costs and operating and maintenance expenses under paragraphs (e), (f), and (g) of this section.

(2) Overhead under paragraph (h) of this section.

(3)(i) Depreciation and a return on undepreciated capital investment under paragraph (i)(1) of this section, or you may elect to use a cost equal to a return on the initial depreciable capital investment in the transportation system under paragraph (i)(2) of this section. After you have elected to use either method for a transportation system, you may not later elect to change to the other alternative without ONRR's approval. If ONRR accepts your request to change methods, you may use your changed method beginning with the production month following the month when ONRR received your change request.

(ii) A return on the reasonable salvage value under paragraph (i)(1)(iii) of this section after you have depreciated the transportation system to its reasonable salvage value.

(c) To the extent not included in costs identified in paragraphs (e) through (h) of this section.

(1) If you or your affiliate incur(s) the following actual costs under your or your affiliate's non-arm's-length contract, you may include these costs in your calculations under this section:

(i) 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

(ii) 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

(iii) 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

(iv) Fees paid to a non-affiliated quality bank administrator for administration of a quality bank

(v) 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) First, multiply the volume that the pipeline requires you to maintain—and that you do maintain—in the pipeline by the value of that volume for the current month calculated under § 1206.101 or § 1206.102, as applicable.

(B) Second, multiply the value calculated under paragraph (c)(1)(v)(A) of this section by the monthly rate of return, calculated by dividing the rate of return specified in paragraph (i)(3) of this section by 12.

(2) You may not include in your transportation allowance:

(i) Any of the costs identified under § 1206.111(c); and/or

(ii) Fees paid (either in volume or in value) for actual or theoretical line losses.

(d) You may not use any cost as a deduction that duplicates all or part of any other cost that you use under this section.

(e) Allowable capital investment costs are generally those for depreciable fixed assets (including the costs of delivery and installation of capital equipment) that are an integral part of the transportation system.

(f) Allowable operating expenses include the following:

(1) Operations supervision and engineering

(2) Operations labor

(3) Fuel

(4) Utilities

(5) Materials

(6) Ad valorem property taxes

(7) Rent

(8) Supplies

(9) Any other directly allocable and attributable operating expense that you can document

(g) Allowable maintenance expenses include the following:

(1) Maintenance of the transportation system

(2) Maintenance of equipment

(3) Maintenance labor

(4) Other directly allocable and attributable maintenance expenses that you can document

(h) 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.

(i)(1) To calculate depreciation and a return on undepreciated capital investment, you may elect to use either a straight-line depreciation method (based on the life of equipment or on the life of the reserves that the transportation system services), or you may elect to use a unit-of-production method. After you make an election, you may not change methods without ONRR's approval. If ONRR accepts your request to change methods, you may use your changed method beginning with the production month following the month when ONRR received your change request.

(i) A change in ownership of a transportation system will not alter the depreciation schedule that the original transporter/lessee established for purposes of the allowance calculation.

(ii) You may depreciate a transportation system, with or without a change in ownership, only once.

(iii)(A) To calculate the return on undepreciated capital investment, you may use an amount equal to the undepreciated capital investment in the transportation system multiplied by the rate of return that you determine under paragraph (i)(3) of this section.

(B) After you have depreciated a transportation system to the reasonable salvage value, you may continue to include in the allowance calculation a cost equal to the reasonable salvage value multiplied by a rate of return under paragraph (i)(3) of this section.

(2) As an alternative to using depreciation and a return on undepreciated capital investment, as provided under paragraph (b)(3) of this section, you may use as a cost an amount equal to the allowable initial capital investment in the transportation system multiplied by the rate of return determined under paragraph (i)(3) of this section. You may not include depreciation in your allowance.

(3) The rate of return is the industrial rate associated with Standard & Poor's BBB rating.

(i) You must use the monthly average BBB rate that Standard & Poor's publishes for the first month for which the allowance is applicable.

(ii) You must re-determine the rate at the beginning of each subsequent calendar year.

§ 1206.113 What adjustments and transportation allowances apply when I value oil production from my lease using NYMEX prices or ANS spot prices?

This section applies when you use NYMEX prices or ANS spot prices to calculate the value of production under § 1206.102. As specified in this section, you must adjust the NYMEX price to reflect the difference in value between your lease and Cushing, Oklahoma, or adjust the ANS spot price to reflect the difference in value between your lease and the appropriate ONRR-recognized market center at which the ANS spot price is published (for example, Long Beach, California, or San Francisco, California). Paragraph (a) of this section explains how you adjust the value between the lease and the market center, and paragraph (b) of this section explains how you adjust the value between the market center and Cushing when you use NYMEX prices. Paragraph (c) of this section explains how adjustments may be made for quality differentials that are not accounted for through exchange agreements. Paragraph (d) of this section gives some examples. References in this section to “you” include your affiliates, as applicable.

(a) To adjust the value between the lease and the market center:

(1)(i) For oil that you exchange at arm's-length between your lease and the market center (or between any intermediate points between those locations), you must calculate a lease-to-market center differential by the applicable location and quality differentials derived from your arm's-length exchange agreement applicable to production during the production month.

(ii) For oil that you exchange between your lease and the market center (or between any intermediate points between those locations) under an exchange agreement that is not at arm's-length, you must obtain approval from ONRR for a location and quality differential. Until you obtain such approval, you may use the location and quality differential derived from that exchange agreement applicable to production during the production month. If ONRR prescribes a different differential, you must apply ONRR's differential to all periods for which you used your proposed differential. You must pay any additional royalties due resulting from using ONRR's differential, plus late payment interest from the original royalty due date, or you may report a credit for any overpaid royalties, plus interest, under 30 U.S.C. 1721(h).

(2) For oil that you transport between your lease and the market center (or between any intermediate points between those locations), you may take an allowance for the cost of transporting that oil between the relevant points, as determined under § 1206.111 or 1206.112, 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, you must determine the adjustment between the lease and the market center for the oil that is not transported or exchanged (or both transported and exchanged) to or through a market center as follows:

(i) Determine the volume-weighted average of the lease-to-market center adjustment calculated under paragraphs (a)(1) and (2) of this section for the oil that you do transport or exchange (or both transport and exchange) from your lease to a market center.

(ii) Use that volume-weighted average lease-to-market center adjustment as the adjustment for the oil that you do not transport or exchange (or both transport and exchange) from your lease to a market center.

(4) If you transport or exchange (or both transport and exchange) less than 20 percent of the crude oil produced from your lease between the lease and a market center, you must propose to ONRR an adjustment between the lease and the market center for the portion of the oil that you do not transport or exchange (or both transport and exchange) to a market center. Until you obtain such approval, you may use your proposed adjustment. If ONRR prescribes a different adjustment, you must apply ONRR's adjustment to all periods for which you used your proposed adjustment. You must pay any additional royalties due resulting from using ONRR's adjustment, plus late payment interest from the original royalty due date, or you may report a credit for any overpaid royalties plus interest under 30 U.S.C. 1721(h).

(5) You may not both take a transportation allowance and use a location and quality adjustment or exchange differential for the same oil between the same points.

(b) For oil that you value using NYMEX prices, you must 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 of the oil that 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 of the oil that you produce from the leases during that production month for which that market center is used.

(2) If paragraph (b)(1) of this section does not apply, you must use the WTI differential published in an ONRR-approved publication for the market center nearest to 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, you must use the WTI differential for Light Louisiana Sweet crude oil at St. James, Louisiana. After you select an ONRR-approved publication, you may not select a different publication more often than once every two years, unless the publication you use is no longer published or ONRR revokes its approval of the publication. If you must change publications, you must begin a new two-year period.

(3) If neither paragraph (b)(1) nor (2) of this section applies, you may propose an alternative differential to ONRR. Until you obtain such approval, you may use your proposed differential. If ONRR prescribes a different differential, you must apply ONRR's differential to all periods for which you used your proposed differential. You must pay any additional royalties due resulting from using ONRR's differential, plus late payment interest from the original royalty due date, or you may report a credit for any overpaid royalties plus interest under 30 U.S.C. 1721(h).

(c)(1) If you adjust for location and quality differentials or for transportation costs under paragraphs (a) and (b) of this section, you also must 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 that BSEE or BLM, as applicable, approve. You must 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.

(i) You may request prior ONRR approval to use a different adjustment.

(ii) If ONRR approves your request to use a different quality adjustment, you may begin using that adjustment for the production month following the month when ONRR received your request.

(d) The examples in this paragraph illustrate how to apply the requirement of this section.

(1) Example 1. 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 that the lessee refines the oil received in exchange at Midland. Assume that the NYMEX price is $86.21/bbl, adjusted for the roll; that the WTI differential (Cushing to Midland) is−$2.27/bbl; that the lessee's exchange agreement between Roswell and Midland results in a location and quality differential of−$0.08/bbl; and that the lessee's actual cost of transporting the oil from Artesia to Roswell is $0.40/bbl. In this example, the royalty value of the oil is $86.21−$2.27−$0.08−$0.40 = $83.46/bbl.

(2) Example 2. Assume the same facts as in the example in paragraph (d)(1) of this section, except that the lessee transports and exchanges to Midland 40 percent of the production from the lease near Artesia and transports the remaining 60 percent directly to its own refinery in Ohio. In this example, the 40 percent of the production would be valued at $83.46/bbl, as explained in the previous example. In this example, the other 60 percent also would be valued at $83.46/bbl.

(3) Example 3. 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 that it refines. Assume that the ANS spot price is $105.65/bbl and that the lessee's actual cost of transporting the oil from Bakersfield to Hynes Station is $0.28/bbl. The lessee must request approval from ONRR for a location and quality adjustment between Hynes Station and Long Beach. For example, the lessee likely would propose using the tariff on Line 63 from Hynes Station to Long Beach as the adjustment between those points. Assume that adjustment to be $0.72, including the sulfur and gravity bank adjustments, and that ONRR approves the lessee's request. In this example, the preliminary (because the location and quality adjustment is subject to ONRR's review) royalty value of the oil is $105.65 −$0.72 −$0.28 = $104.65/bbl. The fact that oil was exchanged to Cushing does not change the use of ANS spot prices for royalty valuation.

§ 1206.114 How will ONRR identify market centers?

ONRR will monitor market activity and, if necessary, add to or modify the list of market centers that we publish to www.onrr.gov. ONRR will consider the following factors and conditions in specifying market centers:

(a) Points where ONRR-approved publications publish prices useful for index purposes

(b) Markets served

(c) Input from industry and others knowledgeable in crude oil marketing and transportation

(d) Simplification

(e) Other relevant matters

§ 1206.115 What are my reporting requirements under an arm's-length transportation contract?

(a) You must use a separate entry on form ONRR-2014 to notify ONRR of an allowance based on transportation costs that you or your affiliate incur(s).

(b) ONRR may require you or your affiliate to submit arm's-length transportation contracts, production agreements, operating agreements, and related documents.

(c) You can find recordkeeping requirements in parts 1207 and 1212 of this chapter.

§ 1206.116 What are my reporting requirements under a non-arm's-length transportation contract?

(a) You must use a separate entry on form ONRR-2014 to notify ONRR of an allowance based on transportation costs that you or your affiliate incur(s).

(b)(1) For new non-arm's-length transportation facilities or arrangements, you must base your initial deduction on estimates of allowable transportation costs for the applicable period.

(2) You must use your or your affiliate's most recently available operations data for the transportation system as your estimate, if available. If such data is not available, you must use estimates based on data for similar transportation systems.

(3) Section 1206.118 applies when you amend your report based on the actual costs.

(c) ONRR may require you or your affiliate to submit all data used to calculate the allowance deduction. You may find recordkeeping requirements in parts 1207 and 1212 of this chapter.

(d) If you are authorized under § 1206.112(j) to use an exception to the requirement to calculate your actual transportation costs, you must follow the reporting requirements of § 1206.115.

§ 1206.117 What interest and penalties apply if I improperly report a transportation allowance?

(a) If you deduct a transportation allowance on form ONRR-2014 that exceeds 50 percent of the value of the oil transported, you must pay additional royalties due, plus late payment interest calculated under §§ 1218.54 and 1218.102 of this chapter, on the excess allowance amount taken from the date when that amount is taken to the date when you pay the additional royalties due.

(b) If you improperly net a transportation allowance against the oil instead of reporting the allowance as a separate entry on form ONRR-2014, ONRR may assess a civil penalty under 30 CFR part 1241.

§ 1206.118 What reporting adjustments must I make for transportation allowances?

(a) If your actual transportation allowance is less than the amount that you claimed on form ONRR-2014 for each month during the allowance reporting period, you must pay additional royalties due, plus late payment interest calculated under §§ 1218.54 and 1218.102 of this chapter from the date when you took the deduction to the date when you repay the difference.

(b) If the actual transportation allowance is greater than the amount that you claimed on form ONRR-2014 for any month during the period reported on the allowance form, you are entitled to a credit plus interest.

§ 1206.119 How do I determine royalty quantity and quality?

(a) You must calculate royalties based on the quantity and quality of oil as measured at the point of royalty settlement that BLM or BSEE approves for onshore leases and OCS leases, respectively.

(b) If you base the value of oil determined under this subpart on a quantity and/or quality that is different from the quantity and/or quality at the point of royalty settlement that BLM or BSEE approves, you must adjust that value for the differences in quantity and/or quality.

(c) You may not make any deductions from the royalty volume or royalty value for actual or theoretical losses. Any actual loss that you sustain before the royalty settlement metering or measurement point is not subject to royalty if BLM or BSEE, whichever is appropriate, determines that such loss was unavoidable.

(d) You must pay royalties 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 you claim to have taken place either before or after the approved point of royalty settlement.

§ 1206.140 What is the purpose and scope of this subpart?

(a) This subpart applies to all gas 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 mineral leasing laws, other applicable laws, and lease terms.

(b) The terms “you” and “your” in this subpart refer to the lessee.

(c) If the regulations in this subpart are inconsistent with a(an): Federal statute; settlement agreement between the United States and a lessee resulting from administrative or judicial litigation; written agreement between the lessee and ONRR's Director establishing a method to determine the value of production from any lease that ONRR expects would at least approximate the value established under this subpart; 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.

(d) ONRR may audit and order you to adjust all royalty payments.

§ 1206.141 How do I calculate royalty value for unprocessed gas that I or my affiliate sell(s) under an arm's-length or non-arm's-length contract?

(a) This section applies to unprocessed gas. Unprocessed gas is:

(1) Gas that is not processed;

(2) Any gas that you are not required to value under § 1206.142 or that ONRR does not value under § 1206.144; or

(3) Any gas that you sell prior to processing based on a price per MMBtu or Mcf when the price is not based on the residue gas and gas plant products.

(b) The value of gas under this section for royalty purposes is the gross proceeds accruing to you or your affiliate under the first arm's-length contract less a transportation allowance determined under § 1206.152. This value does not apply if you exercise the option in paragraph (c) of this section or if ONRR decides to value your gas under § 1206.144. You must use this paragraph (b) to value gas when:

(1) You sell under an arm's-length contract;

(2) You sell or transfer unprocessed gas to your affiliate or another person under a non-arm's-length contract and that affiliate or person, or an affiliate of either of them, then sells the gas under an arm's-length contract, unless you exercise the option provided in paragraph (c) of this section;

(3) You, your affiliate, or another person sell(s) unprocessed gas produced from a lease under multiple arm's-length contracts, and that gas is valued under this paragraph. Unless you exercise the option provided in paragraph (c) of this section, the value of the gas is the volume-weighted average of the values, established under this paragraph, for each contract for the sale of gas produced from that lease; or

(4) You or your affiliate sell(s) under a pipeline cash-out program. In that case, for over-delivered volumes within the tolerance under a pipeline cash-out program, the value is the price that the pipeline must pay you or your affiliate under the transportation contract. You must 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.

(c) If you do not sell under an arm's-length contract, you may elect to value your gas under this paragraph (c). You may not change your election more often than once every two years.

(1)(i) If you can only transport gas to one index pricing point published in an ONRR-approved publication, available at www.onrr.gov, your value, for royalty purposes, is the highest reported monthly bidweek price for that index pricing point for the production month.

(ii) If you can transport gas to more than one index pricing point published in an ONRR-approved publication available at www.onrr.gov, your value, for royalty purposes, is the highest reported monthly bidweek price for the index pricing points to which your gas could be transported for the production month, whether or not there are constraints for that production month.

(iii) If there are sequential index pricing points on a pipeline, you must use the first index pricing point at or after your gas enters the pipeline.

(iv) You must reduce the number calculated under paragraphs (c)(1)(i) and (c)(1)(ii) of this section by 5 percent for sales from the OCS Gulf of Mexico and by 10 percent for sales from all other areas, but not by less than 10 cents per MMBtu or more than 30 cents per MMBtu.

(v) After you select an ONRR-approved publication available at www.onrr.gov, you may not select a different publication more often than once every two years.

(vi) ONRR may exclude an individual index pricing point found in an ONRR-approved publication if ONRR determines that the index pricing point does not accurately reflect the values of production. ONRR will publish a list of excluded index pricing points available at www.onrr.gov.

(2) You may not take any other deductions from the value calculated under this paragraph (c).

(d) If some of your gas is used, lost, unaccounted for, or retained as a fee under the terms of a sales or service agreement, that gas will be valued for royalty purposes using the same royalty valuation method for valuing the rest of the gas that you do sell.

(e) If you have no written contract for the sale of gas or no sale of gas subject to this section and:

(1) There is an index pricing point for the gas, then you must value your gas under paragraph (c) of this section; or

(2) There is not an index pricing point for the gas, then ONRR will decide the value under § 1206.144.

(i) You must propose to ONRR a method to determine the value using the procedures in § 1206.148(a).

(ii) You may use that method to determine value, for royalty purposes, until ONRR issues our decision.

(iii) After ONRR issues our determination, you must make the adjustments under § 1206.143(a)(2).

§ 1206.142 How do I calculate royalty value for processed gas that I or my affiliate sell(s) under an arm's-length or non-arm's-length contract?

(a) This section applies to the valuation of processed gas, including but not limited to:

(1) Gas that you or your affiliate do not sell, or otherwise dispose of, under an arm's-length contract prior to processing.

(2) Gas where your or your affiliate's arm's-length contract for the sale of gas prior to processing provides for payment to be determined on the basis of the value of any products resulting from processing, including residue gas or natural gas liquids.

(3) Gas that you or your affiliate process under an arm's-length keepwhole contract.

(4) Gas where your or your affiliate's arm's-length contract includes a reservation of the right to process the gas, and you or your affiliate exercise(s) that right.

(b) The value of gas subject to this section, for royalty purposes, is the combined value of the residue gas and all gas plant products that you determine under this section plus the value of any condensate recovered downstream of the point of royalty settlement without resorting to processing that you determine under subpart C of this part less applicable transportation and processing allowances that you determine under this subpart, unless you exercise the option provided in paragraph (d) of this section.

(c) The value of residue gas or any gas plant product under this section for royalty purposes is the gross proceeds accruing to you or your affiliate under the first arm's-length contract. This value does not apply if you exercise the option provided in paragraph (d) of this section, or if ONRR decides to value your residue gas or any gas plant product under § 1206.144. You must use this paragraph (c) to value residue gas or any gas plant product when:

(1) You sell under an arm's-length contract;

(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 residue gas or any gas plant product under an arm's-length contract, unless you exercise the option provided in paragraph (d) of this section;

(3) You, your affiliate, or another person sell(s), under multiple arm's-length contracts, residue gas or any gas plant products recovered from gas produced from a lease that you value under this paragraph. In that case, unless you exercise the option provided in paragraph (d) of this section, because you sold non-arm's-length to your affiliate or another person, the value of the residue gas or any gas plant product is the volume-weighted average of the gross proceeds established under this paragraph for each arm's-length contract for the sale of residue gas or any gas plant products recovered from gas produced from that lease; or

(4) You or your affiliate sell(s) under a pipeline cash-out program. In that case, for over-delivered volumes within the tolerance under a pipeline cash-out program, the value is the price that the pipeline must pay to you or your affiliate under the transportation contract. You must 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.

(d) If you do not sell under an arm's-length contract, you may elect to value your residue gas and NGLs under this paragraph (d). You may not change your election more often than once every two years.

(1)(i) If you can only transport residue gas to one index pricing point published in an ONRR-approved publication available at www.onrr.gov, your value, for royalty purposes, is the highest reported monthly bidweek price for that index pricing point for the production month.

(ii) If you can transport residue gas to more than one index pricing point published in an ONRR-approved publication available at www.onrr.gov, your value, for royalty purposes, is the highest reported monthly bidweek price for the index pricing points to which your gas could be transported for the production month, whether or not there are constraints, for the production month.

(iii) If there are sequential index pricing points on a pipeline, you must use the first index pricing point at or after your residue gas enters the pipeline.

(iv) You must reduce the number calculated under paragraphs (d)(1)(i) and (ii) of this section by 5 percent for sales from the OCS Gulf of Mexico and by 10 percent for sales from all other areas, but not by less than 10 cents per MMBtu or more than 30 cents per MMBtu.

(v) After you select an ONRR-approved publication available at www.onrr.gov, you may not select a different publication more often than once every two years.

(vi) ONRR may exclude an individual index pricing point found in an ONRR-approved publication if ONRR determines that the index pricing point does not accurately reflect the values of production. ONRR will publish a list of excluded index pricing points on www.onrr.gov.

(2)(i) If you sell NGLs in an area with one or more ONRR-approved commercial price bulletins available at www.onrr.gov, you must choose one bulletin, and your value, for royalty purposes, is the monthly average price for that bulletin for the production month.

(ii) You must reduce the number calculated under paragraph (d)(2)(i) of this section by the amounts that ONRR posts at www.onrr.gov for the geographic location of your lease. The methodology that ONRR will use to calculate the amounts is set forth in the preamble to this regulation. This methodology is binding on you and ONRR. ONRR will update the amounts periodically using this methodology.

(iii) After you select an ONRR-approved commercial price bulletin available at www.onrr.gov, you may not select a different commercial price bulletin more often than once every two years.

(3) You may not take any other deductions from the value calculated under this paragraph (d).

(4) ONRR will post changes to any of the rates in this paragraph (d) on its website.

(e) If some of your gas or gas plant products are used, lost, unaccounted for, or retained as a fee under the terms of a sales or service agreement, that gas will be valued for royalty purposes using the same royalty valuation method for valuing the rest of the gas or gas plant products that you do sell.

(f) If you have no written contract for the sale of gas or no sale of gas subject to this section and:

(1) There is an index pricing point or commercial price bulletin for the gas, then you must value your gas under paragraph (d) of this section.

(2) There is not an index pricing point or commercial price bulletin for the gas, then ONRR will determine the value under § 1206.144.

(i) You must propose to ONRR a method to determine the value using the procedures in § 1206.148(a).

(ii) You may use that method to determine value, for royalty purposes, until ONRR issues our decision.

(iii) After ONRR issues our determination, you must make the adjustments under § 1206.143(a)(2).

§ 1206.143 How will ONRR determine if my royalty payments are correct?

(a)(1) ONRR may monitor, review, and audit the royalties that you report. If ONRR determines that your reported value is inconsistent with the requirements of this subpart, ONRR will direct you to use a different measure of royalty value or decide your value under § 1206.144.

(2) If ONRR directs you to use a different royalty value, you must either pay any additional royalties due, plus late payment interest calculated under §§ 1218.54 and 1218.102 of this chapter, or report a credit for, or request a refund of, any overpaid royalties.

(b) When the provisions in this subpart refer to gross proceeds, in conducting reviews and audits, ONRR will examine if your or your affiliate's contract reflects the total consideration actually transferred, either directly or indirectly, from the buyer to you or your affiliate for the gas, residue gas, or gas plant products. If ONRR determines that a contract does not reflect the total consideration, ONRR may decide your value under § 1206.144.

(c) ONRR may decide your value under § 1206.144 if ONRR determines that the gross proceeds accruing to you or your affiliate under a contract do not reflect reasonable consideration because:

(1) There is misconduct by or between the contracting parties;

(2) You have breached your duty to market the gas, residue gas, or gas plant products for the mutual benefit of yourself and the lessor by selling your gas, residue gas, or gas plant products at a value that is unreasonably low. ONRR may consider a sales price unreasonably low if it is 10 percent less than the lowest reasonable measures of market price, including, but not limited to, index prices and prices reported to ONRR for like-quality gas, residue gas, or gas plant products; or

(3) ONRR cannot determine if you properly valued your gas, residue gas, or gas plant products under § 1206.141 or § 1206.142 for any reason, including, but not limited to, your or your affiliate's failure to provide documents that ONRR requests under 30 CFR part 1212, subpart B.

(d) You have the burden of demonstrating that your or your affiliate's contract is arm's-length.

(e) ONRR may require you to certify that the provisions in your or your affiliate's contract include(s) all of the consideration that the buyer paid to you or your affiliate, either directly or indirectly, for the gas, residue gas, or gas plant products.

(f)(1) Absent contract revision or amendment, if you or your affiliate fail(s) to take proper or timely action to receive prices or benefits to which you or your affiliate are entitled, you must pay royalty based upon that obtainable price or benefit.

(2) If you or your affiliate make timely application for a price increase or benefit allowed under your or your affiliate's contract, but the purchaser refuses, and you or your affiliate take reasonable, documented measures to force purchaser compliance, you will not owe additional royalties unless or until you or your affiliate receive additional monies or consideration resulting from the price increase. You may not construe this paragraph to permit you to avoid your royalty payment obligation in situations where a purchaser fails to pay, in whole or in part, or in a timely manner, for a quantity of gas, residue gas, or gas plant products.

(g)(1) You or your affiliate must make all contracts, contract revisions, or amendments in writing, and all parties to the contract must sign the contract, contract revisions, or amendments.

(2) If you or your affiliate fail(s) to comply with paragraph (g)(1) of this section, ONRR may decide your value under § 1206.144.

(3) This provision applies notwithstanding any other provisions in this title 30 to the contrary.

§ 1206.144 How will ONRR determine the value of my gas for royalty purposes?

If ONRR decides to value your gas, residue gas, or gas plant products for royalty purposes under § 1206.143, or any other provision in this subpart, then ONRR will determine the value, for royalty purposes, by considering any information that we deem relevant, which may include, but is not limited to:

(a) The value of like-quality gas in the same field or nearby fields or areas.

(b) The value of like-quality residue gas or gas plant products from the same plant or area.

(c) Public sources of price or market information that ONRR deems to be reliable.

(d) Information available or reported to ONRR, including, but not limited to, on form ONRR-2014 and form ONRR-4054.

(e) Costs of transportation or processing if ONRR determines that they are applicable.

(f) Any information that ONRR deems relevant regarding the particular lease operation or the salability of the gas.

§ 1206.145 What records must I keep in order to support my calculations of royalty under this subpart?

If you value your gas under this subpart, you must retain all data relevant to the determination of the royalty that you paid. You can find recordkeeping requirements in parts 1207 and 1212 of this chapter.

(a) You must show:

(1) How you calculated the royalty value, including all allowable deductions; and

(2) How you complied with this subpart.

(b) Upon request, you must submit all data to ONRR. You must comply with any such requirement within the time that ONRR specifies.

§ 1206.146 What are my responsibilities to place production into marketable condition and to market production?

(a) You must place gas, residue gas, and gas plant products in marketable condition and market the gas, residue gas, and gas plant products for the mutual benefit of the lessee and the lessor at no cost to the Federal government.

(b) If you use gross proceeds under an arm's-length contract to determine royalty, you must increase those gross proceeds to the extent that the purchaser, or any other person, provides certain services that you normally are responsible to perform in order to place the gas, residue gas, and gas plant products in marketable condition or to market the gas.

§ 1206.147 When is an ONRR audit, review, reconciliation, monitoring, or other like process considered final?

Notwithstanding any provision in these regulations to the contrary, ONRR does not consider any audit, review, reconciliation, monitoring, or other like process that results in ONRR re-determining royalty due, under this subpart, final or binding as against the Federal government or its beneficiaries unless ONRR chooses to, in writing, formally close the audit period.

§ 1206.148 How do I request a valuation determination?

(a) You may request a valuation determination from ONRR regarding any gas produced. Your request must:

(1) Be in writing;

(2) Identify specifically all leases involved, all interest owners of those leases, the designee(s), and the operator(s) for those leases;

(3) Completely explain all relevant facts. You must inform ONRR of any changes to relevant facts that occur before we respond to your request;

(4) Include copies of all relevant documents;

(5) Provide your analysis of the issue(s), including citations to all relevant precedents (including adverse precedents); and

(6) Suggest your proposed valuation method.

(b) In response to your request, ONRR may:

(1) Request that the Assistant Secretary for Policy, Management and Budget issue a determination;

(2) Decide that ONRR will issue guidance; or

(3) Inform you in writing that ONRR will not provide a determination or guidance. Situations in which ONRR typically will not provide any determination or guidance include, but are not limited to:

(i) Requests for guidance on hypothetical situations; or

(ii) Matters that are the subject of pending litigation or administrative appeals.

(c)(1) A determination that the Assistant Secretary for Policy, Management and Budget signs is binding on both you and ONRR until the Assistant Secretary modifies or rescinds it.

(2) After the Assistant Secretary issues a determination, you must make any adjustments to royalty payments that follow from the determination, and, if you owe additional royalties, you must pay the additional royalties due, plus late payment interest calculated under §§ 1218.54 and 1218.102 of this chapter.

(3) A determination that the Assistant Secretary signs is the final action of the Department and is subject to judicial review under 5 U.S.C. 701-706.

(d) Guidance that ONRR issues is not binding on ONRR, delegated States, or you with respect to the specific situation addressed in the guidance.

(1) Guidance and ONRR's decision whether or not to issue guidance or to request an Assistant Secretary determination, or neither, under paragraph (b) of this section, are not appealable decisions or orders under part 1290 of this title.

(2) If you receive an order requiring you to pay royalty on the same basis as the guidance, you may appeal that order under part 1290 of this title.

(e) ONRR or the Assistant Secretary may use any of the applicable criteria in this subpart to provide guidance or to make a determination.

(f) A change in an applicable statute or regulation on which ONRR based any guidance, or the Assistant Secretary based any determination, takes precedence over the determination or guidance after the effective date of the statute or regulation, regardless of whether ONRR or the Assistant Secretary modifies or rescinds the guidance or determination.

(g) ONRR may make requests and replies under this section available to the public, subject to the confidentiality requirements under § 1206.149.

§ 1206.149 Does ONRR protect information that I provide?

(a) Certain information that you or your affiliate submit(s) to ONRR regarding royalties on gas, including deductions and allowances, may be exempt from disclosure.

(b) To the extent that applicable laws and regulations permit, ONRR will keep confidential any data that you or your affiliate submit(s) that is privileged, confidential, or otherwise exempt from disclosure.

(c) You and others must submit all requests for information under the Freedom of Information Act regulations of the Department of the Interior at 43 CFR part 2.

§ 1206.150 How do I determine royalty quantity and quality?

(a)(1) You must calculate royalties based on the quantity and quality of unprocessed gas as measured at the point of royalty settlement that BLM or BSEE approves for onshore leases and OCS leases, respectively.

(2) If you base the value of gas determined under this subpart on a quantity and/or quality that is different from the quantity and/or quality at the point of royalty settlement that BLM or BSEE approves, you must adjust that value 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 you value residue gas and/or gas plant products determined under this subpart on 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 under paragraph (c) of this section, you must adjust that value for the differences in quantity and/or quality.

(c) You must determine the quantity of the residue gas and gas plant products attributable to a lease based on the following procedure:

(1) When you derive the net output of the processing plant from gas obtained from only one lease, you must base the quantity of the residue gas and gas plant products for royalty computation on the net output of the plant.

(2) When you derive the net output of a processing plant from gas obtained from more than one lease producing gas of uniform content, you must base the quantity of the residue gas and gas plant products allocable to each lease on the same proportions as the ratios obtained by dividing the amount of gas delivered to the plant from each lease by the total amount of gas delivered from all leases.

(3) When the net output of a processing plant is derived from gas obtained from more than one lease producing gas of non-uniform content:

(i) You must determine the quantity of the residue gas allocable to each lease by multiplying the amount of gas delivered to the plant from the lease by the residue gas content of the gas, and dividing that arithmetical product 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.

(ii) You must determine the net output of gas plant products allocable to each lease by multiplying the amount of gas delivered to the plant from the lease by the gas plant product content of the gas, dividing that arithmetical product 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) You may request prior ONRR approval of other methods for determining the quantity of residue gas and gas plant products allocable to each lease. If approved, you must apply that method to all gas production from Federal leases that is processed in the same plant. You must do so beginning with the production month following the month when ONRR received your request to use another method.

(d)(1) You may not make any deductions from the royalty volume or royalty value for actual or theoretical losses. Any actual loss of unprocessed gas that you sustain before the royalty settlement meter or measurement point is not subject to royalty if BLM or BSEE, whichever is appropriate, determines that such loss was unavoidable.

(2) Except as provided in paragraph (d)(1) of this section and § 1202.151(c), you must pay royalties due on 100 percent of the volume determined under paragraphs (a) through (c) of this section. You may not reduce that determined volume for actual losses after you have determined the quantity basis, or for theoretical losses that you claim 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. You may not take any deduction from the value of the unprocessed gas, residue gas, and/or gas plant products to compensate for actual losses after you have determined the quantity basis or for theoretical losses that you claim to have taken place.

§ 1206.151 [Reserved]

§ 1206.152 What general transportation allowance requirements apply to me?

(a) ONRR will allow a deduction for the reasonable, actual costs to transport residue gas, gas plant products, or unprocessed gas from the lease to the point off of the lease under § 1206.153 or § 1206.154, as applicable. You may not deduct transportation costs that you incur when moving a particular volume of production to reduce royalties that you owe on production for which you did not incur those costs. This paragraph applies when:

(1) You value unprocessed gas under § 1206.141(b) or residue gas and gas plant products under § 1206.142(b) based on a sale at a point off of the lease, unit, or communitized area where the residue gas, gas plant products, or unprocessed gas is produced; and

(2)(i) The movement to the sales point is not gathering.

(ii) For gas produced on the OCS, the movement of gas from the wellhead to the first platform is not transportation.

(b) You must calculate the deduction for transportation costs based on your or your affiliate's cost of transporting each product through each individual transportation system. If your or your affiliate's transportation contract includes more than one product in a gaseous phase, you must allocate costs consistently and equitably to each of the products transported. 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 products in the gaseous phase (excluding waste products with no value).

(1) You may not take an allowance for transporting lease production that is not royalty-bearing.

(2) You may propose to ONRR a prospective cost allocation method based on the values of the products transported. ONRR will approve the method if it is consistent with the purposes of the regulations in this subpart.

(3) You may use your proposed procedure to calculate a transportation allowance beginning with the production month following the month when ONRR received your proposed procedure until ONRR accepts or rejects your cost allocation. If ONRR rejects your cost allocation, you must amend your form ONRR-2014 for the months when you used the rejected method and pay any additional royalty due, plus late payment interest calculated under §§ 1218.54 and 1218.102 of this chapter.

(c)(1) Where you or your affiliate transport(s) both gaseous and liquid products through the same transportation system, you must propose a cost allocation procedure to ONRR.

(2) You may use your proposed procedure to calculate a transportation allowance until ONRR accepts or rejects your cost allocation. If ONRR rejects your cost allocation, you must amend your form ONRR-2014 for the months when you used the rejected method and pay any additional royalty due, plus late payment interest calculated under §§ 1218.54 and 1218.102 of this chapter.

(3) You must submit your initial proposal, including all available data, within three months after you first claim the allocated deductions on form ONRR-2014.

(d) If you value unprocessed gas under § 1206.141(c) or residue gas and gas plant products under § 1206.142 (d), you may not take a transportation allowance.

(e)(1) Your transportation allowance may not exceed 50 percent of the value of the residue gas, gas plant products, or unprocessed gas as determined under § 1206.141 or § 1206.142 of this subpart.

(2) If ONRR approved your request to take a transportation allowance in excess of the 50-percent limitation under former § 1206.156(c)(3), that approval is terminated as of January 1, 2017.

(f) You must express transportation allowances for residue gas, gas plant products, or unprocessed gas as a dollar-value equivalent. If your or your affiliate's payments for transportation under a contract are not on a dollar-per-unit basis, you must convert whatever consideration that you or your affiliate are/is paid to a dollar-value equivalent.

(g) ONRR may determine your transportation allowance under § 1206.144 because:

(1) There is misconduct by or between the contracting parties;

(2) ONRR determines that the consideration that you or your affiliate paid under an arm's-length transportation contract does not reflect the reasonable cost of the transportation because you breached your duty to market the gas, residue gas, or gas plant products for the mutual benefit of yourself and the lessor by transporting your gas, residue gas, or gas plant products at a cost that is unreasonably high. We may consider a transportation allowance unreasonably high if it is 10 percent higher than the highest reasonable measures of transportation costs, including, but not limited to, transportation allowances reported to ONRR and tariffs for gas, residue gas, or gas plant products transported through the same system; or

(3) ONRR cannot determine if you properly calculated a transportation allowance under § 1206.153 or § 1206.154 for any reason, including, but not limited to, your or your affiliate's failure to provide documents that ONRR requests under 30 CFR part 1212, subpart B.

(h) You do not need ONRR's approval before reporting a transportation allowance.

§ 1206.153 How do I determine a transportation allowance if I have an arm's-length transportation contract?

(a)(1) 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 § 1206.152(g) and subject to the limitation in § 1206.152(e).

(2) You must be able to demonstrate that your or your affiliate's contract is arm's-length.

(b) Subject to the requirements of paragraph (c) of this section, you may include, but are not limited to, the following costs to determine your transportation allowance under paragraph (a) 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 section:

(1) Firm demand charges paid to pipelines. You may deduct firm demand charges or capacity reservation fees that you or your affiliate paid to a pipeline, including charges or fees for unused firm capacity that you or your affiliate have not sold before you report your allowance. If you or your affiliate receive(s) 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 or your affiliate receive(s) 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 form ONRR-2014 by the amount of that payment. You must modify form ONRR-2014 by the amount received or credited for the affected reporting period and pay any resulting royalty due, plus late payment interest calculated under §§ 1218.54 and 1218.102 of this chapter.

(2) Gas Supply Realignment (GSR) costs. The GSR costs result from a pipeline reforming or terminating supply contracts with producers in order 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 that 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. Theoretical losses are not deductible in transportation arrangements unless the transportation allowance is based on arm's-length transportation rates charged under a FERC or State regulatory-approved tariff. If you or your affiliate receive(s) volumes or credit for line gain, you must reduce your transportation allowance accordingly and pay any resulting royalties plus late payment interest calculated under §§ 1218.54 and 1218.102 of this chapter;

(8) Temporary storage services. This includes short-duration storage services that market centers or hubs (commonly referred to as “parking” or “banking”) offer or other temporary storage services that pipeline transporters provide, whether actual or provided as a matter of accounting. Temporary storage is limited to 30 days or fewer.

(9) Supplemental costs for compression, dehydration, and treatment of gas. ONRR allows these costs only if such services are required for transportation and exceed the services necessary to place production into marketable condition required under § 1206.146 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 or your affiliate, as a shipper, to maintain under a transportation contract.

(11) Hurricane surcharges. You may deduct hurricane surcharges that you or your affiliate actually pay(s).

(c) You may not include the following costs to determine your transportation allowance under paragraph (a) of this section:

(1) Fees or costs incurred for storage. This includes storing production in a storage facility, whether on or off of the lease, for more than 30 days.

(2) Aggregator/marketer fees. This includes fees that you or your affiliate pay(s) 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 that you or your affiliate incur(s) as a shipper. These penalties include, but are not limited to:

(i) Over-delivery cash-out penalties. This includes the difference between the price that the pipeline pays to you or your affiliate for over-delivered volumes outside of the tolerances and the price that you or your affiliate receive(s) for over-delivered volumes within the tolerances.

(ii) Scheduling penalties. This includes penalties that you or your affiliate incur(s) 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 that you or your affiliate incur(s) (generally on a monthly basis) for differences between volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point.

(iv) Operational penalties. This includes fees that you or your affiliate incur(s) 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 that you or your affiliate pay(s) to hub operators for administrative services (such as title transfer tracking) necessary to account for the sale of gas within a hub.

(5) Fees paid to brokers. This includes fees that you or your affiliate pay(s) 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 that you or your affiliate pay(s) 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 the sale or movement of production.

(8) Other non-allowable costs. Any cost you or your affiliate incur(s) for services that you are required to provide at no cost to the lessor, including, but not limited to, costs to place your gas, residue gas, or gas plant products into marketable condition disallowed under § 1206.146 and costs of boosting residue gas disallowed under § 1202.151(b).

(d) If you have no written contract for the transportation of gas, then ONRR will determine your transportation allowance under § 1206.144. You may not use this paragraph (d) if you or your affiliate perform(s) your own transportation.

(1) You must propose to ONRR a method to determine the allowance using the procedures in § 1206.148(a).

(2) You may use that method to determine your allowance until ONRR issues its determination.

§ 1206.154 How do I determine a transportation allowance if I have a non-arm's-length transportation contract?

(a) This section applies if you or your affiliate do(es) not have an arm's-length transportation contract, including situations where you or your affiliate provide your own transportation services. You must 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 may include:

(1) Capital costs and operating and maintenance expenses under paragraphs (e), (f), and (g) of this section.

(2) Overhead under paragraph (h) of this section.

(3) Depreciation and a return on undepreciated capital investment under paragraph (i)(1) of this section, or you may elect to use a cost equal to a return on the initial depreciable capital investment in the transportation system under paragraph (i)(2) of this section. After you have elected to use either method for a transportation system, you may not later elect to change to the other alternative without ONRR's approval. If ONRR accepts your request to change methods, you may use your changed method beginning with the production month following the month when ONRR received your change request.

(4) A return on the reasonable salvage value under paragraph (i)(1)(iii) of this section, after you have depreciated the transportation system to its reasonable salvage value.

(c)(1) To the extent not included in costs identified in paragraphs (e) through (g) of this section, if you or your affiliate incur(s) the actual transportation costs listed under § 1206.153(b)(2), (5), and (6) of this subpart under your or your affiliate's non-arm's-length contract, you may include those costs in your calculations under this section. You may not include any of the other costs identified under § 1206.153(b).

(2) You may not include in your calculations under this section any of the non-allowable costs listed under § 1206.153(c).

(d) You may not use any cost as a deduction that duplicates all or part of any other cost that you use under this section.

(e) Allowable capital investment costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the transportation system.

(f) Allowable operating expenses include the following:

(1) Operations supervision and engineering

(2) Operations labor

(3) Fuel

(4) Utilities

(5) Materials

(6) Ad valorem property taxes

(7) Rent

(8) Supplies

(9) Any other directly allocable and attributable operating expense that you can document

(g) Allowable maintenance expenses include the following:

(i) Maintenance of the transportation system

(ii) Maintenance of equipment

(iii) Maintenance labor

(iv) Other directly allocable and attributable maintenance expenses that you can document

(h) 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.

(i)(1) To calculate depreciation and a return on undepreciated capital investment, you may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves that the transportation system services, or you may elect to use a unit-of-production method. After you make an election, you may not change methods without ONRR's approval. If ONRR accepts your request to change methods, you may use your changed method beginning with the production month following the month when ONRR received your change request.

(i) A change in ownership of a transportation system will not alter the depreciation schedule that the original transporter/lessee established for the purposes of the allowance calculation.

(ii) You may depreciate a transportation system only once with or without a change in ownership.

(iii)(A) To calculate the return on undepreciated capital investment, you may use an amount equal to the undepreciated capital investment in the transportation system multiplied by the rate of return that you determine under paragraph (i)(3) of this section.

(B) After you have depreciated a transportation system to the reasonable salvage value, you may continue to include in the allowance calculation a cost equal to the reasonable salvage value multiplied by a rate of return under paragraph (i)(3) of this section.

(2) As an alternative to using depreciation and a return on undepreciated capital investment, as provided under paragraph (b)(3) of this section, you may use as a cost an amount equal to the allowable initial capital investment in the transportation system multiplied by the rate of return determined under paragraph (i)(3) of this section. You may not include depreciation in your allowance.

(3) The rate of return is the industrial rate associated with Standard & Poor's BBB rating.

(i) You must use the monthly average BBB rate that Standard & Poor's publishes for the first month for which the allowance is applicable.

(ii) You must re-determine the rate at the beginning of each subsequent calendar year.

§ 1206.155 What are my reporting requirements under an arm's-length transportation contract?

(a) You must use a separate entry on form ONRR-2014 to notify ONRR of an allowance based on transportation costs that you or your affiliate incur(s).

(b) ONRR may require you or your affiliate to submit arm's-length transportation contracts, production agreements, operating agreements, and related documents.

(c) You can find recordkeeping requirements in parts 1207 and 1212 of this chapter.

§ 1206.156 What are my reporting requirements under a non-arm's-length transportation contract?

(a) You must use a separate entry on form ONRR-2014 to notify ONRR of an allowance based on non-arm's-length transportation costs that you or your affiliate incur(s).

(b)(1) For new non-arm's-length transportation facilities or arrangements, you must base your initial deduction on estimates of allowable transportation costs for the applicable period.

(2) You must use your or your affiliate's most recently available operations data for the transportation system as your estimate. If such data is not available, you must use estimates based on data for similar transportation systems.

(3) Section 1206.158 applies when you amend your report based on your actual costs.

(c) ONRR may require you or your affiliate to submit all data used to calculate the allowance deduction. You can find recordkeeping requirements in parts 1207 and 1212 of this chapter.

§ 1206.157 What interest and penalties apply if I improperly report a transportation allowance?

(a)(1) If ONRR determines that you took an unauthorized transportation allowance, then you must pay any additional royalties due, plus late payment interest calculated under §§ 1218.54 and 1218.102 of this chapter.

(2) If you understated your transportation allowance, you may be entitled to a credit, with interest.

(b) If you deduct a transportation allowance on form ONRR-2014 that exceeds 50 percent of the value of the gas, residue gas, or gas plant products transported, you must pay late payment interest on the excess allowance amount taken from the date when that amount is taken until the date when you pay the additional royalties due.

(c) If you improperly net a transportation allowance against the sales value of the residue gas, gas plant products, or unprocessed gas instead of reporting the allowance as a separate entry on form ONRR-2014, ONRR may assess a civil penalty under 30 CFR part 1241.

§ 1206.158 What reporting adjustments must I make for transportation allowances?

(a) If your actual transportation allowance is less than the amount that you claimed on form ONRR-2014 for each month during the allowance reporting period, you must pay additional royalties due, plus late payment interest calculated under §§ 1218.54 and 1218.102 of this chapter from the date when you took the deduction to the date when you repay the difference.

(b) If the actual transportation allowance is greater than the amount that you claimed on form ONRR-2014 for any month during the period reported on the allowance form, you are entitled to a credit, plus interest.

§ 1206.159 What general processing allowances requirements apply to me?

(a)(1) When you value any gas plant product under § 1206.142(c) of this subpart, you may deduct from the value the reasonable, actual costs of processing.

(2) You do not need ONRR's approval before reporting a processing allowance.

(b) You must allocate processing costs among the gas plant products. You must determine a separate processing allowance for each gas plant product and processing plant relationship. ONRR considers NGLs to be one product.

(c)(1) You may not apply the processing allowance against the value of the residue gas.

(2) The processing allowance deduction on the basis of an individual product may not exceed 66 2/3 percent of the value of each gas plant product determined under § 1206.142(c). Before you calculate the 66 2/3-percent limit, you must first reduce the value for any transportation allowances related to post-processing transportation authorized under § 1206.152.

(3) If ONRR approved your request to take a processing allowance in excess of the limitation in paragraph (c)(2) of this section under former § 1206.158(c)(3), that approval is terminated as of January 1, 2017.

(4) If ONRR approved your request to take an extraordinary cost processing allowance under former § 1206.158(d), ONRR terminates that approval as of January 1, 2017.

(d)(1) ONRR will not allow a processing cost deduction 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.

(2) Where gas is processed for the removal of acid gases, commonly referred to as “sweetening,” ONRR will not allow processing cost deductions for such costs unless the acid gases removed are further processed into a gas plant product.

(A) In such event, you are eligible for a processing allowance determined under this subpart.

(B) ONRR will not grant any processing allowance for processing lease production that is not royalty bearing.

(e) ONRR may determine your processing allowance under § 1206.144 because:

(1) There is misconduct by or between the contracting parties;

(2) ONRR determines that the consideration that you or your affiliate paid under an arm's-length processing contract does not reflect the reasonable cost of the processing because you breached your duty to market the gas, residue gas, or gas plant products for the mutual benefit of yourself and the lessor by processing your gas, residue gas, or gas plant products at a cost that is unreasonably high. We may consider a processing allowance unreasonably high if it is 10 percent higher than the highest reasonable measures of processing costs, including, but not limited to, processing allowances reported to ONRR; or

(3) ONRR cannot determine if you properly calculated a processing allowance under § 1206.160 or § 1206.161 for any reason, including, but not limited to, your or your affiliate's failure to provide documents that ONRR requests under 30 CFR part 1212, subpart B.

§ 1206.160 How do I determine a processing allowance if I have an arm's-length processing contract?

(a)(1) If you or your affiliate incur processing costs under an arm's-length processing contract, you may claim a processing allowance for the reasonable, actual costs incurred, as more fully explained in paragraph (b) of this section, except as provided in paragraphs (a)(3)(i) and (a)(3)(ii) of this section and subject to the limitation in § 1206.159(c)(2).

(2) You must be able to demonstrate that your or your affiliate's contract is arm's-length.

(b)(1) If your or your affiliate's arm's-length processing contract includes more than one gas plant product, and you can determine the processing costs for each product based on the contract, then you must determine the processing costs for each gas plant product under the contract.

(2) If your or your affiliate's arm's-length processing contract includes more than one gas plant product, and you cannot determine the processing costs attributable to each product from the contract, you must propose an allocation procedure to ONRR.

(i) You may use your proposed allocation procedure until ONRR issues its determination.

(ii) You must submit all relevant data to support your proposal.

(iii) ONRR will determine the processing allowance based upon your proposal and any additional information that ONRR deems necessary.

(iv) You must submit the allocation proposal within three months of claiming the allocated deduction on form ONRR-2014.

(3) You may not take an allowance for the costs of processing lease production that is not royalty-bearing.

(4) If your or your affiliate's payments for processing under an arm's-length contract are not based on a dollar-per-unit basis, you must convert whatever consideration that you or your affiliate paid to a dollar-value equivalent.

(c) If you have no written contract for the arm's-length processing of gas, then ONRR will determine your processing allowance under § 1206.144. You may not use this paragraph (c) if you or your affiliate perform(s) your own processing.

(1) You must propose to ONRR a method to determine the allowance using the procedures in § 1206.148(a).

(2) You may use that method to determine your allowance until ONRR issues a determination.

§ 1206.161 How do I determine a processing allowance if I have a non-arm's-length processing contract?

(a) This section applies if you or your affiliate do(es) not have an arm's-length processing contract, including situations where you or your affiliate provide your own processing services. You must calculate your processing allowance based on your or your affiliate's reasonable, actual costs for processing during the reporting period using the procedures prescribed in this section.

(b) Your or your affiliate's actual costs may include:

(1) Capital costs and operating and maintenance expenses under paragraphs (d), (e), and (f) of this section.

(2) Overhead under paragraph (g) of this section.

(3) Depreciation and a return on undepreciated capital investment in accordance with paragraph (h)(1) of this section, or you may elect to use a cost equal to the initial depreciable capital investment in the processing plant under paragraph (h)(2) of this section. After you have elected to use either method for a processing plant, you may not later elect to change to the other alternative without ONRR's approval. If ONRR accepts your request to change methods, you may use your changed method beginning with the production month following the month when ONRR received your change request.

(4) A return on the reasonable salvage value under paragraph (h)(1)(iii) of this section, after you have depreciated the processing plant to its reasonable salvage value.

(c) You may not use any cost as a deduction that duplicates all or part of any other cost that you use under this section.

(d) Allowable capital investment costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment), which are an integral part of the processing plant.

(e) Allowable operating expenses include the following:

(1) Operations supervision and engineering

(2) Operations labor

(3) Fuel

(4) Utilities

(5) Materials

(6) Ad valorem property taxes

(7) Rent

(8) Supplies

(9) Any other directly allocable and attributable operating expense that you can document

(f) Allowable maintenance expenses may include the following:

(1) Maintenance of the processing plant

(2) Maintenance of equipment

(3) Maintenance labor

(4) Other directly allocable and attributable maintenance expenses that you can document

(g) 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 and other fees, including royalties, are not allowable expenses.

(h)(1) To calculate depreciation and a return on undepreciated capital investment, you may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves that the processing plant services, or you may elect to use a unit-of-production method. After you make an election, you may not change methods without ONRR's approval. If ONRR accepts your request to change methods, you may use your changed method beginning with the production month following the month when ONRR received your change request.

(i) A change in ownership of a processing plant will not alter the depreciation schedule that the original processor/lessee established for purposes of the allowance calculation.

(ii) You may depreciate a processing plant only once with or without a change in ownership.

(iii)(A) To calculate a return on undepreciated capital investment, you may use an amount equal to the undepreciated capital investment in the processing plant multiplied by the rate of return that you determine under paragraph (h)(3) of this section.

(B) After you have depreciated a processing plant to its reasonable salvage value, you may continue to include in the allowance calculation a cost equal to the reasonable salvage value multiplied by a rate of return under paragraph (h)(3) of this section.

(2) You may use as a cost an amount equal to the allowable initial capital investment in the processing plant multiplied by the rate of return determined under paragraph (h)(3) of this section. You may not include depreciation in your allowance.

(3) The rate of return is the industrial rate associated with Standard & Poor's BBB rating.

(i) You must use the monthly average BBB rate that Standard & Poor's publishes for the first month for which the allowance is applicable.

(ii) You must re-determine the rate at the beginning of each subsequent calendar year.

(i)(1) You must determine the processing allowance for each gas plant product based on your or your affiliate's reasonable and actual cost of processing the gas. You must base your allocation of costs to each gas plant product upon generally accepted accounting principles.

(2) You may not take an allowance for processing lease production that is not royalty-bearing.

(j) You may apply for an exception from the requirement to calculate actual costs under paragraphs (a) and (b) of this section.

(1) ONRR will grant the exception if:

(i) You have or your affiliate 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 under arm's-length processing contracts.

(2) If ONRR grants the exception, you must use as your processing allowance the volume-weighted average prices charged to other persons under arm's-length contracts for processing at the same plant.

§ 1206.162 What are my reporting requirements under an arm's-length processing contract?

(a) You must use a separate entry on form ONRR-2014 to notify ONRR of an allowance based on arm's-length processing costs that you or your affiliate incur(s).

(b) ONRR may require you or your affiliate to submit arm's-length processing contracts, production agreements, operating agreements, and related documents.

(c) You can find recordkeeping requirements in parts 1207 and 1212 of this chapter.

§ 1206.163 What are my reporting requirements under a non-arm's-length processing contract?

(a) You must use a separate entry on form ONRR-2014 to notify ONRR of an allowance based on non-arm's-length processing costs that you or your affiliate incur(s).

(b)(1) For new non-arm's-length processing facilities or arrangements, you must base your initial deduction on estimates of allowable gas processing costs for the applicable period.

(2) You must use your or your affiliate's most recently available operations data for the processing plant as your estimate, if available. If such data is not available, you must use estimates based on data for similar processing plants.

(3) Section 1206.165 applies when you amend your report based on your actual costs.

(c) ONRR may require you or your affiliate to submit all data used to calculate the allowance deduction. You can find recordkeeping requirements in parts 1207 and 1212 of this chapter.

(d) If you are authorized under § 1206.161(j) to use an exception to the requirement to calculate your actual processing costs, you must follow the reporting requirements of § 1206.162.

§ 1206.164 What interest and penalties apply if I improperly report a processing allowance?

(a)(1) If ONRR determines that you took an unauthorized processing allowance, then you must pay any additional royalties due, plus late payment interest calculated under §§ 1218.54 and 1218.102 of this chapter.

(2) If you understated your processing allowance, you may be entitled to a credit, with interest.

(b) If you deduct a processing allowance on form ONRR-2014 that exceeds 66 2/3 percent of the value of a gas plant product, you must pay late payment interest on the excess allowance amount taken from the date when that amount is taken until the date when you pay the additional royalties due.

(c) If you improperly net a processing allowance against the sales value of a gas plant product instead of reporting the allowance as a separate entry on form ONRR-2014, ONRR may assess a civil penalty under 30 CFR part 1241.

§ 1206.165 What reporting adjustments must I make for processing allowances?

(a) If your actual processing allowance is less than the amount that you claimed on form ONRR-2014 for each month during the allowance reporting period, you must pay additional royalties due, plus late payment interest calculated under §§ 1218.54 and 1218.102 of this chapter from the date when you took the deduction to the date when you repay the difference.

(b) If the actual processing allowance is greater than the amount that you claimed on form ONRR-2014 for any month during the period reported on the allowance form, you are entitled to a credit, plus interest.

§ 1206.170 What does this subpart contain?

This subpart contains royalty valuation provisions applicable to Indian lessees.

(a) This subpart applies to all gas production from Indian (tribal and allotted) oil and gas leases (except leases on the Osage Indian Reservation). The purpose of this subpart is to establish the value of production for royalty purposes consistent with the mineral leasing laws, other applicable laws, and lease terms. This subpart does not apply to Federal leases.

(b) If the specific provisions of any Federal statute, treaty, negotiated agreement, settlement agreement resulting from any administrative or judicial proceeding, or Indian oil and gas lease are inconsistent with any regulation in this subpart, then the Federal statute, treaty, negotiated agreement, settlement agreement, or lease will govern to the extent of that inconsistency.

(c) You may calculate the value of production for royalty purposes under methods other than those the regulations in this title require, but only if you, the tribal lessor, and ONRR jointly agree to the valuation methodology. For leases on Indian allotted lands, you and ONRR must agree to the valuation methodology.

(d) All royalty payments you make to ONRR are subject to monitoring, review, audit, and adjustment.

(e) The regulations in this subpart are intended to ensure that the trust responsibilities of the United States with respect to the administration of Indian oil and gas leases are discharged in accordance with the requirements of the governing mineral leasing laws, treaties, and lease terms.

§ 1206.171 What definitions apply to this subpart?

The following definitions apply to this subpart and to subpart J of part 1202 of this title:

Accounting for comparison means the same as dual accounting.

Active spot market means a market where one or more ONRR-acceptable publications publish bidweek prices (or if bidweek prices are not available, first of the month prices) for at least one index-pricing point in the index zone.

Allowance means a deduction in determining value for royalty purposes. Processing allowance means an allowance for the reasonable, actual costs of processing gas determined under this subpart. Transportation allowance means an allowance for the reasonable, actual cost of transportation determined under this subpart.

Approved Federal Agreement (AFA) means a unit or communitization agreement approved under departmental regulations.

Area means a geographic region at least as large as the defined limits of an oil or gas field, in which oil or gas lease products have similar quality, economic, or legal characteristics. An area may be all lands within the boundaries of an Indian reservation.

Arm's-length contract means a contract or agreement that has been arrived at in the marketplace between independent, nonaffiliated persons with opposing economic interests regarding that contract. For purposes of this subpart, two persons are affiliated if one person controls, is controlled by, or is under common control with another person. The following percentages (based on the instruments of ownership of the voting securities of an entity, or based on other forms of ownership) determine if persons are affiliated:

(1) Ownership in excess of 50 percent constitutes control.

(2) Ownership of 10 through 50 percent creates a presumption of control.

(3) Ownership of less than 10 percent creates a presumption of noncontrol which ONRR may rebut if it demonstrates actual or legal control, including the existence of interlocking directorates. Notwithstanding any other provisions of this subpart, contracts between relatives, either by blood or by marriage, are not arm's-length contracts. ONRR may require the lessee to certify the percentage of ownership or control of the entity. To be considered arm's-length for any production month, a contract must meet the requirements of this definition for that production month as well as when the contract was executed.

Audit means a review, conducted under generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees or other persons who pay royalties, rents, or bonuses on Indian leases.

BIA means the Bureau of Indian Affairs of the Department of the Interior.

BLM means the Bureau of Land Management of the Department of the Interior.

Compression means raising the pressure of gas.

Condensate means liquid hydrocarbons (normally exceeding 40 degrees of API gravity) recovered at the surface without resorting to processing. Condensate is the mixture of liquid hydrocarbons that results from condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground reservoir.

Contract means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.

Dedicated means a contractual commitment to deliver gas production (or a specified portion of production) from a lease or well when that production is specified in a sales contract and that production must be sold pursuant to that contract to the extent that production occurs from that lease or well.

Drip condensate means any condensate recovered downstream of the facility measurement point without resorting to processing. Drip condensate includes condensate recovered as a result of its becoming a liquid during the transportation of the gas removed from the lease or recovered at the inlet of a gas processing plant by mechanical means, often referred to as scrubber condensate.

Dual Accounting (or accounting for comparison) refers to the requirement to pay royalty based on a value which is the higher of the value of gas prior to processing less any applicable allowances as compared to the combined value of drip condensate, residue gas, and gas plant products after processing, less applicable allowances.

Entitlement (or entitled share) means the gas production from a lease, or allocable to lease acreage under the terms of an AFA, multiplied by the operating rights owner's percentage of interest ownership in the lease or the acreage.

Facility measurement point (or point of royalty settlement) means the point where the BLM-approved measurement device is located for determining the volume of gas removed from the lease. The facility measurement point may be on the lease or off-lease with BLM approval.

Field means a geographic region situated over one or more subsurface oil and gas reservoirs encompassing at least the outermost boundaries of all oil and gas accumulations known to be within those reservoirs vertically projected to the land surface. Onshore fields are usually given names and their official boundaries are often designated by oil and gas regulatory agencies in the respective States in which the fields are located.

Gas means any fluid, either combustible or noncombustible, hydrocarbon or nonhydrocarbon, which is extracted from a reservoir and which has neither independent shape nor volume, but tends to expand indefinitely. It is a substance that exists in a gaseous or rarefied state under standard temperature and pressure conditions.

Gas plant products means separate marketable elements, compounds, or mixtures, whether in liquid, gaseous, or solid form, resulting from processing gas. However, it does not include residue gas.

Gathering means the movement of lease production to a central accumulation or treatment point on the lease, unit, or communitized area; or a central accumulation or treatment point off the lease, unit, or communitized area as approved by BLM operations personnel.

Gross proceeds (for royalty payment purposes) means the total monies and other consideration accruing to an oil and gas lessee for the disposition of unprocessed gas, residue gas, and gas plant products produced. Gross proceeds includes, but is not limited to, payments to the lessee for certain services such as compression, dehydration, measurement, or field gathering to the extent that the lessee is obligated to perform them at no cost to the Indian lessor, and payments for gas processing rights. Gross proceeds, as applied to gas, also includes but is not limited to reimbursements for severance taxes and other reimbursements. Tax reimbursements are part of the gross proceeds accruing to a lessee even though the Indian royalty interest is exempt from taxation. Monies and other consideration, including the forms of consideration identified in this paragraph, to which a lessee is contractually or legally entitled but which it does not seek to collect through reasonable efforts are also part of gross proceeds.

Index means the calculated composite price ($/MMBtu) of spot-market sales published by a publication that meets ONRR-established criteria for acceptability at the index-pricing point.

Index-pricing point (IPP) means any point on a pipeline for which there is an index.

Index zone means a field or an area with an active spot market and published indices applicable to that field or area that are acceptable to ONRR under § 1206.172(d)(2).

Indian allottee means any Indian for whom land or an interest in land is held in trust by the United States or who holds title subject to Federal restriction against alienation.

Indian tribe means any Indian tribe, band, nation, pueblo, community, rancheria, colony, or other group of Indians for which any land or interest in land is held in trust by the United States or which is subject to Federal restriction against alienation.

Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States under a mineral leasing law that authorizes exploration for, development or extraction of, or removal of lease products—or the land area covered by that authorization, whichever is required by the context. For purposes of this subpart, this definition excludes Federal leases.

Lease products means any leased minerals attributable to, originating from, or allocated to a lease.

Lessee means any person to whom the United States, a tribe, and/or individual Indian landowner issues a lease, and any person who has been assigned an obligation to make royalty or other payments required by the lease. This includes any person who has an interest in a lease (including operating rights owners) as well as an operator or payor who has no interest in the lease but who has assumed the royalty payment responsibility.

Like-quality lease products means lease products which have similar chemical, physical, and legal characteristics.

Marketable condition means a condition in which lease products are sufficiently free from impurities and otherwise so conditioned that a purchaser will accept them under a sales contract typical for the field or area.

Minimum royalty means that minimum amount of annual royalty that the lessee must pay as specified in the lease or in applicable leasing regulations.

Natural gas liquids (NGL's) means those gas plant products consisting of ethane, propane, butane, or heavier liquid hydrocarbons.

Net-back method (or work-back method) means a method for calculating market value of gas at the lease under which costs of transportation, processing, and manufacturing are deducted from the proceeds received for, or the value of, the gas, residue gas, or gas plant products, and any extracted, processed, or manufactured products, at the first point at which reasonable values for any such products may be determined by a sale under an arm's-length contract or comparison to other sales of such products.

Net output means the quantity of residue gas and each gas plant product that a processing plant produces.

Net profit share means the specified share of the net profit from production of oil and gas as provided in the agreement.

ONRR means the Office of Natural Resources Revenue, Department of the Interior. ONRR includes, where appropriate, tribal auditors acting under agreements under the Federal Oil and Gas Royalty Management Act of 1982, 30 U.S.C. 1701 et seq. or other applicable agreements.

Operating rights owner (or working interest owner) means any person who owns operating rights in a lease subject to this subpart. A record title owner is the owner of operating rights under a lease except to the extent that the operating rights or a portion thereof have been transferred from record title (see BLM regulations at 43 CFR 3100.0-5(d)).

Person means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity).

Point of royalty measurement means the same as facility measurement point.

Processing means any process designed to remove elements or compounds (hydrocarbon and nonhydrocarbon) from gas, including absorption, adsorption, or refrigeration. Field processes which normally take place on or near the lease, such as natural pressure reduction, mechanical separation, heating, cooling, dehydration, desulphurization (or “sweetening”), and compression, are not considered processing. The changing of pressures and/or temperatures in a reservoir is not considered processing.

Residue gas means that hydrocarbon gas consisting principally of methane resulting from processing gas.

Sales type code means the contract type or general disposition (e.g., arm's-length or non-arm's-length) of production from the lease. The sales type code applies to the sales contract, or other disposition, and not to the arm's-length or non-arm's-length nature of a transportation or processing allowance.

Spot sales agreement means a contract wherein a seller agrees to sell to a buyer a specified amount of unprocessed gas, residue gas, or gas plant products at a specified price over a fixed period, usually of short duration. It also does not normally require a cancellation notice to terminate, and does not contain an obligation, or imply an intent, to continue in subsequent periods.

Takes means when the operating rights owner sells or removes production from, or allocated to, the lease, or when such sale or removal occurs for the benefit of an operating rights owner.

Work-back method means the same as net-back method.

[64 FR 43515, Aug. 10, 1999, as amended at 73 FR 15891, Mar. 26, 2008]

§ 1206.172 How do I value gas produced from leases in an index zone?

(a) What leases this section applies to. This section explains how lessees must value, for royalty purposes, gas produced from Indian leases located in an index zone. For other leases, value must be determined under § 1206.174.

(1) You must use the valuation provision of this section if your lease is in an index zone and meets one of the following two requirements:

(i) Has a major portion provision;

(ii) Does not have a major portion provision, but provides for the Secretary to determine the value of production.

(2) This section does not apply to carbon dioxide, nitrogen, or other non-hydrocarbon components of the gas stream. However, if they are recovered and sold separately from the gas stream, you must determine the value of these products under § 1206.174.

(b) Valuing residue gas and gas before processing. (1) Except as provided in paragraphs (e), (f), and (g) of this section, this paragraph (b) explains how you must value the following four types of gas:

(i) Gas production before processing;

(ii) Gas production that you certify on Form ONRR-4410, Certification for Not Performing Accounting for Comparison (Dual Accounting), is not processed before it flows into a pipeline with an index but which may be processed later;

(iii) Residue gas after processing; and

(iv) Gas that is never processed.

(2) The value of gas production that is not sold under an arm's-length dedicated contract is the index-based value determined under paragraph (d) of this section unless the gas was subject to a previous contract which was part of a gas contract settlement. If the previous contract was subject to a gas contract settlement and if the royalty-bearing contract settlement proceeds per MMBtu added to the 80 percent of the safety net prices calculated at § 1206.172(e)(4)(i) exceeds the index-based value that applies to the gas under this section (including any adjustments required under § 1206.176), then the value of the gas is the higher of the value determined under this section (including any adjustments required under § 1206.176) or § 1206.174.

(3) The value of gas production that is sold under an arm's-length dedicated contract is the higher of the index-based value under paragraph (d) of this section or the value of that production determined under § 1206.174(b).

(c) Valuing gas that is processed before it flows into a pipeline with an index. Except as provided in paragraphs (e), (f), and (g) of this section, this paragraph (c) explains how you must value gas that is processed before it flows into a pipeline with an index. You must value this gas production based on the higher of the following two values:

(1) The value of the gas before processing determined under paragraph (b) of this section.

(2) The value of the gas after processing, which is either the alternative dual accounting value under § 1206.173 or the sum of the following three values:

(i) The value of the residue gas determined under paragraph (b)(2) or (3) of this section, as applicable;

(ii) The value of the gas plant products determined under § 1206.174, less any applicable processing and/or transportation allowances determined under this subpart; and

(iii) The value of any drip condensate associated with the processed gas determined under subpart B of this part.

(d) Determining the index-based value for gas production. (1) To determine the index-based value per MMBtu for production from a lease in an index zone, you must use the following procedures:

(i) For each ONRR-approved publication, calculate the average of the highest reported prices for all index-pricing points in the index zone, except for any prices excluded under paragraph (d)(6) of this section;

(ii) Sum the averages calculated in paragraph (d)(1)(i) of this section and divide by the number of publications; and

(iii) Reduce the number calculated under paragraph (d)(1)(ii) of this section by 10 percent, but not by less than 10 cents per MMBtu or more than 30 cents per MMBtu. The result is the index-based value per MMBtu for production from all leases in that index zone.

(2) ONRR will publish in the Federal Register the index zones that are eligible for the index-based valuation method under this paragraph. ONRR will monitor the market activity in the index zones and, if necessary, hold a technical conference to add or modify a particular index zone. Any change to the index zones will be published in the Federal Register. ONRR will consider the following five factors and conditions in determining eligible index zones:

(i) Areas for which ONRR-approved publications establish index prices that accurately reflect the value of production in the field or area where the production occurs;

(ii) Common markets served;

(iii) Common pipeline systems;

(iv) Simplification; and

(v) Easy identification in ONRR's systems, such as counties or Indian reservations.

(3) If market conditions change so that an index-based method for determining value is no longer appropriate for an index zone, ONRR will hold a technical conference to consider disqualification of an index zone. ONRR will publish notice in the Federal Register if an index zone is disqualified. If an index zone is disqualified, then production from leases in that index zone cannot be valued under this paragraph.

(4) ONRR periodically will publish in the Federal Register a list of acceptable publications based on certain criteria, including, but not limited to the following five criteria:

(i) Publications buyers and sellers frequently use;

(ii) Publications frequently referenced in purchase or sales contracts;

(iii) Publications that use adequate survey techniques, including the gathering of information from a substantial number of sales;

(iv) Publications that publish the range of reported prices they use to calculate their index; and

(v) Publications independent from DOI, lessors, and lessees.

(5) Any publication may petition ONRR to be added to the list of acceptable publications.

(6) ONRR may exclude an individual index price for an index zone in an ONRR-approved publication if ONRR determines that the index price does not accurately reflect the value of production in that index zone. ONRR will publish a list of excluded indices in the Federal Register.

(7) ONRR will reference which tables in the publications you must use for determining the associated index prices.

(8) The index-based values determined under this paragraph are not subject to deductions for transportation or processing allowances determined under §§ 1206.177, 1206.178, 1206.179, and 1206.180.

(e) Determining the minimum value for royalty purposes of gas sold beyond the first index pricing point. (1) Notwithstanding any other provision of this section, the value for royalty purposes of gas production from an Indian lease that is sold beyond the first index pricing point through which it flows cannot be less than the value determined under this paragraph (e).

(2) By June 30 following any calendar year, you must calculate for each month of that calendar year your safety net price per MMBtu using the procedures in paragraph (e)(3) of this section. You must calculate a safety net price for each month and for each index zone where you have an Indian lease for which you report and pay royalties.

(3) Your safety net price (S) for an index zone is the volume-weighted average contract price per delivered MMBtu under your or your affiliate's arm's-length contracts for the disposition of residue gas or unprocessed gas produced from your Indian leases in that index zone as computed under this paragraph (e)(3).

(i) Include in your calculation only sales under those contracts that establish a delivery point beyond the first index pricing point through which the gas flows, and that include any gas produced from or allocable to one or more of your Indian leases in that index zone, even if the contract also includes gas produced from Federal, State, or fee properties. Include in your volume-weighted average calculation those volumes that are allocable to your Indian leases in that index zone.

(ii) Do not reduce the contract price for any transportation costs incurred to deliver the gas to the purchaser.

(iii) For purposes of this paragraph (e), the contract price will not include the following amounts:

(A) Any amounts you receive in compromise or settlement of a predecessor contract for that gas;

(B) Deductions for you or any other person to put gas production into marketable condition or to market the gas; and

(C) Any amounts related to marketable securities associated with the sales contract.

(4) Next, you must determine for each month the safety net differential (SND). You must perform this calculation separately for each index zone.

(i) For each index zone, the safety net differential is equal to: SND = [(0.80 × S) − (1.25 × I)] where (I) is the index-based value determined under 30 CFR 206.172(d).

(ii) If the safety net differential is positive you owe additional royalties.

(5)(i) To calculate the additional royalties you owe, make the following calculation for each of your Indian leases in that index zone that produced gas that was sold beyond the first index-pricing point through which the gas flowed and that was used in the calculation in paragraph (e)(3) of this section:

Lease royalties owed = SND × V × R, where R = the lease royalty rate and V = the volume allocable to the lease which produced gas that was sold beyond the first index pricing point.

(ii) If gas produced from any of your Indian leases is commingled or pooled with gas produced from non-Indian properties, and if any of the combined gas is sold at a delivery point beyond the first index pricing point through which the gas flows, then the volume allocable to each Indian lease for which gas was sold beyond the first index pricing point in the calculation under paragraph (e)(5)(i) of this section is the volume produced from the lease multiplied by the proportion that the total volume of gas sold beyond the first index pricing point bears to the total volume of gas commingled or pooled from all properties.

(iii) Add the numbers calculated for each lease under paragraph (e)(5)(i) of this section. The total is the additional royalty you owe.

(6) You have the following responsibilities to comply with the minimum value for royalty purposes:

(i) You must report the safety net price for each index zone to ONRR on Form ONRR-4411, Safety Net Report, no later than June 30 following each calendar year;

(ii) You must pay and report on Form ONRR-2014 additional royalties due no later than June 30 following each calendar year; and

(iii) ONRR may order you to amend your safety net price within one year from the date your Form ONRR-4411 is due or is filed, whichever is later. If ONRR does not order any amendments within that one-year period, your safety net price calculation is final.

(f) Excluding some or all tribal leases from valuation under this section. (1) An Indian tribe may ask ONRR to exclude some or all of its leases from valuation under this section. ONRR will consult with BIA regarding the request.

(i) If ONRR approves the request for your lease, you must value your production under § 1206.174 beginning with production on the first day of the second month following the date ONRR publishes notice of its decision in the Federal Register.

(ii) If an Indian tribe requests exclusion from an index zone for less than all of its leases, ONRR will approve the request only if the excluded leases may be segregated into one or more groups based on separate fields within the reservation.

(2) An Indian tribe may ask ONRR to terminate exclusion of its leases from valuation under this section. ONRR will consult with BIA regarding the request.

(i) If ONRR approves the request, you must value your production under § 1206.172 beginning with production on the first day of the second month following the date ONRR publishes notice of its decision in the Federal Register.

(ii) Termination of an exclusion under paragraph (f)(2)(i) of this section cannot take effect earlier than 1 year after the first day of the production month that the exclusion was effective.

(3) The Indian tribe's request to ONRR under either paragraph (f)(1) or (2) of this section must be in the form of a tribal resolution.

(g) Excluding Indian allotted leases from valuation under this section. (1)(i) ONRR may exclude any Indian allotted leases from valuation under this section. ONRR will consult with BIA regarding the exclusion.

(ii) If ONRR excludes your lease, you must value your production under § 1206.174 beginning with production on the first day of the second month following the date ONRR publishes notice of its decision in the Federal Register.

(iii) If ONRR excludes any Indian allotted leases under this paragraph (g)(1), it will exclude all Indian allotted leases in the same field.

(2)(i) ONRR may terminate the exclusion of any Indian allotted leases from valuation under this section. ONRR will consult with BIA regarding the termination.

(ii) If ONRR terminates the exclusion, you must value your production under § 1206.172 beginning with production on the first day of the second month following the date ONRR publishes notice of its decision in the Federal Register.

§ 1206.173 How do I calculate the alternative methodology for dual accounting?

(a) Electing a dual accounting method. (1) If you are required to perform the accounting for comparison (dual accounting) under § 1206.176, you have two choices. You may elect to perform the dual accounting calculation according to either § 1206.176(a) (called actual dual accounting), or paragraph (b) of this section (called the alternative methodology for dual accounting).

(2) You must make a separate election to use the alternative methodology for dual accounting for your Indian leases in each ONRR-designated area. Your election for a designated area must apply to all of your Indian leases in that area.

(i) ONRR will publish in the Federal Register a list of the lease prefixes that will be associated with each designated area for purposes of this section. The ONRR-designated areas are as follows:

(A) Alabama-Coushatta;

(B) Blackfeet Reservation;

(C) Crow Reservation;

(D) Fort Belknap Reservation;

(E) Fort Berthold Reservation;

(F) Fort Peck Reservation;

(G) Jicarilla Apache Reservation;

(H) ONRR-designated groups of counties in the State of Oklahoma;

(I) Navajo Reservation;

(J) Northern Cheyenne Reservation;

(K) Rocky Boys Reservation;

(L) Southern Ute Reservation;

(M) Turtle Mountain Reservation;

(N) Ute Mountain Ute Reservation;

(O) Uintah and Ouray Reservation;

(P) Wind River Reservation; and

(Q) Any other area that ONRR designates. ONRR will publish a new area designation in the Federal Register.

(ii) You may elect to begin using the alternative methodology for dual accounting at the beginning of any month. The first election to use the alternative methodology will be effective from the time of election through the end of the following calendar year. Thereafter, each election to use the alternative methodology must remain in effect for 2 calendar years. You may return to the actual dual accounting method only at the beginning of the next election period or with the written approval of ONRR and the tribal lessor for tribal leases, and ONRR for Indian allottee leases in the designated area.

(iii) When you elect to use the alternative methodology for a designated area, you must also use the alternative methodology for any new wells commenced and any new leases acquired in the designated area during the term of the election.

(b) Calculating value using the alternative methodology for dual accounting. (1) The alternative methodology adjusts the value of gas before processing determined under either § 1206.172 or § 1206.174 to provide the value of the gas after processing. You must use the value of the gas after processing for royalty payment purposes. The amount of the increase depends on your relationship with the owner(s) of the plant where the gas is processed. If you have no direct or indirect ownership interest in the processing plant, then the increase is lower, as provided in the table in paragraph (b)(2)(ii) of this section. If you have a direct or indirect ownership interest in the plant where the gas is processed, the increase is higher, as provided in paragraph (b)(2)(ii) of this section.

(2) To calculate the value of the gas after processing using the alternative methodology for dual accounting, you must apply the increase to the value before processing, determined in either § 1206.172 or § 1206.174, as follows:

(i) Value of gas after processing = (value determined under either § 1206.172 or § 1206.174, as applicable) × (1 + increment for dual accounting); and

(ii) In this equation, the increment for dual accounting is the number you take from the applicable Btu range, determined under paragraph (b)(3) of this section, in the following table:

BTU range | Increment if Lessee has no ownership interest in plant | Increment if lessee has an ownership interest in plant

1001 to 1050 | .0275 | .0375

1051 to 1100 | .0400 | .0625

1101 to 1150 | .0425 | .0750

1151 to 1200 | .0700 | .1225

1201 to 1250 | .0975 | .1700

1251 to 1300 | .1175 | .2050

1301 to 1350 | .1400 | .2400

1351 to 1400 | .1450 | .2500

1401 to 1450 | .1500 | .2600

1451 to 1500 | .1550 | .2700

1501 to 1550 | .1600 | .2800

1551 to 1600 | .1650 | .2900

1601 to 1650 | .1850 | .3225

1651 to 1700 | .1950 | .3425

1701 + | .2000 | .3550

(3) The applicable Btu for purposes of this section is the volume weighted-average Btu for the lease computed from measurements at the facility measurement point(s) for gas production from the lease.

(4) If any of your gas from the lease is processed during a month, use the following two paragraphs to determine which amounts are subject to dual accounting and which dual accounting method you must use.

(i) Weighted-average Btu content determined under paragraph (b)(3) of this section is greater than 1,000 Btu's per cubic foot (Btu/cf). All gas production from the lease is subject to dual accounting and you must use the alternative method for all that gas production if you elected to use the alternative method under this section.

(ii) Weighted-average Btu content determined under paragraph (b)(3) of this section is less than or equal to 1,000 Btu/cf. Only the volumes of lease production measured at facility measurement points whose quality exceeds 1,000 Btu/cf are subject to dual accounting, and you may use the alternative methodology for these volumes. For gas measured at facility measurement points for these leases where the quality is equal to or less than 1,000 Btu/cf, you are not required to do dual accounting.

§ 1206.174 How do I value gas production when an index-based method cannot be used?

(a) Situations in which an index-based method cannot be used. (1) Gas production must be valued under this section in the following situations.

(i) Your lease is not in an index zone (or ONRR has excluded your lease from an index zone).

(ii) If your lease is in an index zone and you sell your gas under an arm's-length dedicated contract, then the value of your gas is the higher of the value received under the dedicated contract determined under § 1206.174(b) or the value under § 1206.172.

(iii) Also use this section to value any other gas production that cannot be valued under § 1206.172, as well as gas plant products, and to value components of the gas stream that have no Btu value (for example, carbon dioxide, nitrogen, etc.).

(2) The value for royalty purposes of gas production subject to this subpart is the value of gas determined under this section less applicable allowances determined under this subpart.

(3) You must determine the value of gas production that is processed and is subject to accounting for comparison using the procedure in § 1206.176.

(4) This paragraph applies if your lease has a major portion provision. It also applies if your lease does not have a major portion provision but the lease provides for the Secretary to determine value.

(i) The value of production you must initially report and pay is the value determined in accordance with the other paragraphs of this section.

(ii) ONRR will determine the major portion value and notify you in the Federal Register of that value. The value of production for royalty purposes for your lease is the higher of either the value determined under this section which you initially used to report and pay royalties, or the major portion value calculated under this paragraph (a)(4). If the major portion value is higher, you must submit an amended Form ONRR-2014 to ONRR by the due date specified in the written notice from ONRR of the major portion value. Late-payment interest under § 1218.54 of this chapter on any underpayment will not begin to accrue until the date the amended Form ONRR-2014 is due to ONRR.

(iii) Except as provided in paragraph (a)(4)(iv) of this section, ONRR will calculate the major portion value for each designated area (which are the same designated areas as under § 1206.173) using values reported for unprocessed gas and residue gas on Form ONRR-2014 for gas produced from leases on that Indian reservation or other designated area. ONRR will array the reported prices from highest to lowest price. The major portion value is that price at which 25 percent (by volume) of the gas (starting from the highest) is sold. ONRR cannot unilaterally change the major portion value after you are notified in writing of what that value is for your leases.

(iv) ONRR may calculate the major portion value using different data than the data described in paragraph (a)(4)(iii) of this section or data to augment the data described in paragraph (a)(4)(iii) of this section. This may include price data reported to the State tax authority or price data from leases ONRR has reviewed in the designated area. ONRR may use this alternate or the augmented data source beginning with production on the first day of the month following the date ONRR publishes notice in the Federal Register that it is calculating the major portion using a method in this paragraph (a)(4)(iv) of this section.

(b) Arm's-length contracts. (1) The value of gas, residue gas, or any gas plant product you sell under an arm's-length contract is the gross proceeds accruing to you or your affiliate, except as provided in paragraphs (b)(1)(ii)-(iv) of this section.

(i) You have the burden of demonstrating that your contract is arm's-length.

(ii) In conducting reviews and audits for gas valued based upon gross proceeds under this paragraph, ONRR will examine whether or not your contract reflects the total consideration actually transferred either directly or indirectly from the buyer to you or your affiliate for the gas, residue gas, or gas plant product. If the contract does not reflect the total consideration, then ONRR may require that the gas, residue gas, or gas plant product sold under that contract be valued in accordance with paragraph (c) of this section. Value may not be less than the gross proceeds accruing to you or your affiliate, including the additional consideration.

(iii) If ONRR determines for gas valued under this paragraph that the gross proceeds accruing to you or your affiliate under an arm's-length contract do not reflect the value of the gas, residue gas, or gas plant products because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of you and the lessor, then ONRR will require that the gas, residue gas, or gas plant product be valued under paragraphs (c)(2) or (3) of this section. In these circumstances, ONRR will notify you and give you an opportunity to provide written information justifying your value.

(iv) This paragraph applies to situations where a pipeline purchases gas from a lessee according to a cash-out program under a transportation contract. For all over-delivered volumes, the royalty value is the price the pipeline is required to pay for volumes within the tolerances for over-delivery specified in the transportation contract. Use the same value for volumes that exceed the over-delivery tolerances even if those volumes are subject to a lower price specified in the transportation contract. However, if ONRR determines that the price specified in the transportation contract for over-delivered volumes is unreasonably low, the lessees must value all over-delivered volumes under paragraph (c)(2) or (3) of this section.

(2) ONRR may require you to certify that your arm's-length contract provisions include all of the consideration the buyer pays, either directly or indirectly, for the gas, residue gas, or gas plant product.

(c) Non-arm's-length contracts. If your gas, residue gas, or any gas plant product is not sold under an arm's-length contract, then you must value the production using the first applicable method of the following three methods:

(1) The gross proceeds accruing to you under your non-arm's-length contract sale (or other disposition other than by an arm's-length contract), provided that those gross proceeds are equivalent to the gross proceeds derived from, or paid under, comparable arm's-length contracts for purchases, sales, or other dispositions of like-quality gas in the same field (or, if necessary to obtain a reasonable sample, from the same area). For residue gas or gas plant products, the comparable arm's-length contracts must be for gas from the same processing plant (or, if necessary to obtain a reasonable sample, from nearby plants). In evaluating the comparability of arm's-length contracts for the purposes of these regulations, the following factors will be considered: price, time of execution, duration, market or markets served, terms, quality of gas, residue gas, or gas plant products, volume, and such other factors as may be appropriate to reflect the value of the gas, residue gas, or gas plant products.

(2) A value determined by consideration of other information relevant in valuing like-quality gas, residue gas, or gas plant products, including gross proceeds under arm's-length contracts for like-quality gas in the same field or nearby fields or areas, or for residue gas or gas plant products from the same gas plant or other nearby processing plants. Other factors to consider include prices received in spot sales of gas, residue gas or gas plant products, other reliable public sources of price or market information, and other information as to the particular lease operation or the salability of such gas, residue gas, or gas plant products.

(3) A net-back method or any other reasonable method to determine value.

(d) Supporting data. If you determine the value of production under paragraph (c) of this section, you must retain all data relevant to the determination of royalty value.

(1) Such data will be subject to review and audit, and ONRR will direct you to use a different value if we determine upon review or audit that the value you reported is inconsistent with the requirements of these regulations.

(2) You must make all such data available upon request to the authorized ONRR or Indian representatives, to the Office of the Inspector General of the Department, or other authorized persons. This includes your arm's-length sales and volume data for like-quality gas, residue gas, and gas plant products that are sold, purchased, or otherwise obtained from the same processing plant or from nearby processing plants, or from the same or nearby field or area.

(e) Improper values. If ONRR determines that you have not properly determined value, you must pay the difference, if any, between royalty payments made based upon the value you used and the royalty payments that are due based upon the value ONRR established. You also must pay interest computed on that difference under § 1218.54 of this chapter. If you are entitled to a credit, ONRR will provide instructions on how to take that credit.

(f) Value guidance. You may ask ONRR for guidance in determining value. You may propose a valuation method to ONRR. Submit all available data related to your proposal and any additional information ONRR deems necessary. ONRR will promptly review your proposal and provide you with a non-binding determination of the guidance you request.

(g) Minimum value of production. (1) For gas, residue gas, and gas plant products valued under this section, under no circumstances may the value of production for royalty purposes be less than the gross proceeds accruing to the lessee (including its affiliates) for gas, residue gas and/or any gas plant products, less applicable transportation allowances and processing allowances determined under this subpart.

(2) For gas plant products valued under this section and not valued under § 1206.173, the alternative methodology for dual accounting, the minimum value of production for each gas plant product is as follows:

(i) Leases in certain States and areas have specific minimum values.

(A) For production from leases in Colorado in the San Juan Basin, New Mexico, and Texas, the monthly average minimum price reported in commercial price bulletins for the gas plant product at Mont Belvieu, Texas, minus 8.0 cents per gallon.

(B) For production in Arizona, in Colorado outside the San Juan Basin, Minnesota, Montana, North Dakota, Oklahoma, South Dakota, Utah, and Wyoming, the monthly average minimum price reported in commercial price bulletins for the gas plant product at Conway, Kansas, minus 7.0 cents per gallon;

(ii) You may use any commercial price bulletin, but you must use the same bulletin for all of the calendar year. If the commercial price bulletin you are using stops publication, you may use a different commercial price bulletin for the remaining part of the calendar year; and (iii) If you use a commercial price bulletin that is published monthly, the monthly average minimum price is the bulletin's minimum price. If you use a commercial price bulletin that is published weekly, the monthly average minimum price is the arithmetic average of the bulletin's weekly minimum prices. If you use a commercial price bulletin that is published daily, the monthly average minimum price is the arithmetic average of the bulletin's minimum prices for each Wednesday in the month.

(h) Marketable condition/Marketing. You are required to place gas, residue gas, and gas plant products in marketable condition and market the gas for the mutual benefit of the lessee and the lessor at no cost to the Indian lessor. When your gross proceeds establish the value under this section, that value must be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services to place the gas, residue gas, or gas plant products in marketable condition or to market the gas, the cost of which ordinarily is your responsibility.

(i) Highest obtainable price or benefit. For gas, residue gas, and gas plant products valued under this section, value must be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if you fail to take proper or timely action to receive prices or benefits to which you are entitled, you must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments must be in writing and signed by all parties to an arm's-length contract. If you make timely application for a price increase or benefit allowed under your contract but the purchaser refuses, and you take reasonable measures, which are documented, to force purchaser compliance, you will owe no additional royalties unless or until monies or consideration resulting from the price increase or additional benefits are received. This paragraph is not intended to permit you to avoid your royalty payment obligation in situations where your purchaser fails to pay, in whole or in part, or timely, for a quantity of gas, residue gas, or gas plant product.

(j) Non-binding ONRR reviews. Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in an ONRR redetermination of value under this section will be considered final or binding against the Federal Government or its beneficiaries until the audit period is formally closed.

(k) Confidential information. Certain information submitted to ONRR to support valuation proposals, including transportation allowances and processing allowances, may be exempted from disclosure under the Freedom of Information Act, 5 U.S.C. 552, or other Federal law. Any data specified by law to be privileged, confidential, or otherwise exempt, will be maintained in a confidential manner in accordance with applicable laws and regulations. All requests for information about determinations made under this subpart must be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2.

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

§ 1206.175 How do I determine quantities and qualities of production for computing royalties?

(a) For unprocessed gas, you must pay royalties on the quantity and quality at the facility measurement point BLM either allowed or approved.

(b) For residue gas and gas plant products, you must pay royalties on your share of the monthly net output of the plant even though residue gas and/or gas plant products may be in temporary storage.

(c) If you have no ownership interest in the processing plant and you do not operate the plant, you may use the contract volume allocation to determine your share of plant products.

(d) If you have an ownership interest in the plant or if you operate it, use the following procedure to determine the quantity of the residue gas and gas plant products attributable to you for royalty payment purposes:

(1) When the net output of the processing plant is derived from gas obtained from only one lease, the quantity of the residue gas and gas plant products on which you must pay royalty is the net output of the plant.

(2) When the net output of a processing plant is derived from gas obtained from more than one lease producing gas of uniform content, the quantity of the residue gas and gas plant products allocable to each lease must be in the same proportions as the ratios obtained by dividing the amount of gas delivered to the plant from each lease by the total amount of gas delivered from all leases.

(3) When the net output of a processing plant is derived from gas obtained from more than one lease producing gas of non-uniform content, the volumes of residue gas and gas plant products allocable to each lease are based on theoretical volumes of residue gas and gas plant products measured in the lease gas stream. You must calculate the portion of net plant output of residue gas and gas plant products attributable to each lease as follows:

(i) First, compute the theoretical volumes of residue gas and of gas plant products attributable to the lease by multiplying the lease volume of the gas stream by the tested residue gas content (mole percentage) or gas plant product (GPM) content of the gas stream;

(ii) Second, calculate the theoretical volumes of residue gas and of gas plant products delivered from all leases by summing the theoretical volumes of residue gas and of gas plant products delivered from each lease; and

(iii) Third, calculate the theoretical quantities of net plant output of residue gas and of gas plant products attributable to each lease by multiplying the net plant output of residue gas, or gas plant products, by the ratio in which the theoretical volumes of residue gas, or gas plant products, is the numerator and the theoretical volume of residue gas, or gas plant products, delivered from all leases is the denominator.

(4) You may request ONRR approval of other methods for determining the quantity of residue gas and gas plant products allocable to each lease. If ONRR approves a different method, it will be applicable to all gas production from your Indian leases that is processed in the same plant.

(e) You may not take any deductions from the royalty volume or royalty value for actual or theoretical losses. Any actual loss of unprocessed gas incurred prior to the facility measurement point will not be subject to royalty if BLM determines that the loss was unavoidable.

§ 1206.176 How do I perform accounting for comparison?

(a) This section applies if the gas produced from your Indian lease is processed and that Indian lease requires accounting for comparison (also referred to as actual dual accounting). Except as provided in paragraphs (b) and (c) of this section, the actual dual accounting value, for royalty purposes, is the greater of the following two values:

(1) The combined value of the following products:

(i) The residue gas and gas plant products resulting from processing the gas determined under either § 1206.172 or § 1206.174, less any applicable allowances; and

(ii) Any drip condensate associated with the processed gas recovered downstream of the point of royalty settlement without resorting to processing determined under § 1206.52, less applicable allowances.

(2) The value of the gas prior to processing determined under either § 1206.172 or § 1206.174, including any applicable allowances.

(b) If you are required to account for comparison, you may elect to use the alternative dual accounting methodology provided for in § 1206.173 instead of the provisions in paragraph (a) of this section.

(c) Accounting for comparison is not required for gas if no gas from the lease is processed until after the gas flows into a pipeline with an index located in an index zone or into a mainline pipeline not in an index zone. If you do not perform dual accounting, you must certify to ONRR that gas flows into such a pipeline before it is processed.

(d) Except as provided in paragraph (e) of this section, if you value any gas production from a lease for a month using the dual accounting provisions of this section or the alternative dual accounting methodology of § 1206.173, then the value of that gas is the minimum value for any other gas production from that lease for that month flowing through the same facility measurement point.

(e) If the weighted-average Btu quality for your lease is less than 1,000 Btu's per cubic foot, see § 1206.173(b)(4)(ii) to determine if you must perform a dual accounting calculation.

§ 1206.177 What general requirements regarding transportation allowances apply to me?

(a) When you value gas under § 1206.174 at a point off the lease, unit, or communitized area (for example, sales point or point of value determination), you may deduct from value a transportation allowance to reflect the value, for royalty purposes, at the lease, unit, or communitized area. The allowance is based on the reasonable actual costs you incurred to transport unprocessed gas, residue gas, or gas plant products from a lease to a point off the lease, unit, or communitized area. This would include, if appropriate, transportation from the lease to a gas processing plant off the lease, unit, or communitized area and from the plant to a point away from the plant. You may not deduct any allowance for gathering costs.

(b) You must allocate transportation costs among all products you produce and transport as provided in § 1206.178.

(c)(1) Except as provided in paragraphs (c)(2) and (3) of this section, your transportation allowance deduction for each sales type code may not exceed 50 percent of the value of the unprocessed gas, residue gas, or gas plant product. For purposes of this section, natural gas liquids are considered one product.

(2) If you ask ONRR, ONRR may approve a transportation allowance deduction in excess of the limitations in paragraph (c)(1) of this section. To receive this approval, you must demonstrate that the transportation costs incurred in excess of the limitations in paragraph (c)(1) of this section were reasonable, actual, and necessary. Under no circumstances may an allowance reduce the value for royalty purposes under any sales type code to zero.

(3) Your application for exception (using Form ONRR-4393, Request to Exceed Regulatory Allowance Limitation) must contain all relevant and supporting documentation necessary for ONRR to make a determination.

(d) If ONRR conducts a review or audit and determines that you have improperly determined a transportation allowance authorized by this subpart, then you will be required to pay any additional royalties, plus interest determined in accordance with § 1218.54 of this chapter. Alternatively, you may be entitled to a credit, but you will not receive any interest on your overpayment.

[64 FR 43515, Aug. 10, 1999, as amended at 73 FR 15891, Mar. 26, 2008]

§ 1206.178 How do I determine a transportation allowance?

(a) Determining a transportation allowance under an arm's-length contract. (1) This paragraph explains how to determine your allowance if you have an arm's-length transportation contract.

(i) If you have an arm's-length contract for transportation of your production, the transportation allowance is the reasonable, actual costs you incur for transporting the unprocessed gas, residue gas and/or gas plant products under that contract. Paragraphs (a)(1)(ii) and (iii) of this section provide a limited exception. You have the burden of demonstrating that your contract is arm's-length. Your allowances also are subject to paragraph (e) of this section. You are required to submit to ONRR a copy of your arm's-length transportation contract(s) and all subsequent amendments to the contract(s) within 2 months of the date ONRR receives your report which claims the allowance on the Form ONRR-2014.

(ii) When either ONRR or a tribe conducts reviews and audits, they will examine whether or not the contract reflects more than the consideration actually transferred either directly or indirectly from you to the transporter of the transportation. If the contract reflects more than the total consideration, then ONRR may require that the transportation allowance be determined under paragraph (b) of this section.

(iii) If ONRR determines that the consideration paid under an arm's-length transportation contract does not reflect the value of the transportation because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of you and the lessor, then ONRR will require that the transportation allowance be determined under paragraph (b) of this section. In these circumstances, ONRR will notify you and give you an opportunity to provide written information justifying your transportation costs.

(2) This paragraph explains how to allocate the costs to each product if your arm's-length transportation contract includes more than one product in a gaseous phase and the transportation costs attributable to each product cannot be determined from the contract.

(i) If your arm's-length transportation contract includes more than one product in a gaseous phase and the transportation costs attributable to each product cannot be determined from the contract, the total transportation costs must be allocated in a consistent and equitable manner to each of the products transported. To make this allocation, use the same proportion as the ratio that the volume of each product (excluding waste products which have no value) bears to the volume of all products in the gaseous phase (excluding waste products which have no value). Except as provided in this paragraph, you cannot take an allowance for the costs of transporting lease production that is not royalty bearing without ONRR approval, or without lessor approval on tribal leases.

(ii) As an alternative to paragraph (a)(2)(i) of this section, you may propose to ONRR a cost allocation method based on the values of the products transported. ONRR will approve the method if we determine that it meets one of the two following requirements:

(A) The methodology in paragraph (a)(2)(i) of this section cannot be applied; and

(B) Your proposal is more reasonable than the methodology in paragraph (a)(2)(i) of this section.

(3) This paragraph explains how to allocate costs to each product if your arm's-length transportation contract includes both gaseous and liquid products and the transportation costs attributable to each cannot be determined from the contract.

(i) If your arm's-length transportation contract includes both gaseous and liquid products and the transportation costs attributable to each cannot be determined from the contract, you must propose an allocation procedure to ONRR. You may use the transportation allowance determined in accordance with your proposed allocation procedure until ONRR decides whether to accept your cost allocation.

(ii) You are required to submit all relevant data to support your allocation proposal. ONRR will then determine the gas transportation allowance based upon your proposal and any additional information ONRR deems necessary.

(4) If your payments for transportation under an arm's-length contract are not based on a dollar per unit price, you must convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.

(5) Where an arm's-length sales contract price includes a reduction for a transportation factor, ONRR will not consider the transportation factor to be a transportation allowance. You may use the transportation factor to determine your gross proceeds for the sale of the product. However, the transportation factor may not exceed 50 percent of the base price of the product without ONRR approval.

(b) Determining a transportation allowance under a non-arm's-length or no contract. (1) This paragraph explains how to determine your allowance if you have a non-arm's-length transportation contract or no contract.

(i) When you have a non-arm's-length transportation contract or no contract, including those situations where you perform transportation services for yourself, the transportation allowance is based upon your reasonable, allowable, actual costs for transportation as provided in this paragraph.

(ii) All transportation allowances deducted under a non-arm's-length or no contract situation are subject to monitoring, review, audit, and adjustment. You must submit the actual cost information to support the allowance to ONRR on Form ONRR-4295, Gas Transportation Allowance Report, within 3 months after the end of the 12-month period to which the allowance applies. However, ONRR may approve a longer time period. ONRR will monitor the allowance deductions to ensure that deductions are reasonable and allowable. When necessary or appropriate, ONRR may require you to modify your actual transportation allowance deduction.

(2) This paragraph explains what actual transportation costs are allowable under a non-arm's-length contract or no contract situation. The transportation allowance for non-arm's-length or no-contract situations is based upon your actual costs for transportation during the reporting period. Allowable costs include operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment (in accordance with paragraph (b)(2)(iv)(A) of this section), or a cost equal to the initial depreciable investment in the transportation system multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those costs for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the transportation system.

(i) Allowable operating expenses include operations supervision and engineering, operations labor, fuel, utilities, materials, ad valorem property taxes, rent, supplies, and any other directly allocable and attributable operating expense that you can document.

(ii) Allowable maintenance expenses include maintenance of the transportation system, maintenance of equipment, maintenance labor, and other directly allocable and attributable maintenance expenses that you can document.

(iii) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.

(iv) You may use either depreciation with a return on undepreciated capital investment or a return on depreciable capital investment. After you have elected to use either method for a transportation system, you may not later elect to change to the other alternative without ONRR approval.

(A) To compute depreciation, you may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves that the transportation system services, or a unit of production method. Once you make an election, you may not change methods without ONRR approval. A change in ownership of a transportation system will not alter the depreciation schedule that the original transporter/lessee established for purposes of the allowance calculation. With or without a change in ownership, a transportation system may be depreciated only once. Equipment may not be depreciated below a reasonable salvage value. To compute a return on undepreciated capital investment, you will multiply the undepreciated capital investment in the transportation system by the rate of return determined under paragraph (b)(2)(v) of this section.

(B) To compute a return on depreciable capital investment, you will multiply the initial capital investment in the transportation system by the rate of return determined under paragraph (b)(2)(v) of this section. No allowance will be provided for depreciation. This alternative will apply only to transportation facilities first placed in service after March 1, 1988.

(v) The rate of return is the industrial rate associated with Standard and Poor's BBB rating. The rate of return is the monthly average rate as published in Standard and Poor's Bond Guide for the first month of the reporting period for which the allowance is applicable and is effective during the reporting period. The rate must be redetermined at the beginning of each subsequent transportation allowance reporting period that is determined under paragraph (b)(4) of this section.

(3) This paragraph explains how to allocate transportation costs to each product and transportation system.

(i) The deduction for transportation costs must be determined based on your cost of transporting each product through each individual transportation system. If you transport more than one product in a gaseous phase, the allocation of costs to each of the products transported must be made in a consistent and equitable manner. The allocation should be in the same proportion that the volume of each product (excluding waste products that have no value) bears to the volume of all products in the gaseous phase (excluding waste products that have no value). Except as provided in this paragraph, you may not take an allowance for transporting a product that is not royalty bearing without ONRR approval.

(ii) As an alternative to the requirements of paragraph (b)(3)(i) of this section, you may propose to ONRR a cost allocation method based on the values of the products transported. ONRR will approve the method upon determining that it meets one of the two following requirements:

(A) The methodology in paragraph (b)(3)(i) of this section cannot be applied; and

(B) Your proposal is more reasonable than the method in paragraph (b)(3)(i) of this section.

(4) Your transportation allowance under this paragraph (b) must be determined based upon a calendar year or other period if you and ONRR agree to an alternative.

(5) If you transport both gaseous and liquid products through the same transportation system, you must propose a cost allocation procedure to ONRR. You may use the transportation allowance determined in accordance with your proposed allocation procedure until ONRR issues its determination on the acceptability of the cost allocation. You are required to submit all relevant data to support your proposal. ONRR will then determine the transportation allowance based upon your proposal and any additional information ONRR deems necessary.

(c) Using the alternative transportation calculation when you have a non-arm's-length or no contract. (1) As an alternative to computing your transportation allowance under paragraph (b) of this section, you may use as the transportation allowance 10 percent of your gross proceeds but not to exceed 30 cents per MMBtu.

(2) Your election to use the alternative transportation allowance calculation in paragraph (c)(1) of this section must be made at the beginning of a month and must remain in effect for an entire calendar year. Your first election will remain in effect until the end of the succeeding calendar year, except for elections effective January 1 that will be effective only for that calendar year.

(d) Reporting your transportation allowance. (1) If ONRR requests, you must submit all data used to determine your transportation allowance. The data must be provided within a reasonable period of time that ONRR will determine.

(2) You must report transportation allowances as a separate entry on Form ONRR-2014. ONRR may approve a different reporting procedure on allottee leases, and with lessor approval on tribal leases.

(e) Adjusting incorrect allowances. If for any month the transportation allowance you are entitled to is less than the amount you took on Form ONRR-2014, you are required to report and pay additional royalties due, plus interest computed under § 1218.54 of this chapter from the first day of the first month you deducted the improper transportation allowance until the date you pay the royalties due. If the transportation allowance you are entitled to is greater than the amount you took on Form ONRR-2014 for any royalties during the reporting period, you are entitled to a credit. No interest will be paid on the overpayment.

(f) Determining allowable costs for transportation allowances. Lessees may include, but are not limited to, the following costs in determining the arm's-length transportation allowance under paragraph (a) of this section or the non-arm's-length transportation allowance under paragraph (b) of this section:

(1) Firm demand charges paid to pipelines. You must limit the allowable costs for the firm demand charges to the applicable rate per MMBtu multiplied by the actual volumes transported. You may not include any losses incurred for previously purchased but unused firm capacity. You also may not include any gains associated with releasing firm capacity. If you receive a payment or credit from the pipeline for penalty refunds, rate case refunds, or other reasons, you must reduce the firm demand charge claimed on the Form ONRR-2014. You must modify the Form ONRR-2014 by the amount received or credited for the affected reporting period.

(2) Gas supply realignment (GSR) costs. The GSR costs result from a pipeline reforming or terminating supply contracts with producers to implement the restructuring requirements of FERC orders in 18 CFR part 284.

(3) Commodity charges. The commodity charge allows the pipeline to recover the costs of providing service.

(4) Wheeling costs. Hub operators charge a wheeling cost for transporting gas from one pipeline to either the same or another pipeline through a market center or hub. A hub is a connected manifold of pipelines through which a series of incoming pipelines are interconnected to a series of outgoing pipelines.

(5) Gas Research Institute (GRI) fees. The GRI conducts research, development, and commercialization programs on natural gas related topics for the benefit of the U.S. gas industry and gas customers. GRI fees are allowable provided such fees are mandatory in FERC-approved tariffs.

(6) Annual Charge Adjustment (ACA) fees. FERC charges these fees to pipelines to pay for its operating expenses.

(7) Payments (either volumetric or in value) for actual or theoretical losses. This paragraph does not apply to non-arm's-length transportation arrangements.

(8) Temporary storage services. This includes short duration storage services offered by market centers or hubs (commonly referred to as “parking” or “banking”), or other temporary storage services provided by pipeline transporters, whether actual or provided as a matter of accounting. Temporary storage is limited to 30 days or less.

(9) Supplemental costs for compression, dehydration, and treatment of gas. ONRR allows these costs only if such services are required for transportation and exceed the services necessary to place production into marketable condition required under § 1206.174(h).

(g) Determining nonallowable costs for transportation allowances. Lessees may not include the following costs in determining the arm's-length transportation allowance under paragraph (a) of this section or the non-arm's-length transportation allowance under paragraph (b) of this section:

(1) Fees or costs incurred for storage. This includes storing production in a storage facility, whether on or off the lease, for more than 30 days.

(2) 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 the following:

(i) Over-delivery cash-out penalties. This includes the difference between the price the pipeline pays you for over-delivered volumes outside the tolerances and the price you receive for over-delivered volumes within tolerances.

(ii) Scheduling penalties. This includes penalties you incur for differences between daily volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point.

(iii) Imbalance penalties. This includes penalties you incur (generally on a monthly basis) for differences between volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point.

(iv) Operational penalties. This includes fees you incur for violation of the pipeline's curtailment or operational orders issued to protect the operational integrity of the pipeline.

(4) Intra-hub transfer fees. These are fees you pay to hub operators for administrative services (e.g., title transfer tracking) necessary to account for the sale of gas within a hub.

(5) Other nonallowable costs. Any cost you incur for services you are required to provide at no cost to the lessor.

(h) Other transportation cost determinations. You must follow the provisions of this section to determine transportation costs when establishing value using either a net-back valuation procedure or any other procedure that allows deduction of actual transportation costs.

[64 FR 43515, Aug. 10, 1999, as amended at 73 FR 15891, Mar. 26, 2008]

§ 1206.179 What general requirements regarding processing allowances apply to me?

(a) When you value any gas plant product under § 1206.174, you may deduct from value the reasonable actual costs of processing.

(b) You must allocate processing costs among the gas plant products. You must determine a separate processing allowance for each gas plant product and processing plant relationship. Natural gas liquids are considered as one product.

(c) The processing allowance deduction based on an individual product may not exceed 66 2/3 percent of the value of each gas plant product determined under § 1206.174. Before you calculate the 66 2/3 percent limit, you must first reduce the value for any transportation allowances related to post-processing transportation authorized under § 1206.177.

(d) Processing cost deductions will not be allowed for placing lease products in marketable condition. These costs include among others, dehydration, separation, compression upstream of the facility measurement point, or storage, even if those functions are performed off the lease or at a processing plant. Costs for the removal of acid gases, commonly referred to as sweetening, are not allowed unless the acid gases removed are further processed into a gas plant product. In such event, you will be eligible for a processing allowance determined under this subpart. However, ONRR will not grant any processing allowance for processing lease production that is not royalty bearing.

(e) You will be allowed a reasonable amount of residue gas royalty free for operation of the processing plant, but no allowance will be made for expenses incidental to marketing, except as provided in 30 CFR part 1206. In those situations where a processing plant processes gas from more than one lease, only that proportionate share of your residue gas necessary for the operation of the processing plant will be allowed royalty free.

(f) You do not owe royalty on residue gas, or any gas plant product resulting from processing gas, that is reinjected into a reservoir within the same lease, unit, or approved Federal agreement, until such time as those products are finally produced from the reservoir for sale or other disposition. This paragraph applies only when the reinjection is included in a BLM-approved plan of development or operations.

(g) If ONRR determines that you have determined an improper processing allowance authorized by this subpart, then you will be required to pay any additional royalties plus late payment interest determined under § 1218.54 of this chapter. Alternatively, you may be entitled to a credit, but you will not receive any interest on your overpayment.

§ 1206.180 How do I determine an actual processing allowance?

(a) Determining a processing allowance if you have an arms's-length processing contract. (1) This paragraph explains how you determine an allowance under an arm's-length processing contract.

(i) The processing allowance is the reasonable actual costs you incur to process the gas under that contract. Paragraphs (a)(1)(ii) and (iii) of this section provide a limited exception. You have the burden of demonstrating that your contract is arm's-length. You are required to submit to ONRR a copy of your arm's-length contract(s) and all subsequent amendments to the contract(s) within 2 months of the date ONRR receives your first report that deducts the allowance on the Form ONRR-2014.

(ii) When ONRR conducts reviews and audits, we will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from you to the processor for the processing. If the contract reflects more than the total consideration, then ONRR may require that the processing allowance be determined under paragraph (b) of this section.

(iii) If ONRR determines that the consideration paid under an arm's-length processing contract does not reflect the value of the processing because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of you and the lessor, then ONRR will require that the processing allowance be determined under paragraph (b) of this section. In these circumstances, ONRR will notify you and give you an opportunity to provide written information justifying your processing costs.

(2) If your arm's-length processing contract includes more than one gas plant product and the processing costs attributable to each product can be determined from the contract, then the processing costs for each gas plant product must be determined in accordance with the contract. You may not take an allowance for the costs of processing lease production that is not royalty-bearing.

(3) If your arm's-length processing contract includes more than one gas plant product and the processing costs attributable to each product cannot be determined from the contract, you must propose an allocation procedure to ONRR. You may use your proposed allocation procedure until ONRR issues its determination. You are required to submit all relevant data to support your proposal. ONRR will then determine the processing allowance based upon your proposal and any additional information ONRR deems necessary. You may not take a processing allowance for the costs of processing lease production that is not royalty-bearing.

(4) If your payments for processing under an arm's-length contract are not based on a dollar per unit price, you must convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.

(b) Determining a processing allowance if you have a non-arm's-length contract or no contract. (1) This paragraph applies if you have a non-arm's-length processing contract or no contract, including those situations where you perform processing for yourself.

(i) If you have a non-arm's-length contract or no contract, the processing allowance is based upon your reasonable actual costs of processing as provided in paragraph (b)(2) of this section.

(ii) All processing allowances deducted under a non-arm's-length or no-contract situation are subject to monitoring, review, audit, and adjustment. You must submit the actual cost information to support the allowance to ONRR on Form ONRR-4109, Gas Processing Allowance Summary Report, within 3 months after the end of the 12-month period for which the allowance applies. ONRR may approve a longer time period. ONRR will monitor the allowance deduction to ensure that deductions are reasonable and allowable. When necessary or appropriate, ONRR may require you to modify your processing allowance.

(2) The processing allowance for non-arm's-length or no-contract situations is based upon your actual costs for processing during the reporting period. Allowable costs include operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment (in accordance with paragraph (b)(2)(iv)(A) of this section), or a cost equal to the initial depreciable investment in the processing plant multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those costs for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the processing plant.

(i) Allowable operating expenses include operations supervision and engineering, operations labor, fuel, utilities, materials, ad valorem property taxes, rent, supplies, and any other directly allocable and attributable operating expense that the lessee can document.

(ii) Allowable maintenance expenses include maintenance of the processing plant, maintenance of equipment, maintenance labor, and other directly allocable and attributable maintenance expenses that you can document.

(iii) Overhead directly attributable and allocable to the operation and maintenance of the processing plant is an allowable expense. State and Federal income taxes and severance taxes, including royalties, are not allowable expenses.

(iv) You may use either depreciation with a return on undepreciable capital investment or a return on depreciable capital investment. After you elect to use either method for a processing plant, you may not later elect to change to the other alternative without ONRR approval.

(A) To compute depreciation, you may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves that the processing plant services, or a unit-of-production method. Once you make an election, you may not change methods without ONRR approval. A change in ownership of a processing plant will not alter the depreciation schedule that the original processor/lessee established for purposes of the allowance calculation. However, for processing plants you or your affiliate purchase that do not have a previously claimed ONRR depreciation schedule, you may treat the processing plant as a newly installed facility for depreciation purposes. A processing plant may be depreciated only once, regardless of whether there is a change in ownership. Equipment may not be depreciated below a reasonable salvage value. To compute a return on undepreciated capital investment, you must multiply the undepreciable capital investment in the processing plant by the rate of return determined under paragraph (b)(2)(v) of this section.

(B) To compute a return on depreciable capital investment, you must multiply the initial capital investment in the processing plant by the rate of return determined under paragraph (b)(2)(v) of this section. No allowance will be provided for depreciation. This alternative will apply only to plants first placed in service after March 1, 1988.

(v) The rate of return is the industrial rate associated with Standard and Poor's BBB rating. The rate of return is the monthly average rate as published in Standard and Poor's Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year.

(3) Your processing allowance under this paragraph (b) must be determined based upon a calendar year or other period if you and ONRR agree to an alternative.

(4) The processing allowance for each gas plant product must be determined based on your reasonable and actual cost of processing the gas. You must base your allocation of costs to each gas plant product upon generally accepted accounting principles. You may not take an allowance for the costs of processing lease production that is not royalty-bearing.

(c) Reporting your processing allowance. (1) If ONRR requests, you must submit all data used to determine your processing allowance. The data must be provided within a reasonable period of time, as ONRR determines.

(2) You must report gas processing allowances as a separate entry on the Form ONRR-2014. ONRR may approve a different reporting procedure for allottee leases, and with lessor approval on tribal leases.

(d) Adjusting incorrect processing allowances. If for any month the gas processing allowance you are entitled to is less than the amount you took on Form ONRR-2014, you are required to pay additional royalties, plus interest computed under § 1218.54 of this chapter from the first day of the first month you deducted a processing allowance until the date you pay the royalties due. If the processing allowance you are entitled is greater than the amount you took on Form ONRR-2014, you are entitled to a credit. However, no interest will be paid on the overpayment.

(e) Other processing cost determinations. You must follow the provisions of this section to determine processing costs when establishing value using either a net-back valuation procedure or any other procedure that requires deduction of actual processing costs.

[64 FR 43515, Aug. 10, 1999, as amended at 73 FR 15891, Mar. 26, 2008]

§ 1206.181 How do I establish processing costs for dual accounting purposes when I do not process the gas?

Where accounting for comparison (dual accounting) is required for gas production from a lease but neither you nor someone acting on your behalf processes the gas, and you have elected to perform actual dual accounting under § 1206.176, you must use the first applicable of the following methods to establish processing costs for dual accounting purposes:

(a) The average of the costs established in your current arm's-length processing agreements for gas from the lease, provided that some gas has previously been processed under these agreements.

(b) The average of the costs established in your current arm's-length processing agreements for gas from the lease, provided that the agreements are in effect for plants to which the lease is physically connected and under which gas from other leases in the field or area is being or has been processed.

(c) A proposed comparable processing fee submitted to either the tribe and ONRR (for tribal leases) or ONRR (for allotted leases) with your supporting documentation submitted to ONRR. If ONRR does not take action on your proposal within 120 days, the proposal will be deemed to be denied and subject to appeal to the ONRR Director under 30 CFR part 1290.

(d) Processing costs based on the regulations in §§ 1206.179 and 1206.180.

§ 1206.250 Purpose and scope.

(a) This subpart is applicable to all coal produced from Federal coal leases. The purpose of this subpart is to establish the value of coal produced for royalty purposes, of all coal from Federal leases consistent with the mineral leasing laws, other applicable laws and lease terms.

(b) If the specific provisions of any statute or settlement agreement between the United States and a lessee resulting from administrative or judicial litigation, or any coal lease subject to the requirements of this subpart, are inconsistent with any regulation in this subpart then the statute, lease provision, or settlement shall govern to the extent of that inconsistency.

(c) ONRR may audit and order you to adjust all royalty payments. ONRR or an authorized State may require you to provide records for the audit by one or more of the methods specified in 30 CFR 1217.10.

[88 FR 47006, July 21, 2023, as amended at 88 FR 53792, Aug. 9, 2023]

§ 1206.251 Definitions.

The definitions in § 1206.20 do not apply to this subpart. For purposes of this subpart:

Ad valorem lease means a lease where the royalty due to the lessor is based upon a percentage of the amount or value of the coal.

Allowance means a deduction used in determining value for royalty purposes. Coal washing allowance means an allowance for the reasonable, actual costs incurred by the lessee for coal washing. Transportation allowance means an allowance for the reasonable, actual costs incurred by the lessee for moving coal to a point of sale or point of delivery remote from both the lease and mine or wash plant.

Area means a geographic region in which coal has similar quality and economic characteristics. Area boundaries are not officially designated and the areas are not necessarily named.

Arm's-length contract means:

(1) A contract or agreement that has been arrived at in the marketplace between independent, nonaffiliated persons with opposing economic interests regarding that contract. For purposes of this subpart, two persons are affiliated if one person controls, is controlled by, or is under common control with another person. For purposes of this subpart, based on the instruments of ownership of the voting securities of an entity, or based on other forms of ownership:

(i) Ownership in excess of 50 percent constitutes control;

(ii) Ownership of 10 through 50 percent creates a presumption of control; and

(iii) Ownership of less than 10 percent creates a presumption of noncontrol which ONRR may rebut if it demonstrates actual or legal control, including the existence of interlocking directorates.

(2) Notwithstanding any other provisions of this subpart, contracts between relatives, either by blood or by marriage, are not arm's-length contracts. The ONRR may require the lessee to certify ownership control. To be considered arm's-length for any production month, a contract must meet the requirements of this definition for that production month as well as when the contract was executed.

Audit means a review, conducted in accordance with generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees or other interest holders who pay royalties, rents, or bonuses on Federal leases.

BLM means the Bureau of Land Management of the Department of the Interior.

Coal means coal of all ranks from lignite through anthracite.

Coal washing means any treatment to remove impurities from coal. Coal washing may include, but is not limited to, operations such as flotation, air, water, or heavy media separation; drying; and related handling (or combination thereof).

Contract means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.

Gross proceeds (for royalty payment purposes) means the total monies and other consideration accruing to a coal lessee for the production and disposition of the coal produced. Gross proceeds includes, but is not limited to, payments to the lessee for certain services such as crushing, sizing, screening, storing, mixing, loading, treatment with substances including chemicals or oils, and other preparation of the coal to the extent that the lessee is obligated to perform them at no cost to the Federal Government. Gross proceeds, as applied to coal, also includes but is not limited to reimbursements for royalties, taxes or fees, and other reimbursements. Tax reimbursements are part of the gross proceeds accruing to a lessee even though the Federal royalty interest may be exempt from taxation. Monies and other consideration, including the forms of consideration identified in this paragraph, to which a lessee is contractually or legally entitled but which it does not seek to collect through reasonable efforts are also part of gross proceeds.

Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States for a Federal coal resource under a mineral leasing law that authorizes exploration for, development or extraction of, or removal of coal—or the land covered by that authorization, whichever is required by the context.

Lessee means any person to whom the United States issues a lease, and any person who has been assigned an obligation to make royalty or other payments required by the lease. This includes any person who has an interest in a lease as well as an operator or payor who has no interest in the lease but who has assumed the royalty payment responsibility.

Like-quality coal means coal that has similar chemical and physical characteristics.

Marketable condition means coal that is sufficiently free from impurities and otherwise in a condition that it will be accepted by a purchaser under a sales contract typical for that area.

Mine means an underground or surface excavation or series of excavations and the surface or underground support facilities that contribute directly or indirectly to mining, production, preparation, and handling of lease products.

Net-back method means a method for calculating market value of coal at the lease or mine. Under this method, costs of transportation, washing, handling, etc., are deducted from the ultimate proceeds received for the coal at the first point at which reasonable values for the coal may be determined by a sale pursuant to an arm's-length contract or by comparison to other sales of coal, to ascertain value at the mine.

Net output means the quantity of washed coal that a washing plant produces.

Netting is the deduction of an allowance from the sales value by reporting a one line net sales value, instead of correctly reporting the deduction as a separate line item on the form ONRR-4430.

Person means by individual, firm, corporation, association, partnership, consortium, or joint venture.

Sales type code means the contract type or general disposition (e.g., arm's-length or non-arm's-length) of production from the lease. The sales type code applies to the sales contract, or other disposition, and not to the arm's-length or non-arm's-length nature of a transportation or washing allowance.

Spot market price means the price received under any sales transaction when planned or actual deliveries span a short period of time, usually not exceeding one year.

§ 1206.252 Information collection.

The information collection requirements contained in this subpart have been approved by the Office of Management and Budget (OMB) under 44 U.S.C. 3501 et seq. The forms, filing date, and approved OMB control numbers are identified in part 1210 of this subchapter.

§ 206.253 Coal subject to royalties—general provisions.

(a) All coal (except coal unavoidably lost as determined by BLM under 43 CFR part 3400) from a Federal lease subject to this part is subject to royalty. This includes coal used, sold, or otherwise disposed of by the lessee on or off the lease.

(b) If a lessee receives compensation for unavoidably lost coal through insurance coverage or other arrangements, royalties at the rate specified in the lease are to be paid on the amount of compensation received for the coal. No royalty is due on insurance compensation received by the lessee for other losses.

(c) If waste piles or slurry ponds are reworked to recover coal, the lessee shall pay royalty at the rate specified in the lease at the time the recovered coal is used, sold, or otherwise finally disposed of. The royalty rate shall be that rate applicable to the production method used to initially mine coal in the waste pile or slurry pond; i.e., underground mining method or surface mining method. Coal in waste pits or slurry ponds initially mined from Federal leases shall be allocated to such leases regardless of whether it is stored on Federal lands. The lessee shall maintain accurate records to determine to which individual Federal lease coal in the waste pit or slurry pond should be allocated. However, nothing in this section requires payment of a royalty on coal for which a royalty has already been paid.

§ 1206.254 Quality and quantity measurement standards for reporting and paying royalties.

For all leases subject to this subpart, the quantity of coal on which royalty is due shall be measured in short tons (of 2,000 pounds each) by methods prescribed by the BLM. Coal quantity information will be reported on appropriate forms required under 30 CFR part 1210 of this subchapter.

§ 1206.255 Point of royalty determination.

(a) For all leases subject to this subpart, royalty shall be computed on the basis of the quantity and quality of Federal coal in marketable condition measured at the point of royalty measurement as determined jointly by BLM and ONRR.

(b) Coal produced and added to stockpiles or inventory does not require payment of royalty until such coal is later used, sold, or otherwise finally disposed of. ONRR may ask BLM to increase the lease bond to protect the lessor's interest when BLM determines that stockpiles or inventory become excessive so as to increase the risk of degradation of the resource.

(c) The lessee shall pay royalty at a rate specified in the lease at the time the coal is used, sold, or otherwise finally disposed of, unless otherwise provided for at § 1206.256(d).

§ 1206.256 Valuation standards for cents-per-ton leases.

(a) This section is applicable to coal leases on Federal lands which provide for the determination of royalty on a cents-per-ton (or other quantity) basis.

(b) The royalty for coal from leases subject to this section shall be based on the dollar rate per ton prescribed in the lease. That dollar rate shall be applicable to the actual quantity of coal used, sold, or otherwise finally disposed of, including coal which is avoidably lost as determine by BLM pursuant to 43 CFR part 3400.

(c) For leases subject to this section, there shall be no allowances for transportation, removal of impurities, coal washing, or any other processing or preparation of the coal.

(d) When a coal lease is readjusted pursuant to 43 CFR part 3400 and the royalty valuation method changes from a cents-per-ton basis to an ad valorem basis, coal which is produced prior to the effective date of readjustment and sold or used within 30 days of the effective date of readjustment shall be valued pursuant to this section. All coal that is not used, sold, or otherwise finally disposed of within 30 days after the effective date of readjustment shall be valued pursuant to the provisions of § 1206.257, and royalties shall be paid at the royalty rate specified in the readjusted lease.

§ 1206.257 Valuation standards for ad valorem leases.

(a) This section is applicable to coal leases on Federal lands which provide for the determination of royalty as a percentage of the amount of value of coal (ad valorem). The value for royalty purposes of coal from such leases shall be the value of coal determined under this section, less applicable coal washing allowances and transportation allowances determined under §§ 1206.258 through 1206.262, or any allowance authorized by § 1206.265. The royalty due shall be equal to the value for royalty purposes multiplied by the royalty rate in the lease.

(b)(1) The value of coal that is sold pursuant to an arm's-length contract shall be the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(2), (3), and (5) of this section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value which the lessee reports, for royalty purposes, is subject to monitoring, review, and audit.

(2) In conducting reviews and audits, ONRR will examine whether the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the coal produced. If the contract does not reflect the total consideration, then the ONRR may require that the coal sold pursuant to that contract be valued in accordance with paragraph (c) of this section. Value may not be based on less than the gross proceeds accruing to the lessee for the coal production, including the additional consideration.

(3) If ONRR determines that the gross proceeds accruing to the lessee pursuant to an arm's-length contract do not reflect the reasonable value of the production because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then ONRR shall require that the coal production be valued pursuant to paragraph (c)(2)(ii), (iii), (iv), or (v) of this section, and in accordance with the notification requirements of paragraph (d)(3) of this section. When ONRR determines that the value may be unreasonable, ONRR will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's reported coal value.

(4) ONRR may require a lessee to certify that its arm's-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the coal production.

(5) The value of production for royalty purposes shall not include payments received by the lessee pursuant to a contract which the lessee demonstrates, to ONRR's satisfaction, were not part of the total consideration paid for the purchase of coal production.

(c)(1) The value of coal from leases subject to this section and which is not sold pursuant to an arm's-length contract shall be determined in accordance with this section.

(2) If the value of the coal cannot be determined pursuant to paragraph (b) of this section, then the value shall be determined through application of other valuation criteria. The criteria shall be considered in the following order, and the value shall be based upon the first applicable criterion:

(i) The gross proceeds accruing to the lessee pursuant to a sale under its non-arm's-length contract (or other disposition of produced coal by other than an arm's-length contract), provided that those gross proceeds are within the range of the gross proceeds derived from, or paid under, comparable arm's-length contracts between buyers and sellers neither of whom is affiliated with the lessee for sales, purchases, or other dispositions of like-quality coal produced in the area. In evaluating the comparability of arm's-length contracts for the purposes of these regulations, the following factors shall be considered: Price, time of execution, duration, market or markets served, terms, quality of coal, quantity, and such other factors as may be appropriate to reflect the value of the coal;

(ii) Prices reported for that coal to a public utility commission;

(iii) Prices reported for that coal to the Energy Information Administration of the Department of Energy;

(iv) Other relevant matters including, but not limited to, published or publicly available spot market prices, or information submitted by the lessee concerning circumstances unique to a particular lease operation or the saleability of certain types of coal;

(v) If a reasonable value cannot be determined using paragraph (c)(2)(i), (ii), (iii), or (iv) of this section, then a net-back method or any other reasonable method shall be used to determine value.

(3) When the value of coal is determined pursuant to paragraph (c)(2) of this section, that value determination shall be consistent with the provisions contained in paragraph (b)(5) of this section.

(d)(1) Where the value is determined pursuant to paragraph (c) of this section, that value does not require ONRR's prior approval. However, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject to review and audit, and ONRR will direct a lessee to use a different value if it determines that the reported value is inconsistent with the requirements of these regulations.

(2) Any Federal lessee will make available upon request to the authorized ONRR or State representatives, to the Inspector General of the Department of the Interior or other persons authorized to receive such information, arm's-length sales value and sales quantity data for like-quality coal sold, purchased, or otherwise obtained by the lessee from the area.

(3) A lessee shall notify ONRR if it has determined value pursuant to paragraph (c)(2)(ii), (iii), (iv), or (v) of this section. The notification shall be by letter to the Director for Office of Natural Resources Revenue of his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this section is a one-time notification due no later than the month the lessee first reports royalties on the form ONRR-4430 using a valuation method authorized by paragraph (c)(2)(ii), (iii), (iv), or (v) of this section, and each time there is a change in a method under paragraph (c)(2)(iv) or (v) of this section.

(e) If ONRR determines that a lessee has not properly determined value, the lessee shall be liable for the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by ONRR. The lessee shall also be liable for interest computed pursuant to § 1218.202 of this subchapter. If the lessee is entitled to a credit, ONRR will provide instructions for the taking of that credit.

(f) The lessee may request a value determination from ONRR. In that event, the lessee shall propose to ONRR a value determination method, and may use that method in determining value for royalty purposes until ONRR issues its decision. The lessee shall submit all available data relevant to its proposal. The ONRR shall expeditiously determine the value based upon the lessee's proposal and any additional information ONRR deems necessary. That determination shall remain effective for the period stated therein. After ONRR issues its determination, the lessee shall make the adjustments in accordance with paragraph (e) of this section.

(g) Notwithstanding any other provisions of this section, under no circumstances shall the value for royalty purposes be less than the gross proceeds accruing to the lessee for the disposition of produced coal less applicable provisions of paragraph (b)(5) of this section and less applicable allowances determined pursuant to §§ 1206.258 through 1206.262 and 1206.265.

(h) The lessee is required to place coal in marketable condition at no cost to the Federal Government. Where the value established under this section is determined by a lessee's gross proceeds, that value shall be increased to the extent that the gross proceeds has been reduced because the purchaser, or any other person, is providing certain services, the cost of which ordinarily is the responsibility of the lessee to place the coal in marketable condition.

(i) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled, it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to an arm's-length contract, and may be retroactively applied to value for royalty purposes for a period not to exceed two years, unless ONRR approves a longer period. If the lessee makes timely application for a price increase allowed under its contract but the purchaser refuses, and the lessee takes reasonable measures, which are documented, to force purchaser compliance, the lessee will owe no additional royalties unless or until monies or consideration resulting from the price increase are received. This paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a quantity of coal.

(j) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by ONRR of value under this section shall be considered final or binding as against the Federal Government or its beneficiaries until the audit period is formally closed.

(k) Certain information submitted to ONRR to support valuation proposals, including transportation, coal washing, or other allowances under § 1206.265, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 522. Any data specified by the Act to be privileged, confidential, or otherwise exempt shall be maintained in a confidential manner in accordance with applicable law and regulations. All requests for information about determinations made under this part are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2.

§ 1206.258 Washing allowances—general.

(a) For ad valorem leases subject to § 1206.257, ONRR shall, as authorized by this section, allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to wash coal, unless the value determined pursuant to § 1206.257 was based upon like-quality unwashed coal. Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero.

(b) If ONRR determines that a lessee has improperly determined a washing allowance authorized by this section, then the lessee shall be liable for any additional royalties, plus interest determined in accordance with § 1218.202 of this subchapter, or shall be entitled to a credit without interest.

(c) Lessees shall not disproportionately allocate washing costs to Federal leases.

(d) No cost normally associated with mining operations and which are necessary for placing coal in marketable condition shall be allowed as a cost of washing.

(e) Coal washing costs shall only be recognized as allowances when the washed coal is sold and royalties are reported and paid.

§ 1206.259 Determination of washing allowances.

(a) Arm's-length contracts. (1) For washing costs incurred by a lessee under an arm's-length contract, the washing allowance shall be the reasonable actual costs incurred by the lessee for washing the coal under that contract, subject to monitoring, review, audit, and possible future adjustment. The lessee shall have the burden of demonstrating that its contract is arm's-length. ONRR's prior approval is not required before a lessee may deduct costs incurred under an arm's-length contract. The lessee must claim a washing allowance by reporting it as a separate line entry on the Form ONRR-4430.

(2) In conducting reviews and audits, ONRR will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the washer for the washing. If the contract reflects more than the total consideration paid, then the ONRR may require that the washing allowance be determined in accordance with paragraph (b) of this section.

(3) If ONRR determines that the consideration paid pursuant to an arm's-length washing contract does not reflect the reasonable value of the washing because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then ONRR shall require that the washing allowance be determined in accordance with paragraph (b) of this section. When ONRR determines that the value of the washing may be unreasonable, ONRR will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's washing costs.

(4) Where the lessee's payments for washing under an arm's-length contract are not based on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent. Washing allowances shall be expressed as a cost per ton of coal washed.

(b) Non-arm's-length or no contract. (1) If a lessee has a non-arm's-length contract or has no contract, including those situations where the lessee performs washing for itself, the washing allowance will be based upon the lessee's reasonable actual costs. All washing allowances deducted under a non-arm's-length or no contract situation are subject to monitoring, review, audit, and possible future adjustment. The lessee must claim a washing allowance by reporting it as a separate line entry on the Form ONRR-4430. When necessary or appropriate, ONRR may direct a lessee to modify its estimated or actual washing allowance.

(2) The washing allowance for non-arm's-length or no contract situations shall be based upon the lessee's actual costs for washing during the reported period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the depreciable investment in the wash plant multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the wash plant.

(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes, rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.

(ii) Allowable maintenance expenses include: Maintenance of the wash plant; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.

(iii) Overhead attributable and allocable to the operation and maintenance of the wash plant is an allowable expense. State and Federal income taxes and severance taxes, including royalties, are not allowable expenses.

(iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this section. After a lessee has elected to use either method for a wash plant, the lessee may not later elect to change to the other alternative without approval of the ONRR.

(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the wash plant services, whichever is appropriate, or a unit of production method. After an election is made, the lessee may not change methods without ONRR approval. A change in ownership of a wash plant shall not alter the depreciation schedule established by the original operator/lessee for purposes of the allowance calculation. With or without a change in ownership, a wash plant shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.

(B) ONRR shall allow as a cost an amount equal to the allowable capital investment in the wash plant multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to plants first placed in service or acquired after March 1, 1989.

(v) The rate of return must be the industrial rate associated with Standard and Poor's BBB rating. The rate of return must be the monthly average rate as published in Standard and Poor's Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year.

(3) The washing allowance for coal shall be determined based on the lessee's reasonable and actual cost of washing the coal. The lessee may not take an allowance for the costs of washing lease production that is not royalty bearing.

(c) Reporting requirements—(1) Arm's-length contracts. (i) The lessee must notify ONRR of an allowance based on incurred costs by using a separate line entry on the Form ONRR-4430.

(ii) ONRR may require that a lessee submit arm's-length washing contracts and related documents. Documents shall be submitted within a reasonable time, as determined by ONRR.

(2) Non-arm's-length or no contract. (i) The lessee must notify ONRR of an allowance based on the incurred costs by using a separate line entry on the Form ONRR-4430.

(ii) For new washing facilities or arrangements, the lessee's initial washing deduction shall include estimates of the allowable coal washing costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the washing system or, if such data are not available, the lessee shall use estimates based upon industry data for similar washing systems.

(iii) Upon request by ONRR, the lessee shall submit all data used to prepare the allowance deduction. The data shall be provided within a reasonable period of time, as determined by ONRR.

(d) Interest and assessments. (1) If a lessee nets a washing allowance on the Form ONRR-4430, then the lessee shall be assessed an amount up to 10 percent of the allowance netted not to exceed $250 per lease sales type code per sales period.

(2) If a lessee erroneously reports a washing allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.

(3) Interest required to be paid by this section shall be determined in accordance with § 1218.202 of this subchapter.

(e) Adjustments. (1) If the actual coal washing allowance is less than the amount the lessee has taken on Form ONRR-4430 for each month during the allowance reporting period, the lessee shall pay additional royalties due plus interest computed under § 1218.202 of this subchapter from the date when the lessee took the deduction to the date the lessee repays the difference to ONRR. If the actual washing allowance is greater than the amount the lessee has taken on Form ONRR-4430 for each month during the allowance reporting period, the lessee shall be entitled to a credit without interest.

(2) The lessee must submit a corrected Form ONRR-4430 to reflect actual costs, together with any payment, in accordance with instructions provided by ONRR.

(f) Other washing cost determinations. The provisions of this section shall apply to determine washing costs when establishing value using a net-back valuation procedure or any other procedure that requires deduction of washing costs.

§ 1206.260 Allocation of washed coal.

(a) When coal is subjected to washing, the washed coal must be allocated to the leases from which it was extracted.

(b) When the net output of coal from a washing plant is derived from coal obtained from only one lease, the quantity of washed coal allocable to the lease will be based on the net output of the washing plant.

(c) When the net output of coal from a washing plant is derived from coal obtained from more than one lease, unless determined otherwise by BLM, the quantity of net output of washed coal allocable to each lease will be based on the ratio of measured quantities of coal delivered to the washing plant and washed from each lease compared to the total measured quantities of coal delivered to the washing plant and washed.

§ 1206.261 Transportation allowances—general.

(a) For ad valorem leases subject to § 1206.257, where the value for royalty purposes has been determined at a point remote from the lease or mine, ONRR shall, as authorized by this section, allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to:

(1) Transport the coal from a Federal lease to a sales point which is remote from both the lease and mine; or

(2) Transport the coal from a Federal lease to a wash plant when that plant is remote from both the lease and mine and, if applicable, from the wash plant to a remote sales point. In-mine transportation costs shall not be included in the transportation allowance.

(b) Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero.

(c)(1) When coal transported from a mine to a wash plant is eligible for a transportation allowance in accordance with this section, the lessee is not required to allocate transportation costs between the quantity of clean coal output and the rejected waste material. The transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of cleaned coal transported.

(2) For coal that is not washed at a wash plant, the transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of coal transported.

(3) Transportation costs shall only be recognized as allowances when the transported coal is sold and royalties are reported and paid.

(d) If, after a review and/or audit, ONRR determines that a lessee has improperly determined a transportation allowance authorized by this section, then the lessee shall pay any additional royalties, plus interest, determined in accordance with § 1218.202 of this subchapter, or shall be entitled to a credit, without interest.

(e) Lessees shall not disproportionately allocate transportation costs to Federal leases.

§ 1206.262 Determination of transportation allowances.

(a) Arm's-length contracts. (1) For transportation costs incurred by a lessee pursuant to an arm's-length contract, the transportation allowance shall be the reasonable, actual costs incurred by the lessee for transporting the coal under that contract, subject to monitoring, review, audit, and possible future adjustment. The lessee shall have the burden of demonstrating that its contract is arm's-length. The lessee must claim a transportation allowance by reporting it as a separate line entry on the Form ONRR-4430.

(2) In conducting reviews and audits, ONRR will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the transporter for the transportation. If the contract reflects more than the total consideration paid, then the ONRR may require that the transportation allowance be determined in accordance with paragraph (b) of this section.

(3) If ONRR determines that the consideration paid pursuant to an arm's-length transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then ONRR shall require that the transportation allowance be determined in accordance with paragraph (b) of this section. When ONRR determines that the value of the transportation may be unreasonable, ONRR will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's transportation costs.

(4) Where the lessee's payments for transportation under an arm's-length contract are not based on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.

(b) Non-arm's-length or no contract. (1) If a lessee has a non-arm's-length contract or has no contract, including those situations where the lessee performs transportation services for itself, the transportation allowance will be based upon the lessee's reasonable actual costs. All transportation allowances deducted under a non-arm's-length or no contract situation are subject to monitoring, review, audit, and possible future adjustment. The lessee must claim a transportation allowance by reporting it as a separate line entry on the Form ONRR-4430. When necessary or appropriate, ONRR may direct a lessee to modify its estimated or actual transportation allowance deduction.

(2) The transportation allowance for non-arm's-length or no-contract situations shall be based upon the lessee's actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the depreciable investment in the transportation system multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system.

(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.

(ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.

(iii) Overhead attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.

(iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this section. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without approval of ONRR.

(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the transportation system services, whichever is appropriate, or a unit of production method. After an election is made, the lessee may not change methods without ONRR approval. A change in ownership of a transportation system shall not alter the depreciation schedule established by the original transporter/lessee for purposes of the allowance calculation. With or without a change in ownership, a transportation system shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.

(B) ONRR shall allow as a cost an amount equal to the allowable capital investment in the transportation system multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to transportation facilities first placed in service or acquired after March 1, 1989.

(v) The rate of return must be the industrial rate associated with Standard and Poor's BBB rating. The rate of return must be the monthly average rate as published in Standard and Poor's Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year.

(3) A lessee may apply to ONRR for exception from the requirement that it compute actual costs in accordance with paragraphs (b)(1) and (2) of this section. ONRR will grant the exception only if the lessee has a rate for the transportation approved by a Federal agency or by a State regulatory agency (for Federal leases). ONRR shall deny the exception request if it determines that the rate is excessive as compared to arm's-length transportation charges by systems, owned by the lessee or others, providing similar transportation services in that area. If there are no arm's-length transportation charges, ONRR shall deny the exception request if:

(i) No Federal or State regulatory agency costs analysis exists and the Federal or State regulatory agency, as applicable, has declined to investigate under ONRR timely objections upon filing; and

(ii) The rate significantly exceeds the lessee's actual costs for transportation as determined under this section.

(c) Reporting requirements—(1) Arm's-length contracts. (i) The lessee must notify ONRR of an allowance based on incurred costs by using a separate line entry on the form ONRR-4430.

(ii) ONRR may require that a lessee submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. Documents shall be submitted within a reasonable time, as determined by ONRR.

(2) Non-arm's-length or no contract. (i) The lessee must notify ONRR of an allowance based on the incurred costs by using a separate line entry on Form ONRR-4430.

(ii) For new transportation facilities or arrangements, the lessee's initial deduction shall include estimates of the allowable coal transportation costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the transportation system or, if such data are not available, the lessee shall use estimates based upon industry data for similar transportation systems.

(iii) Upon request by ONRR, the lessee shall submit all data used to prepare the allowance deduction. The data shall be provided within a reasonable period of time, as determined by ONRR.

(iv) If the lessee is authorized to use its Federal- or State-agency-approved rate as its transportation cost in accordance with paragraph (b)(3) of this section, it shall follow the reporting requirements of paragraph (c)(1) of this section.

(d) Interest and assessments. (1) If a lessee nets a transportation allowance on Form ONRR-4430, the lessee shall be assessed an amount of up to 10 percent of the allowance netted not to exceed $250 per lease sales type code per sales period.

(2) If a lessee erroneously reports a transportation allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.

(3) Interest required to be paid by this section shall be determined in accordance with § 1218.202 of this subchapter.

(e) Adjustments. (1) If the actual coal transportation allowance is less than the amount the lessee has taken on Form ONRR-4430 for each month during the allowance reporting period, the lessee shall pay additional royalties due plus interest computed under § 1218.202 of this subchapter from the date when the lessee took the deduction to the date the lessee repays the difference to ONRR. If the actual transportation allowance is greater than amount the lessee has taken on Form ONRR-4430 for each month during the allowance reporting period, the lessee shall be entitled to a credit without interest.

(2) The lessee must submit a corrected Form ONRR-4430 to reflect actual costs, together with any payments, in accordance with instructions provided by ONRR.

(f) Other transportation cost determinations. The provisions of this section shall apply to determine transportation costs when establishing value using a net-back valuation procedure or any other procedure that requires deduction of transportation costs.

§ 1206.263 [Reserved]

§ 1206.264 In-situ and surface gasification and liquefaction operations.

If an ad valorem Federal coal lease is developed by in-situ or surface gasification or liquefaction technology, the lessee shall propose the value of coal for royalty purposes to ONRR. The ONRR will review the lessee's proposal and issue a value determination. The lessee may use its proposed value until ONRR issues a value determination.

§ 1206.265 Value enhancement of marketable coal.

If, prior to use, sale, or other disposition, the lessee enhances the value of coal after the coal has been placed in marketable condition in accordance with § 1206.257(h), the lessee shall notify ONRR that such processing is occurring or will occur. The value of that production shall be determined as follows:

(a) A value established for the feedstock coal in marketable condition by application of the provisions of § 1206.257(c)(2)(i) through (iv); or,

(b) In the event that a value cannot be established in accordance with paragraph (a) of this section, then the value of production will be determined in accordance with § 1206.257(c)(2)(v) and the value shall be the lessee's gross proceeds accruing from the disposition of the enhanced product, reduced by ONRR-approved processing costs and procedures including a rate of return on investment equal to two times the Standard and Poor's BBB bond rate applicable under § 1206.259(b)(2)(v).

§ 1206.301 Value basis for royalty computation.

(a) The gross value for royalty purposes shall be the sale or contract unit price times the number of units sold, Provided, however, That where the authorized officer determines:

(1) That a contract of sale or other business arrangement between the lessee and a purchaser of some or all of the commodities produced from the lease is not a bona fide transaction between independent parties because it is based in whole or in part upon considerations other than the value of the commodities, or

(2) That no bona fide sales price is received for some or all of such commodities because the lessee is consuming them, the authorized officer shall determine their gross value, taking into account: (i) All prices received by the lessee in all bona fide transactions, (ii) Prices paid for commodities of like quality produced from the same general area, and (iii) Such other relevant factors as the authorized officer may deem appropriate; and Provided further, That in a situation where an estimated value is used, the authorized officer shall require the payment of such additional royalties, or allow such credits or refunds as may be necessary to adjust royalty payment to reflect the actual gross value.

(b) The lessee is required to certify that the values reported for royalty purposes are bona fide sales not involving considerations other than the sale of the mineral, and he may be required by the authorized officer to supply supporting information.

[43 FR 10341, Mar. 13, 1978. Redesignated at 48 FR 36588, Aug. 12, 1983, and amended at 48 FR 44795, Sept. 30, 1983. Further redesignated at 51 FR 15212, Apr. 22, 1986. Redesignated at 53 FR 39461, Oct. 7, 1988]

§ 1206.350 What is the purpose of this subpart?

(a) This subpart applies to all geothermal resources produced from Federal geothermal leases issued pursuant to the Geothermal Steam Act of 1970 (GSA), as amended by the Energy Policy Act of 2005 (EPAct) (30 U.S.C. 1001 et seq.). The purpose of this subpart is to prescribe how to calculate royalties and direct use fees for geothermal production.

(b) ONRR may audit and order you to adjust all royalty and fee payments. ONRR or an authorized State may require you to provide records for the audit by one or more of the methods specified in 30 CFR 1217.10.

(c) In some cases, the regulations in this subpart may be inconsistent with a statute, settlement agreement, written agreement, or lease provision. If this happens, the statute, settlement agreement, written agreement, or lease provision will govern to the extent of the inconsistency. For purposes of this paragraph, the following definitions apply:

(1) “Settlement agreement” means a settlement agreement between the United States and a lessee resulting from administrative or judicial litigation.

(2) “Written agreement” means a written agreement between the lessee and the ONRR Director or Assistant Secretary, Policy, Management and Budget of the Department of the Interior that:

(i) Establishes a method to determine the royalty from any lease that ONRR expects at least would approximate the value or royalty established under this subpart; and

(ii) Includes a value or gross proceeds determination under § 1206.364 of this subpart.

[72 FR 24459, May 2, 2007, as amended at 88 FR 53792, Aug. 9, 2023]

§ 1206.351 What definitions apply to this subpart?

For purposes of this subpart, the following terms have the meanings indicated.

Affiliate means a person who controls, is controlled by, or is under common control with another person. For purposes of this subpart:

(1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10 percent constitutes a presumption of noncontrol that ONRR may rebut.

(2) If there is ownership or common ownership of 10 through 50 percent of the voting securities, or instruments of ownership, or other forms of ownership of another person, ONRR will consider the following factors in determining whether there is control under the circumstances of a particular case:

(i) The extent to which there are common officers or directors;

(ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership: the percentage of ownership or common ownership, the relative percentage of ownership or common ownership compared to the percentage(s) of ownership by other persons, whether a person is the greatest single owner, or whether there is an opposing voting bloc of greater ownership;

(iii) Operation of a lease, plant, pipeline, or other facility;

(iv) The extent of participation by other owners in operations and day-to-day management of a lease, plant, pipeline, or other facility; and

(v) Other evidence of power to exercise control over or common control with another person.

(3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or marriage, are affiliates.

Allowance means a deduction in determining value for royalty purposes.

Arm's-length contract means a contract or agreement between independent persons who are not affiliates and who have opposing economic interests regarding that contract. To be considered arm's length for any production month, a contract must satisfy this definition for that month, as well as when the contract was executed.

Audit means a review, conducted in accordance with generally accepted accounting and auditing standards, of royalty or fee payment compliance activities of lessees or other interest holders who pay royalties, fees, rents, or bonuses on Federal geothermal leases.

Byproducts means minerals (exclusive of oil, hydrocarbon gas, and helium), found in solution or in association with geothermal steam, that no person would extract and produce by themselves because they are worth less than 75 percent of the value of the geothermal steam or because extraction and production would be too difficult.

Byproduct recovery facility means a facility where byproducts are placed in marketable condition.

Byproduct transportation allowance means an allowance for the reasonable, actual costs of moving byproducts to a point of sale or delivery off the lease, unit area, or communitized area, or away from a byproduct recovery facility. The byproduct transportation allowance does not include gathering costs. You must report a byproduct transportation allowance as a separate discrete field on the Form ONRR-2014.

Class I lease means:

(1) A lease that BLM issued before August 8, 2005, for which the lessee has not converted the royalty rate terms under 43 CFR 3212.25; or

(2) A lease that BLM issued in response to an application that was pending on August 8, 2005, for which the lessee has not made an election under 43 CFR 3200.8(b).

Class II lease means:

A lease that BLM issued after August 8, 2005, except for a lease issued in response to an application that was pending on August 8, 2005, for which the lessee does not make an election under 43 CFR 3200.8(b).

Class III lease means:

A lease that BLM issued before August 8, 2005, for which the lessee has converted to the royalty rate or direct use fee terms under 43 CFR 3212.25.

Commercial production or generation of electricity means generation of electricity that is sold or is subject to sale, including the electricity or energy that is reasonably required to produce the resource used in production of electricity for sale or to convert geothermal energy into electrical energy for sale.

Contract means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.

Deduction means a subtraction the lessee uses to determine the value of geothermal resources produced from a Class I lease that the lessee uses to generate electricity.

Delivered electricity means the amount of electricity in kilowatt-hours delivered to the purchaser.

Direct use means the utilization of geothermal resources for commercial, residential, agricultural, public facilities, or other energy needs, other than the commercial production or generation of electricity.

Direct use facility means a facility that uses the heat or other energy of the geothermal resource for direct use purposes.

Electrical facility means a power plant or other facility that uses a geothermal resource to generate electricity.

Field means the land surface vertically projected over a subsurface geothermal reservoir encompassing at least the outermost boundaries of all geothermal accumulations known to be within that reservoir. Geothermal fields are usually given names and their official boundaries are often designated by regulatory agencies in the respective States in which the fields are located.

Gathering means the movement of lease production from the wellhead to the point of utilization.

Generating deduction means a deduction for the lessee's reasonable, actual costs of generating plant tailgate electricity.

Geothermal resources means:

(1) All products of geothermal processes, including indigenous steam, hot water, and hot brines;

(2) Steam and other gases, hot water, and hot brines resulting from water, gas, or other fluids artificially introduced into geothermal formations;

(3) Heat or other associated energy found in geothermal formations; and

(4) Any byproducts.

Gross proceeds (for royalty payment purposes) means the total monies and other consideration accruing to a geothermal lessee for the sale of electricity or geothermal resource. Gross proceeds includes, but is not limited to:

(1) Payments to the lessee for certain services such as effluent injection, field operation and maintenance, drilling or workover of wells, or field gathering to the extent that the lessee is obligated to perform such functions at no cost to the Federal Government;

(2) Reimbursements for production taxes and other taxes. Tax reimbursements are part of gross proceeds accruing to a lessee even though the Federal royalty interest may be exempt from taxation; and

(3) Any monies and other consideration, including the forms of consideration identified in this paragraph, to which a lessee is contractually or legally entitled but which it does not seek to collect through reasonable efforts.

Lease means a geothermal lease issued under the authority of the GSA, unless the context indicates otherwise.

Lessee (you) means any person to whom the United States issues a geothermal lease, and any person who has been assigned an obligation to make royalty, fee, or other payments required by the lease. This includes any person who has an interest in a geothermal lease as well as an operator or payor who has no interest in the lease but who has assumed the royalty, fee, or other payment responsibility. This also includes any affiliate of the lessee that uses the geothermal resource to generate electricity, in a direct use process, or to recover byproducts, or any affiliate that sells or transports lease production.

Marketable condition means lease products that are sufficiently free from impurities and otherwise in a condition that they will be accepted by a purchaser under a sales contract typical for the disposition from the field or area of such lease products.

Person means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity).

Plant parasitic electricity means electricity used to operate a power plant that is used for commercial production or generation of electricity.

Plant tailgate electricity means the amount of electricity in kilowatt-hours generated by a power plant exclusive of plant parasitic electricity, but inclusive of any electricity generated by the power plant and returned to the lease for lease operations. Plant tailgate electricity should be measured at, or calculated for, the high voltage side of the transformer in the plant switchyard.

Point of utilization means the power plant or direct use facility in which the geothermal resource is utilized.

Public purpose means a program carried out by a State, tribal, or local government for the purpose of providing facilities or services for the benefit of the public in connection with, but not limited to, public health, safety or welfare, other than the commercial generation of electricity. Use of lands or facilities for habitation, cultivation, trade or manufacturing is permissible only when necessary for and integral to (i.e., an essential part of) the public purpose.

Public safety or welfare means a program carried out or promoted by a public agency for public purposes involving, directly or indirectly, protection, safety, and law enforcement activities, and the criminal justice system of a given political area. Public safety or welfare may include, but is not limited to, programs carried out by:

(1) Public police departments;

(2) Sheriffs' offices;

(3) The courts;

(4) Penal and correctional institutions (including juvenile facilities);

(5) State and local civil defense organizations; and

(6) Fire departments and rescue squads (including volunteer fire departments and rescue squads supported in whole or in part with public funds).

Reasonable alternative fuel means a conventional fuel (such as coal, oil, gas, or wood) that would normally be used as a source of heat in direct use operations.

Secretary means the Secretary of the Interior or any person duly authorized to exercise the powers vested in that office.

Transmission deduction means a deduction for the lessee's reasonable actual costs incurred to wheel or transmit the electricity from the lessee's power plant to the purchaser's delivery point.

Wheeling means the transmission of electricity from a power plant to the point of delivery.

§ 1206.352 How do I calculate the royalty due on geothermal resources used for commercial production or generation of electricity?

(a) If you sold geothermal resources produced from a Class I, II, or III lease at arm's length that the purchaser uses to generate electricity, then the royalty on the geothermal resources is the gross proceeds accruing to you from the sale of the geothermal resource to the arm's-length purchaser multiplied by either:

(1) The royalty rate in your lease; or

(2) The royalty rate that BLM prescribes or calculates under 43 CFR 3211.17. See § 1206.361 for additional provisions applicable to determining gross proceeds under arm's-length sales.

(b) If you use the geothermal resource in your own power plant for the generation and sale of electricity, the following provisions apply

(1) For Class I leases, you must determine the royalty on produced geothermal resources in accordance with the first applicable of the following paragraphs:

(i) The gross proceeds accruing to you from the arm's-length sale of the electricity less applicable deductions determined under §§ 1206.353 and 1206.354 of this part, multiplied by the royalty rate in your lease. See § 1206.361 for additional provisions applicable to determining gross proceeds under arm's-length sales. Under no circumstances may the deductions reduce the royalty value of the geothermal resource to zero; or

(ii) A royalty determined by any other reasonable method approved by ONRR under § 1206.364 of this subpart.

(2) For Class II and Class III leases, the royalty on geothermal resources produced is your gross proceeds from the sale of electricity multiplied by the royalty rate BLM prescribed for your lease under 43 CFR 3211.17. See § 1206.361 for additional provisions applicable to determining gross proceeds under arm's-length sales. You may not reduce gross proceeds by any deductions.

§ 1206.353 How do I determine transmission deductions?

(a) If you determine the value of your geothermal resources under § 1206.352(b)(1)(i) of this subpart, you may subtract a transmission deduction from the gross proceeds you received for the sale of electricity to determine the plant tailgate value of the electricity.

(1) The transmission deduction consists of either or both of two components:

(i) Transmission line costs as determined under paragraph (b) of this section; and

(ii) Wheeling costs if the electricity is transmitted across a third party's transmission line under an arm's-length wheeling agreement.

(2) You may deduct the actual costs you (including your affiliate(s)) incur for transmitting electricity under your arm's-length wheeling contract.

(b) To determine your transmission line cost, you must follow the requirements of paragraphs (b)(1) and (b)(2) of this section.

(1) Your transmission line costs are your actual costs associated with the construction and operation of a transmission line for the purpose of transmitting electricity attributable and allocable to your power plant utilizing Federal geothermal resources.

(i) You must determine the monthly transmission line cost component of the transmission deduction by multiplying the annual transmission line cost rate (in dollars per kilowatt-hour) by the amount of electricity delivered for the reporting month.

(ii) You must redetermine the transmission line cost rate annually either at the beginning of the same month of the year in which the power plant was placed into service or at a time concurrent with the beginning of your annual corporate accounting period. The period you select must coincide with the same period you chose for the generating deduction under § 1206.354(b)(1). After you choose a deduction period, you may not later elect to use a different deduction period without ONRR approval.

(2) Your actual transmission line costs during the reporting period include:

(i) Operating and maintenance expenses under paragraphs (d) and (e) of this section;

(ii) Overhead under paragraph (f) of this section; and either

(iii) Depreciation under paragraphs (g) and (h) of this section and a return on undepreciated capital investment under paragraphs (g) and (i) of this section or

(iv) A return on the capital investment in the transmission line under paragraphs (g) and (j) of this section.

(c)(1) Allowable capital costs under paragraph (b) of this section are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the transmission line.

(2)(i) You may include a return on capital you invested in the purchase of real estate for transmission facilities if:

(A) Such purchase is necessary; and

(B) The surface is not part of the Federal lease.

(ii) The rate of return will be the same rate determined under paragraph (k) of this section.

(d) Allowable operating expenses include:

(1) Operations supervision and engineering;

(2) Operations labor;

(3) Fuel;

(4) Utilities;

(5) Materials;

(6) Ad valorem property taxes;

(7) Rent;

(8) Supplies; and

(9) Any other directly allocable and attributable operating or maintenance expense that you can document.

(e) Allowable maintenance expenses include:

(1) Maintenance of the transmission line;

(2) Maintenance of equipment;

(3) Maintenance labor; and

(4) Other directly allocable and attributable maintenance expenses that you can document.

(f) Overhead directly attributable and allocable to the operation and maintenance of the transmission line is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.

(g) To compute costs associated with capital investment, a lessee may use either depreciation with a return on undepreciated capital investment, or a return on capital investment in the transmission line. After a lessee has elected to use either method, the lessee may not later elect to change to the other alternative without ONRR approval.

(h)(1) To compute depreciation, you must use a straight-line depreciation method based on the life of the geothermal project, usually the term of the electricity sales contract, or other depreciation period acceptable to ONRR. You may not depreciate equipment below a reasonable salvage value.

(2) A change in ownership of a transmission line does not alter the depreciation schedule established by the original lessee-owner for purposes of computing transmission line costs.

(3) With or without a change in ownership, you may depreciate a transmission line only once.

(i) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated capital balance as of the beginning of the period for which you are calculating the transmission deduction by the rate of return provided in paragraph (k) of this section.

(j) To compute a return on capital investment in the transmission line, multiply the allowable capital investment in the transmission line by the rate of return determined pursuant to paragraph (k) of this section. There is no allowance for depreciation.

(k) The rate of return must be 2.0 multiplied by the industrial rate associated with Standard & Poor's BBB rating. The BBB rate must be the monthly average rate as published in Standard & Poor's Bond Guide for the first month for which the allowance is applicable. Redetermine the rate at the beginning of each subsequent calendar year.

(l) Calculate the deduction for transmission costs based on your cost of transmitting electricity through each individual transmission line.

(m)(1) For new transmission facilities or arrangements, base your initial deduction on estimates of allowable electricity transmission costs for the applicable period. Use the most recently available operations data for the transmission line or, if such data are not available, use estimates based on data for similar transmission lines.

(2) When actual cost information is available, you must amend your prior Form ONRR-2014 reports to reflect actual transmission costs deductions for each month for which you reported and paid based on estimated transmission costs. You must pay any additional royalties due (together with interest computed under § 1218.302 of this chapter). You are entitled to a credit for or refund of any overpaid royalties.

(n) In conducting reviews and audits, ONRR may require you to submit arm's-length transmission contracts, production agreements, operating agreements, and related documents and all other data used to calculate the deduction. You must comply with any such requirements within the time ONRR specifies. Recordkeeping requirements are found at part 1212 of this chapter.

(o) At the completion of transmission line dismantlement and salvage operations, you may report a credit for or request a refund of royalties in an amount equal to the royalty rate times the amount by which actual transmission line dismantlement costs exceed actual income attributable to salvage of the transmission line.

§ 1206.354 How do I determine generating deductions?

(a) If you determine the value of your geothermal resources under § 1206.352(b)(1)(i) of this subpart, you may deduct your reasonable actual costs incurred to generate electricity from the plant tailgate value of the electricity (usually the transmission-reduced value of the delivered electricity). You may deduct the actual costs you incur for generating electricity under your arm's-length power plant contract.

(b)(1) You must base your generating costs deduction on your actual annual costs associated with the construction and operation of a geothermal power plant.

(i) You must determine your monthly generating deduction by multiplying the annual generating cost rate (in dollars per kilowatt-hour) by the amount of plant tailgate electricity measured (or computed) for the reporting month. The generating cost rate is determined from the annual amount of your plant tailgate electricity.

(ii) You must redetermine your generating cost rate annually either at the beginning of the same month of the year in which the power plant was placed into service or at a time concurrent with the beginning of your annual corporate accounting period. The period you select must coincide with the same period chosen for the transmission deduction under § 1206.353(b)(1). After you choose a deduction period, you may not later elect to use a different deduction period without ONRR approval.

(2) Your generating costs are your actual power plant costs during the reporting period, including:

(i) Operating and maintenance expenses under paragraphs (d) and (e) of this section;

(ii) Overhead under paragraph (f) of this section; and either

(iii) Depreciation under paragraphs (g) and (h) of this section and a return on undepreciated capital investment under paragraphs (g) and (i) of this section; or

(iv) A return on capital investment in the power plant under paragraphs (g) and (j) of this section.

(c)(1) Allowable capital costs under paragraph (b) of this section are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the power plant or are required by the design specifications of the power conversion cycle.

(2)(i) You may include a return on capital you invested in the purchase of real estate for a power plant site if:

(A) The purchase is necessary; and,

(B) The surface is not part of the Federal lease.

(ii) The rate of return will be the same rate determined under paragraph (k) of this section.

(3) You may not deduct the costs of gathering systems and other production-related facilities.

(d) Allowable operating expenses include:

(1) Operations supervision and engineering;

(2) Operations labor;

(3) Auxiliary fuel and/or utilities used to operate the power plant during down time;

(4) Utilities;

(5) Materials;

(6) Ad valorem property taxes;

(7) Rent;

(8) Supplies; and

(9) Any other directly allocable and attributable operating expense.

(e) Allowable maintenance expenses include:

(1) Maintenance of the power plant;

(2) Maintenance of equipment;

(3) Maintenance labor; and

(4) Other directly allocable and attributable maintenance expenses that you can document.

(f) Overhead directly attributable and allocable to the operation and maintenance of the power plant is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.

(g) To compute costs associated with capital investment, a lessee may use either depreciation with a return on undepreciated capital investment, or a return on capital investment in the power plant. After a lessee has elected to use either method, the lessee may not later elect to change to the other alternative without ONRR approval.

(h)(1) To compute depreciation, you must use a straight-line depreciation method based on the life of the geothermal project, usually the term of the electricity sales contract, or other depreciation period acceptable to ONRR. You may not depreciate equipment below a reasonable salvage value.

(2) A change in ownership of the power plant does not alter the depreciation schedule established by the original lessee-owner for purposes of computing generating costs.

(3) With or without a change in ownership, you may depreciate a power plant only once.

(i) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated capital balance as of the beginning of the period for which you are calculating the generating deduction allowance by the rate of return provided in paragraph (k) of this section.

(j) To compute a return on capital investment in the power plant, multiply the allowable capital investment in the power plant by the rate of return determined pursuant to paragraph (k) of this section. There is no allowance for depreciation.

(k) The rate of return must be 2.0 multiplied by the industrial rate associated with Standard & Poor's BBB rating. The BBB rate must be the monthly average rate as published in Standard & Poor's Bond Guide for the first month for which the allowance is applicable. You must redetermine the rate at the beginning of each subsequent calendar year.

(l) Calculate the deduction for generating costs based on your cost of generating electricity through each individual power plant.

(m)(1) For new power plants or arrangements, base your initial deduction on estimates of allowable electricity generation costs for the applicable period. Use the most recently available operations data for the power plant or, if such data are not available, use estimates based on data for similar power plants.

(2) When actual cost information is available, you must amend your prior Form ONRR-2014 reports to reflect actual generating cost deductions for each month for which you reported and paid based on estimated generating costs. You must pay any additional royalties due (together with interest computed under § 1218.302 of this chapter). You are entitled to a credit for or refund of any overpaid royalties.

(n) In conducting reviews and audits, ONRR may require you to submit arm's-length power plant contracts, production agreements, operating agreements, related documents and all other data used to calculate the deduction. You must comply with any such requirements within the time ONRR specifies. Recordkeeping requirements are found at part 1212 of this chapter.

(o) At the completion of power plant dismantlement and salvage operations, you may report a credit for or request a refund of royalty in an amount equal to the royalty rate times the amount by which actual power plant dismantlement costs exceed actual income attributable to salvage of the power plant.

§ 1206.355 How do I calculate royalty due on geothermal resources I sell at arm's length to a purchaser for direct use?

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

§ 1206.356 How do I calculate royalty or fees due on geothermal resources I use for direct use purposes?

If you use the geothermal resource for direct use:

(a) For Class I leases, you must determine the royalty due on geothermal resources in accordance with the first applicable of the following three paragraphs.

(1) The weighted average of the gross proceeds established in arm's-length contracts for the purchase of significant quantities of geothermal resources to operate the lessee's same direct-use facility multiplied by the royalty rate in your lease. In evaluating the acceptability of arm's-length contracts, the following factors will be considered: time of execution, duration, terms, volume, quality of resource, and such other factors as may be appropriate to reflect the value of the resource.

(2) The equivalent value of the least expensive, reasonable alternative energy source (fuel) multiplied by the royalty rate in your lease. The equivalent value of the least expensive, reasonable alternative energy source will be based on the amount of thermal energy that would otherwise be used by the direct use facility in place of the geothermal resource. That amount of thermal energy (in Btu) displaced by the geothermal resource will be determined by the equation:

Where hin is the enthalpy in Btu/lb at the direct use facility inlet (based on measured inlet temperature), hout is the enthalpy in Btu/lb at the facility outlet (based on measured outlet temperature), density is in lbs/cu ft based on inlet temperature, the factor 0.133681 (cu ft/gal) converts gallons to cubic feet, and volume is the quantity of geothermal fluid in gallons produced at the wellhead or measured at an approved point. The efficiency factor of the alternative energy source will be 0.7 for coal and 0.8 for oil, natural gas, and other fuels derived from oil and natural gas, or an efficiency factor proposed by the lessee and approved by ONRR. The methods of measuring resource parameters (temperature, volume, etc.) and the frequency of computing and accumulating the amount of thermal energy displaced will be determined and approved by BLM under 43 CFR 3275.13-3275.17.

(3) A royalty determined by any other reasonable method approved by ONRR or the Assistant Secretary, Policy, Management and Budget of the Department of the Interior, under § 1206.364 of this part.

(b) For geothermal resources produced from Class II and Class III leases, you must multiply the appropriate fee from the schedule in subparagraph (b)(1) of this section by the number of gallons or pounds you produce from the direct use lease each month.

(1) You must use the following fee schedule to calculate fees due under this section:

Direct Use Fee Schedule

[Hot water]

If your average monthly inlet temperature (°F) is | Your fees are . . .

At least . . . | But less than . . . | ($/million gallons) | ($/million pounds)

130 | 140 | 2.524 | 0.307

140 | 150 | 7.549 | 0.921

150 | 160 | 12.543 | 1.536

160 | 170 | 17.503 | 2.150

170 | 180 | 22.426 | 2.764

180 | 190 | 27.310 | 3.379

190 | 200 | 32.153 | 3.993

200 | 210 | 36.955 | 4.607

210 | 220 | 41.710 | 5.221

220 | 230 | 46.417 | 5.836

230 | 240 | 51.075 | 6.450

240 | 250 | 55.682 | 7.064

250 | 260 | 60.236 | 7.679

260 | 270 | 64.736 | 8.293

270 | 280 | 69.176 | 8.907

280 | 290 | 73.558 | 9.521

290 | 300 | 77.876 | 10.136

300 | 310 | 82.133 | 10.750

310 | 320 | 86.328 | 11.364

320 | 330 | 90.445 | 11.979

330 | 340 | 94.501 | 12.593

340 | 350 | 98.481 | 13.207

350 | 360 | 102.387 | 13.821

(i) For direct use geothermal resources with an average monthly inlet temperature of 130 °F or less, you must pay only the lease rental.

(ii) The ONRR, in consultation with BLM, will develop and publish a revised fee schedule in the Federal Register, as needed.

(iii) ONRR, in consultation with BLM, will calculate revised fees schedules using the following formulas:

Where: RV = Royalty due as a function of produced volume in the fee schedule, expressed as dollars per million (10 6) gallons; Rm = Royalty due as a function of produced mass in the fee schedule, expressed as dollars per million (10 6) pounds; ρ[rho] = Water density at inlet temperature expressed as lbs per gallon; Tin = Measured inlet temperature in °F (as required by BLM under 43 CFR part 3275); Tout = Established assumed outlet temperature of 130 °F; e = Boiler Efficiency Factor for coal of 70 percent; Pprbc = The 3-year historical average of Powder River Basin spot coal prices, as published by the Energy Information Administration, or other recognized authoritative reference source of coal prices, in dollars (per MMBtu); Frr = The assumed Lease Royalty Rate of 10 percent.

(2) The fee that you report is subject to monitoring, review, and audit.

(3) The schedule of fees established under this paragraph will apply to any Class III lease with respect to any royalty payments previously made when the lease was a Class I lease that were due and owing, and were paid, on or after July 16, 2003. To use this provision, you must provide ONRR data showing the amount of geothermal production in pounds or gallons of geothermal fluid to input into the fee schedule (see 43 CFR part 3276).

(i) If the royalties you previously paid are less than the fees due under this section, you must pay the difference plus interest on that difference computed under § 1218.302 of this chapter.

(ii) If the royalties you previously paid are more than the fees due under this section, then you are entitled to a refund or credit from ONRR of 50 percent of the overpaid royalties. You are also entitled to a refund or credit of any interest that you paid on the overpaid royalties.

(c) For geothermal resources other than hot water, ONRR will determine fees on a case-by-case basis.

[72 FR 24459, May 2, 2007, as amended at 76 FR 76615, Dec. 8, 2011; 88 FR 57882, Aug. 24, 2023]

§ 1206.357 How do I calculate royalty due on byproducts?

(a) If you sell byproducts, you must determine the royalty due on the byproducts that are royalty-bearing under:

(1) Applicable lease terms of Class I leases and of Class III leases that do not elect to be subject to all of the BLM regulations promulgated for leases issued after August 8, 2005, under 43 CFR 3200.7(a)(2), or

(2) Applicable statutory provisions at 30 U.S.C. 1004(a)(2) for Class II leases and for Class III leases that do elect to be subject to all of the BLM regulations promulgated for leases issued after August 8, 2005, under 43 CFR 3200.7(a)(2).

(b) You must determine the royalty due on the byproducts by multiplying the royalty rate in your lease or that BLM prescribes under 43 CFR 3211.19 by a value of the byproducts determined in accordance with the first applicable of the following subparagraphs:

(1) The gross proceeds accruing to you from the arm's-length sale of the byproducts, less any applicable byproduct transportation allowances determined under §§ 1206.358 and 1206.359. See § 1206.361 for additional provisions applicable to determining gross proceeds;

(2) Other relevant matters including, but not limited to, published or publicly available spot-market prices, or information submitted by the lessee concerning circumstances unique to a particular lease operation or the saleability of certain byproducts; or

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

§ 1206.358 What are byproduct transportation allowances?

(a) When you determine the value of byproducts at a point off the geothermal lease, unit, or participating area, you are allowed a deduction in determining value, for royalty purposes, for your reasonable, actual costs incurred to:

(1) Transport the byproducts from a Federal lease, unit, or participating area to a sales point or point of delivery that is off the lease, unit, or participating area; or

(2) Transport the byproducts from a Federal lease, unit, or participating area, or from a geothermal use facility to a byproduct recovery facility when that byproduct recovery facility is off the lease, unit, or participating area and, if applicable, from the recovery facility to a sales point or point of delivery off the lease, unit, or participating area.

(b) Costs for transporting geothermal fluids from the lease to the geothermal use facility, whether on or off the lease, are not includible in the byproduct transportation allowance.

(c)(1) When you transport byproducts from a lease, unit, participating area, or geothermal use facility to a byproduct recovery facility, you are not required to allocate transportation costs between the quantity of marketable byproducts and the rejected waste material. The byproduct transportation allowance is authorized for the total production that is transported. You must express byproduct transportation allowances as a cost per unit of marketable byproducts transported.

(2) For byproducts that are extracted on the lease, unit, participating area, or at the geothermal use facility, the byproduct transportation allowance is authorized for the total byproduct that is transported to a point of sale off the lease, unit, or participating area. You must express byproduct transportation allowances as a cost per unit of byproduct transported.

(3) You may deduct transportation costs only when you sell, deliver, or otherwise utilize the transported byproduct and report and pay royalties on the byproduct.

(d) Reporting requirements. (1) You must use a discrete field on Form ONRR-2014 to notify ONRR of a transportation allowance.

(2) In conducting reviews and audits, ONRR may require you to submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. You must comply with any such requirements within the time ONRR specifies. Recordkeeping requirements are found at part 1212 of this chapter.

(e) Byproduct transportation allowances are subject to monitoring, review, and audit. If, after a review or audit, ONRR determines that you have improperly determined a byproduct transportation allowance, you must pay any additional royalties due (plus interest computed under § 1218.302 of this chapter). You are entitled to a credit for or refund of any overpaid royalties.

(f) If you commingled byproducts produced from Federal and non-Federal leases for transportation, you may not disproportionately allocate transportation costs to Federal lease production.

§ 1206.359 How do I determine byproduct transportation allowances?

(a) For transportation costs you incur under an arm's-length contract, the transportation allowance will be the reasonable, actual costs you incurred for transporting the byproducts under that contract.

(1) In conducting reviews and audits, ONRR will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from you to the transporter for the transportation. If the contract reflects more than the total consideration you paid, ONRR may require you to determine the byproduct transportation allowance under paragraph (b) of this section.

(2) If ONRR determines that the consideration you paid under an arm's-length byproduct transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, ONRR will require you to determine the byproduct transportation allowance under paragraph (b) of this section. When ONRR determines that the value of the transportation may be unreasonable, ONRR will notify you and give you an opportunity to provide written information justifying your transportation costs.

(3) Where your payments for transportation under an arm's-length contract are not established on a dollars-per-unit basis, you must convert whatever consideration you paid to a dollar value equivalent for the purposes of this section.

(b) If you transport the byproduct yourself or under a non-arm's-length transportation arrangement, the byproduct transportation allowance is your reasonable actual costs for transportation during the reporting period, including:

(1) Operating and maintenance expenses under paragraphs (d) and (e) of this section;

(2) Overhead under paragraph (f) of this section; and either

(3) Depreciation under paragraphs (g) and (h) of this section and a return on undepreciated capital investment under paragraphs (g) and (i) of this section; or

(4) A return on capital investment in the transportation system under paragraphs (g) and (j) of this section.

(c)(1) Allowable capital costs under paragraph (b) of this section are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the transportation system.

(2)(i) You may include a return on capital you invested in the purchase of real estate to locate the byproduct transportation facilities if:

(A) The purchase is necessary; and

(B) The surface is not part of a Federal lease.

(ii) The rate of return will be the same rate determined in paragraph (k) of this section.

(3) You may not deduct the costs of gathering systems and other production-related facilities.

(d) Allowable operating expenses include:

(1) Operations supervision and engineering;

(2) Operations labor;

(3) Fuel;

(4) Utilities;

(5) Materials;

(6) Ad valorem property taxes;

(7) Rent;

(8) Supplies; and

(9) Any other directly allocable and attributable operating expense that you can document.

(e) Allowable maintenance expenses include:

(1) Maintenance of the transportation system;

(2) Maintenance of equipment;

(3) Maintenance labor; and

(4) Other directly allocable and attributable maintenance expenses that you can document.

(f) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.

(g) To compute costs associated with capital investment, a lessee may use either paragraphs (h) and (i) or paragraph (j) of this section. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without ONRR approval.

(h)(1) To compute depreciation, you must use a straight-line depreciation method based on either the life of the equipment or the life of the geothermal project which the transportation system services. After you choose the basis for depreciation, you may not change that basis without ONRR approval. You may not depreciate equipment below a reasonable salvage value.

(2) A change in ownership of a transportation system does not alter the depreciation schedule established by the original lessee-owner for purposes of computing transportation costs.

(3) With or without a change in ownership, you may depreciate a transportation system only once.

(i) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated capital balance as of the beginning of the period for which you are calculating the transportation allowance by the rate of return provided in paragraph (k) of this section.

(j) To compute a return on capital investment in the transportation system, the allowed cost will be the amount equal to the allowable capital investment in the transportation system multiplied by the rate of return determined pursuant to paragraph (k) of this section. There is no allowance for depreciation.

(k) The rate of return must be the industrial rate associated with Standard & Poor's BBB rating. The BBB rate must be the monthly average rate as published in Standard & Poor's Bond Guide for the first month for which the allowance is applicable. You must redetermine the rate at the beginning of each subsequent calendar year.

(l)(1) For new transportation facilities or arrangements, base your initial deduction on estimates of allowable byproduct transportation costs for the applicable period. Use the most recently available operations data for the transportation system or, if such data are not available, use estimates based on data for similar transportation systems.

(2) When actual cost information is available, you must amend your prior Form ONRR-2014 reports to reflect actual byproduct transportation cost deductions for each month for which you reported and paid based on estimated byproduct transportation costs. You must pay any additional royalties due (together with interest computed under § 1218.302 of this chapter). You are entitled to a credit for or a refund of any overpaid royalties.

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

If you determine royalties or direct use fees for your geothermal resource under this subpart, you must retain all data relevant to the determination of the royalty value or the fee you paid. Recordkeeping requirements are found at part 1212 of this chapter.

(a) You must be able to show:

(1) How you calculated the royalty value or fee you reported, including all allowable deductions; and

(2) How you complied with this subpart.

(b) Upon request, you must submit all data to ONRR. You must comply with any such requirement within the time ONRR specifies.

§ 1206.361 How will ONRR determine whether my royalty or direct use fee payments are correct?

(a)(1) The royalties or direct use fees that you report are subject to monitoring, review, and audit. The ONRR may review and audit your data, and ONRR will direct you to use a different measure of royalty value, gross proceeds, or fee, whichever is applicable, if it determines that the reported value, gross proceeds, or fee is inconsistent with the requirements of this subpart.

(2) If ONRR directs you to use a different royalty value, measure of gross proceeds, or fee, you must either pay any royalties or fees due (together with interest computed under § 1218.302 of this chapter) or report a credit for or request a refund of any overpaid royalties or fees.

(b) When the provisions in this subpart refer to gross proceeds either for the sale of electricity or the sale of a geothermal resource, in conducting reviews and audits ONRR will examine whether your sales contract reflects the total consideration actually transferred, either directly or indirectly, from the buyer to you for the geothermal resource or electricity. If ONRR determines that a contract does not reflect the total consideration, or the gross proceeds accruing to you under a contract do not reflect reasonable consideration because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, ONRR may require you to increase the gross proceeds to reflect any additional consideration. Alternatively, for Class I leases, ONRR may require you to use another valuation method in the regulations applicable to dispositions other than under an arm's-length contract. ONRR will notify you to give you an opportunity to provide written information justifying your gross proceeds.

(c) For arm's-length sales, you have the burden of demonstrating that your contract is arm's length.

(d) ONRR may require you to certify that the provisions in your sales contract include all of the consideration the buyer paid you, either directly or indirectly, for the electricity or geothermal resource.

(e) Notwithstanding any other provision of this subpart, under no circumstances will the value of production for royalty purposes under a Class I lease where the geothermal resources are sold before use be less than the gross proceeds accruing to you.

(f) Gross proceeds for the sale of electricity or for the sale of the geothermal resource will be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract.

(1) Absent contract revision or amendment, if you fail to take proper or timely action to receive prices or benefits to which you are entitled, you must pay royalty based upon that obtainable price or benefit.

(2) Contract revisions or amendments you make must be in writing and signed by all parties to the contract.

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

§ 1206.362 What are my responsibilities to place production into marketable condition and to market production?

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

§ 1206.363 When is an ONRR audit, review, reconciliation, monitoring, or other like process considered final?

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

§ 1206.364 How do I request a value or gross proceeds determination?

(a) You may request a value determination from ONRR regarding any geothermal resources produced from a Class I lease or for byproducts produced from a Class I, Class II, or Class III lease. You may also request a gross proceeds determination for a Class II or Class III lease. Your request must:

(1) Be in writing;

(2) Identify specifically all leases involved, all owners of interests in those leases, and the operator(s) for those leases;

(3) Completely explain all relevant facts. You must inform ONRR of any changes to relevant facts that occur before we respond to your request;

(4) Include copies of all relevant documents;

(5) Provide your analysis of the issue(s), including citations to all relevant precedents (including adverse precedents); and

(6) Suggest your proposed gross proceeds calculation or valuation method.

(b) In response to your request:

(1) The Assistant Secretary, Policy, Management and Budget, may issue a determination; or

(2) ONRR may issue a determination; or

(3) ONRR may inform you in writing that ONRR will not provide a determination. Situations in which ONRR typically will not provide any determination include, but are not limited to:

(i) Requests for guidance on hypothetical situations; and

(ii) Matters that are the subject of pending litigation or administrative appeals.

(c)(1) A determination signed by the Assistant Secretary, Policy, Management and Budget, is binding on both you and ONRR until the Assistant Secretary modifies or rescinds it.

(2) After the Assistant Secretary issues a determination, you must make any adjustments in royalty payments that follow from the determination and, if you owe additional royalties, pay the royalties owed together with late payment interest computed under § 1218.302 of this chapter.

(3) A determination signed by the Assistant Secretary is the final action of the Department and is subject to judicial review under 5 U.S.C. 701-706.

(d) A determination issued by ONRR is binding on ONRR and delegated States, but not on you, with respect to the specific situation addressed in the determination unless ONRR (for ONRR-issued determinations) or the Assistant Secretary modifies or rescinds it.

(1) A determination by ONRR is not an appealable decision or order under 30 CFR part 1290.

(2) If you receive an order requiring you to pay royalty on the same basis as the determination, you may appeal that order under 30 CFR part 1290.

(e) In making a determination, ONRR or the Assistant Secretary may use any of the applicable criteria in this subpart.

(f) A change in an applicable statute or regulation on which any determination is based takes precedence over the determination after the effective date of the statute or regulation, regardless of whether ONRR or the Assistant Secretary modifies or rescinds the determination.

(g) ONRR or the Assistant Secretary generally will not retroactively modify or rescind a determination issued under paragraph (d) of this section, unless:

(1) There was a misstatement or omission of material facts; or

(2) The facts subsequently developed are materially different from the facts on which the guidance was based.

(h) ONRR may make requests and replies under this section available to the public, subject to the confidentiality requirements under § 1206.365.

[72 FR 24459, May 2, 2007, as amended at 78 FR 30204, May 22, 2013]

§ 1206.365 Does ONRR protect information I provide?

Certain information you submit to ONRR regarding royalties or fees on geothermal resources or byproducts, including deductions and allowances, may be exempt from disclosure. To the extent applicable laws and regulations permit, ONRR will keep confidential any data you submit that is privileged, confidential, or otherwise exempt from disclosure. All requests for information must be submitted under the Freedom of Information Act regulations of the Department of the Interior at 43 CFR part 2.

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

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

§ 1206.450 What is the purpose and scope of this subpart?

(a) This subpart prescribes the procedures to establish the value, for royalty purposes, of all coal from Indian Tribal and allotted leases (except leases on the Osage Indian Reservation, Osage County, Oklahoma).

(b) If the specific provisions of any statute, treaty, or settlement agreement between the Indian lessor and a lessee resulting from administrative or judicial litigation, or any coal lease subject to the requirements of this subpart, are inconsistent with any regulation in this subpart, then the statute, treaty, lease provision, or settlement shall govern to the extent of that inconsistency.

(c) ONRR may audit and order you to adjust all royalty payments. ONRR or an authorized Tribe may require you to provide records for the audit by one or more of the methods specified in 30 CFR 1217.10.

(d) The regulations in this subpart are intended to ensure that the trust responsibilities of the United States with respect to the administration of Indian coal leases are discharged in accordance with the requirements of the governing mineral leasing laws, treaties, and lease terms.

[88 FR 47012, July 21, 2023, as amended at 88 FR 53792, Aug. 9, 2023]

§ 1206.451 Definitions.

The definitions in § 1206.20 do not apply to this subpart. For purposes of this subpart:

Ad valorem lease means a lease where the royalty due to the lessor is based upon a percentage of the amount or value of the coal.

Allowance means an approved, or an ONRR-initially accepted deduction in determining value for royalty purposes. Coal washing allowance means an allowance for the reasonable, actual costs incurred by the lessee for coal washing, or an approved or ONRR-initially accepted deduction for the costs of washing coal, determined pursuant to this subpart. Transportation allowance means an allowance for the reasonable, actual costs incurred by the lessee for moving coal to a point of sale or point of delivery remote from both the lease and mine or wash plant, or an approved ONRR-initially accepted deduction for costs of such transportation, determined pursuant to this subpart.

Area means a geographic region in which coal has similar quality and economic characteristics. Area boundaries are not officially designated and the areas are not necessarily named.

Arm's-length contract means a contract or agreement that has been arrived at in the marketplace between independent, nonaffiliated persons with opposing economic interests regarding that contract. For purposes of this subpart, two persons are affiliated if one person controls, is controlled by, or is under common control with another person. For purposes of this subpart, based on the instruments of ownership of the voting securities of an entity, or based on other forms of ownership: ownership in excess of 50 percent constitutes control; ownership of 10 through 50 percent creates a presumption of control; and ownership of less than 10 percent creates a presumption of noncontrol which ONRR may rebut if it demonstrates actual or legal control, including the existence of interlocking directorates. Notwithstanding any other provisions of this subpart, contracts between relatives, either by blood or by marriage, are not arm's-length contracts. ONRR may require the lessee to certify ownership control. To be considered arm's-length for any production month, a contract must meet the requirements of this definition for that production month, as well as when the contract was executed.

Audit means a review, conducted in accordance with generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees or other interest holders who pay royalties, rents, or bonuses on Indian leases.

BIA means the Bureau of Indian Affairs of the Department of the Interior.

BLM means the Bureau of Land Management of the Department of the Interior.

Coal means coal of all ranks from lignite through anthracite.

Coal washing means any treatment to remove impurities from coal. Coal washing may include, but is not limited to, operations such as flotation, air, water, or heavy media separation; drying; and related handling (or combination thereof).

Contract means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.

Gross proceeds (for royalty payment purposes) means the total monies and other consideration accruing to a coal lessee for the production and disposition of the coal produced. Gross proceeds includes, but is not limited to, payments to the lessee for certain services such as crushing, sizing, screening, storing, mixing, loading, treatment with substances including chemicals or oils, and other preparation of the coal to the extent that the lessee is obligated to perform them at no cost to the Indian lessor. Gross proceeds, as applied to coal, also includes but is not limited to reimbursements for royalties, taxes or fees, and other reimbursements. Tax reimbursements are part of the gross proceeds accruing to a lessee even though the Indian royalty interest may be exempt from taxation. Monies and other consideration, including the forms of consideration identified in this paragraph, to which a lessee is contractually or legally entitled but which it does not seek to collect through reasonable efforts are also part of gross proceeds.

Indian allottee means any Indian for whom land or an interest in land is held in trust by the United States or who holds title subject to Federal restriction against alienation.

Indian Tribe means any Indian Tribe, band, nation, pueblo, community, rancheria, colony, or other group of Indians for which any land or interest in land is held in trust by the United States or which is subject to Federal restriction against alienation.

Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States for an Indian coal resource under a mineral leasing law that authorizes exploration for, development or extraction of, or removal of coal—or the land covered by that authorization, whichever is required by the context.

Lessee means any person to whom the Indian Tribe or an Indian allottee issues a lease, and any person who has been assigned an obligation to make royalty or other payments required by the lease. This includes any person who has an interest in a lease as well as an operator or payor who has no interest in the lease but who has assumed the royalty payment responsibility.

Like-quality coal means coal that has similar chemical and physical characteristics.

Marketable condition means coal that is sufficiently free from impurities and otherwise in a condition that it will be accepted by a purchaser under a sales contract typical for that area.

Mine means an underground or surface excavation or series of excavations and the surface or underground support facilities that contribute directly or indirectly to mining, production, preparation, and handling of lease products.

Net-back method means a method for calculating market value of coal at the lease or mine. Under this method, costs of transportation, washing, handling, etc., are deducted from the ultimate proceeds received for the coal at the first point at which reasonable values for the coal may be determined by a sale pursuant to an arm's-length contract or by comparison to other sales of coal, to ascertain value at the mine.

Net output means the quantity of washed coal that a washing plant produces.

ONRR means the Office of Natural Resources Revenue of the Department of the Interior.

Person means by individual, firm, corporation, association, partnership, consortium, or joint venture.

Sales type code means the contract type or general disposition (e.g., arm's-length or non-arm's-length) of production from the lease. The sales type code applies to the sales contract, or other disposition, and not to the arm's-length or non-arm's-length nature of a transportation or washing allowance.

Spot market price means the price received under any sales transaction when planned or actual deliveries span a short period of time, usually not exceeding one year.

§ 1206.452 Coal subject to royalties—general provisions.

(a) All coal (except coal unavoidably lost as determined by BLM pursuant to 43 CFR group 3400) from an Indian lease subject to this part is subject to royalty. This includes coal used, sold, or otherwise disposed of by the lessee on or off the lease.

(b) If a lessee receives compensation for unavoidably lost coal through insurance coverage or other arrangements, royalties at the rate specified in the lease are to be paid on the amount of compensation received for the coal. No royalty is due on insurance compensation received by the lessee for other losses.

(c) If waste piles or slurry ponds are reworked to recover coal, the lessee shall pay royalty at the rate specified in the lease at the time the recovered coal is used, sold, or otherwise finally disposed of. The royalty rate shall be that rate applicable to the production method used to initially mine coal in the waste pile or slurry pond; i.e., underground mining method or surface mining method. Coal in waste pits or slurry ponds initially mined from Indian leases shall be allocated to such leases regardless of whether it is stored on Indian lands. The lessee shall maintain accurate records to determine to which individual Indian lease coal in the waste pit or slurry pond should be allocated. However, nothing in this section requires payment of a royalty on coal for which a royalty has already been paid.

§ 1206.453 Quality and quantity measurement standards for reporting and paying royalties.

For all leases subject to this subpart, the quantity of coal on which royalty is due shall be measured in short tons (of 2,000 pounds each) by methods prescribed by the BLM. Coal quantity information will be reported on appropriate forms required under part 1210 of this subchapter.

§ 1206.454 Point of royalty determination.

(a) For all leases subject to this subpart, royalty shall be computed on the basis of the quantity and quality of Indian coal in marketable condition measured at the point of royalty measurement as determined jointly by BLM and ONRR.

(b) Coal produced and added to stockpiles or inventory does not require payment of royalty until such coal is later used, sold, or otherwise finally disposed of. ONRR may ask BLM or BIA to increase the lease bond to protect the lessor's interest when BLM determines that stockpiles or inventory become excessive so as to increase the risk of degradation of the resource.

(c) The lessee shall pay royalty at a rate specified in the lease at the time the coal is used, sold, or otherwise finally disposed of, unless otherwise provided for at § 1206.455(d).

§ 1206.455 Valuation standards for cents-per-ton leases.

(a) This section is applicable to coal leases on Indian Tribal and allotted Indian lands (except leases on the Osage Indian Reservation, Osage County, Oklahoma) which provide for the determination of royalty on a cents-per-ton (or other quantity) basis.

(b) The royalty for coal from leases subject to this section shall be based on the dollar rate per ton prescribed in the lease. That dollar rate shall be applicable to the actual quantity of coal used, sold, or otherwise finally disposed of, including coal which is avoidably lost as determined by BLM pursuant to 43 CFR part 3400.

(c) For leases subject to this section, there shall be no allowances for transportation, removal of impurities, coal washing, or any other processing or preparation of the coal.

(d) When a coal lease is readjusted pursuant to 43 CFR part 3400 and the royalty valuation method changes from a cents-per-ton basis to an ad valorem basis, coal which is produced prior to the effective date of readjustment and sold or used within 30 days of the effective date of readjustment shall be valued pursuant to this section. All coal that is not used, sold, or otherwise finally disposed of within 30 days after the effective date of readjustment shall be valued pursuant to the provisions of § 1206.456, and royalties shall be paid at the royalty rate specified in the readjusted lease.

§ 1206.456 Valuation standards for ad valorem leases.

(a) This section is applicable to coal leases on Indian Tribal and allotted Indian lands (except leases on the Osage Indian Reservation, Osage County, Oklahoma) which provide for the determination of royalty as a percentage of the amount of value of coal (ad valorem). The value for royalty purposes of coal from such leases shall be the value of coal determined pursuant to this section, less applicable coal washing allowances and transportation allowances determined pursuant to §§ 1206.457 through 1206.461, or any allowance authorized by § 1206.464. The royalty due shall be equal to the value for royalty purposes multiplied by the royalty rate in the lease.

(b)(1) The value of coal that is sold pursuant to an arm's-length contract shall be the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(2), (3), and (5) of this section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value which the lessee reports, for royalty purposes, is subject to monitoring, review, and audit.

(2) In conducting reviews and audits, ONRR will examine whether the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the coal produced. If the contract does not reflect the total consideration, then ONRR may require that the coal sold pursuant to that contract be valued in accordance with paragraph (c) of this section. Value may not be based on less than the gross proceeds accruing to the lessee for the coal production, including the additional consideration.

(3) If ONRR determines that the gross proceeds accruing to the lessee pursuant to an arm's-length contract do not reflect the reasonable value of the production because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then ONRR shall require that the coal production be valued pursuant to paragraph (c)(2)(ii), (iii), (iv), or (v) of this section, and in accordance with the notification requirements of paragraph (d)(3) of this section. When ONRR determines that the value may be unreasonable, ONRR will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's reported coal value.

(4) ONRR may require a lessee to certify that its arm's-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the coal production.

(5) The value of production for royalty purposes shall not include payments received by the lessee pursuant to a contract which the lessee demonstrates, to ONRR's satisfaction, were not part of the total consideration paid for the purchase of coal production.

(c)(1) The value of coal from leases subject to this section and which is not sold pursuant to an arm's-length contract shall be determined in accordance with this section.

(2) If the value of the coal cannot be determined pursuant to paragraph (b) of this section, then the value shall be determined through application of other valuation criteria. The criteria shall be considered in the following order, and the value shall be based upon the first applicable criterion:

(i) The gross proceeds accruing to the lessee pursuant to a sale under its non-arm's-length contract (or other disposition of produced coal by other than an arm's-length contract), provided that those gross proceeds are within the range of the gross proceeds derived from, or paid under, comparable arm's-length contracts between buyers and sellers neither of whom is affiliated with the lessee for sales, purchases, or other dispositions of like-quality coal produced in the area. In evaluating the comparability of arm's-length contracts for the purposes of these regulations, the following factors shall be considered: price, time of execution, duration, market or markets served, terms, quality of coal, quantity, and such other factors as may be appropriate to reflect the value of the coal;

(ii) Prices reported for that coal to a public utility commission;

(iii) Prices reported for that coal to the Energy Information Administration of the Department of Energy;

(iv) Other relevant matters including, but not limited to, published or publicly available spot market prices, or information submitted by the lessee concerning circumstances unique to a particular lease operation or the salability of certain types of coal;

(v) If a reasonable value cannot be determined using paragraph (c)(2)(i), (ii), (iii), or (iv) of this section, then a net-back method or any other reasonable method shall be used to determine value.

(3) When the value of coal is determined pursuant to paragraph (c)(2) of this section, that value determination shall be consistent with the provisions contained in paragraph (b)(5) of this section.

(d)(1) Where the value is determined pursuant to paragraph (c) of this section, that value does not require ONRR's prior approval. However, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject to review and audit, and ONRR will direct a lessee to use a different value if it determines that the reported value is inconsistent with the requirements of these regulations.

(2) An Indian lessee will make available upon request to the authorized ONRR or Indian representatives, or to the Inspector General of the Department of the Interior or other persons authorized to receive such information, arm's-length sales and sales quantity data for like-quality coal sold, purchased, or otherwise obtained by the lessee from the area.

(3) A lessee shall notify ONRR if it has determined value pursuant to paragraph (c)(2)(ii), (iii), (iv), or (v) of this section. The notification shall be by letter to the Director for Office of Natural Resources Revenue or his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this section is a one-time notification due no later than the month the lessee first reports royalties on the Form ONRR-4430 using a valuation method authorized by paragraph (c)(2)(ii), (iii), (iv), or (v) of this section, and each time there is a change in a method under paragraph (c)(2)(iv) or (v) of this section.

(e) If ONRR determines that a lessee has not properly determined value, the lessee shall be liable for the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by ONRR. The lessee shall also be liable for interest computed pursuant to § 1218.202 of this subchapter. If the lessee is entitled to a credit, ONRR will provide instructions for the taking of that credit.

(f) The lessee may request a value determination from ONRR. In that event, the lessee shall propose to ONRR a value determination method, and may use that method in determining value for royalty purposes until ONRR issues its decision. The lessee shall submit all available data relevant to its proposal. ONRR shall expeditiously determine the value based upon the lessee's proposal and any additional information ONRR deems necessary. That determination shall remain effective for the period stated therein. After ONRR issues its determination, the lessee shall make the adjustments in accordance with paragraph (e) of this section.

(g) Notwithstanding any other provisions of this section, under no circumstances shall the value for royalty purposes be less than the gross proceeds accruing to the lessee for the disposition of produced coal less applicable provisions of paragraph (b)(5) of this section and less applicable allowances determined pursuant to §§ 1206.457 through 1206.461 and 1206.464.

(h) The lessee is required to place coal in marketable condition at no cost to the Indian lessor. Where the value established pursuant to this section is determined by a lessee's gross proceeds, that value shall be increased to the extent that the gross proceeds has been reduced because the purchaser, or any other person, is providing certain services, the cost of which ordinarily is the responsibility of the lessee to place the coal in marketable condition.

(i) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled, it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to an arm's-length contract, and may be retroactively applied to value for royalty purposes for a period not to exceed two years, unless ONRR approves a longer period. If the lessee makes timely application for a price increase allowed under its contract but the purchaser refuses, and the lessee takes reasonable measures, which are documented, to force purchaser compliance, the lessee will owe no additional royalties unless or until monies or consideration resulting from the price increase are received. This paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a quantity of coal.

(j) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by ONRR of value under this section shall be considered final or binding as against the Indian Tribes or allottees until the audit period is formally closed.

(k) Certain information submitted to ONRR to support valuation proposals, including transportation, coal washing, or other allowances pursuant to §§ 1206.457 through 1206.461 and 1206.464, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 522. Any data specified by the Act to be privileged, confidential, or otherwise exempt shall be maintained in a confidential manner in accordance with applicable law and regulations. All requests for information about determinations made under this part are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2. Nothing in this section is intended to limit or diminish in any manner whatsoever the right of an Indian lessor to obtain any and all information as such lessor may be lawfully entitled from ONRR or such lessor's lessee directly under the terms of the lease or applicable law.

§ 1206.457 Washing allowances—general.

(a) For ad valorem leases subject to § 1206.456, ONRR shall, as authorized by this section, allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to wash coal, unless the value determined pursuant to § 1206.456 was based upon like-quality unwashed coal. Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero.

(b) If ONRR determines that a lessee has improperly determined a washing allowance authorized by this section, then the lessee shall be liable for any additional royalties, plus interest determined in accordance with § 1218.202 of this subchapter, or shall be entitled to a credit, without interest.

(c) Lessees shall not disproportionately allocate washing costs to Indian leases.

(d) No cost normally associated with mining operations and which are necessary for placing coal in marketable condition shall be allowed as a cost of washing.

(e) Coal washing costs shall only be recognized as allowances when the washed coal is sold and royalties are reported and paid.

§ 1206.458 Determination of washing allowances.

(a) Arm's-length contracts. (1) For washing costs incurred by a lessee pursuant to an arm's-length contract, the washing allowance shall be the reasonable actual costs incurred by the lessee for washing the coal under that contract, subject to monitoring, review, audit, and possible future adjustment. ONRR's prior approval is not required before a lessee may deduct costs incurred under an arm's-length contract. However, before any deduction may be taken, the lessee must submit a completed page one of Form ONRR-4292, Coal Washing Allowance Report, in accordance with paragraph (c)(1) of this section. A washing allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that Form ONRR-4292 is filed with ONRR, unless ONRR approves a longer period upon a showing of good cause by the lessee.

(2) In conducting reviews and audits, ONRR will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the washer for the washing. If the contract reflects more than the total consideration paid, then ONRR may require that the washing allowance be determined in accordance with paragraph (b) of this section.

(3) If ONRR determines that the consideration paid pursuant to an arm's-length washing contract does not reflect the reasonable value of the washing because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then ONRR shall require that the washing allowance be determined in accordance with paragraph (b) of this section. When ONRR determines that the value of the washing may be unreasonable, ONRR will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's washing costs.

(4) Where the lessee's payments for washing under an arm's-length contract are not based on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent. Washing allowances shall be expressed as a cost per ton of coal washed.

(b) Non-arm's-length or no contract. (1) If a lessee has a non-arm's-length contract or has no contract, including those situations where the lessee performs washing for itself, the washing allowance will be based upon the lessee's reasonable actual costs. All washing allowances deducted under a non-arm's-length or no contract situation are subject to monitoring, review, audit, and possible future adjustment. Prior ONRR approval of washing allowances is not required for non-arm's-length or no contract situations. However, before any estimated or actual deduction may be taken, the lessee must submit a completed Form ONRR-4292 in accordance with paragraph (c)(2) of this section. A washing allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that Form ONRR-4292 is filed with ONRR, unless ONRR approves a longer period upon a showing of good cause by the lessee. ONRR will monitor the allowance deduction to ensure that deductions are reasonable and allowable. When necessary or appropriate, ONRR may direct a lessee to modify its actual washing allowance.

(2) The washing allowance for non-arm's-length or no contract situations shall be based upon the lessee's actual costs for washing during the reported period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the depreciable investment in the wash plant multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the wash plant.

(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.

(ii) Allowable maintenance expenses include: Maintenance of the wash plant; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.

(iii) Overhead attributable and allocable to the operation and maintenance of the wash plant is an allowable expense. State and Federal income taxes and severance taxes, including royalties, are not allowable expenses.

(iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this section. After a lessee has elected to use either method for a wash plant, the lessee may not later elect to change to the other alternative without approval of ONRR.

(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the wash plant services, whichever is appropriate, or a unit of production method. After an election is made, the lessee may not change methods without ONRR approval. A change in ownership of a wash plant shall not alter the depreciation schedule established by the original operator/lessee for purposes of the allowance calculation. With or without a change in ownership, a wash plant shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.

(B) ONRR shall allow as a cost an amount equal to the allowable capital investment in the wash plant multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to plants first placed in service or acquired after March 1, 1989.

(v) The rate of return shall be the industrial rate associated with Standard and Poor's BBB rating. The rate of return shall be the monthly average rate as published in Standard and Poor's Bond Guide for the first month of the reporting period for which the allowance is applicable and shall be effective during the reporting period. The rate shall be redetermined at the beginning of each subsequent washing allowance reporting period (which is determined pursuant to paragraph (c)(2) of this section).

(3) The washing allowance for coal shall be determined based on the lessee's reasonable and actual cost of washing the coal. The lessee may not take an allowance for the costs of washing lease production that is not royalty bearing.

(c) Reporting requirements—(1) Arm's-length contracts. (i) With the exception of those washing allowances specified in paragraphs (c)(1)(v) and (vi) of this section, the lessee shall submit page one of the initial Form ONRR-4292 prior to, or at the same time, as the washing allowance determined pursuant to an arm's-length contract is reported on Form ONRR-4430, Solid Minerals Production and Royalty Report. A Form ONRR-4292 received by the end of the month that the Form ONRR-4430 is due shall be considered to be received timely.

(ii) The initial Form ONRR-4292 shall be effective for a reporting period beginning the month that the lessee is first authorized to deduct a washing allowance and shall continue until the end of the calendar year, or until the applicable contract or rate terminates or is modified or amended, whichever is earlier.

(iii) After the initial reporting period and for succeeding reporting periods, lessees must submit page one of Form ONRR-4292 within 3 months after the end of the calendar year, or after the applicable contract or rate terminates or is modified or amended, whichever is earlier, unless ONRR approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period).

(iv) ONRR may require that a lessee submit arm's-length washing contracts and related documents. Documents shall be submitted within a reasonable time, as determined by ONRR.

(v) Washing allowances which are based on arm's-length contracts and which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by ONRR in writing shall qualify as being in effect at the time these regulations become effective.

(vi) ONRR may establish, in appropriate circumstances, reporting requirements that are different from the requirements of this section.

(2) Non-arm's-length or no contract. (i) With the exception of those washing allowances specified in paragraphs (c)(2)(v) and (vii) of this section, the lessee shall submit an initial Form ONRR-4292 prior to, or at the same time as, the washing allowance determined pursuant to a non-arm's-length contract or no contract situation is reported on Form ONRR-4430, Solid Minerals Production and Royalty Report. A Form ONRR-4292 received by the end of the month that the Form ONRR-4430 is due shall be considered to be timely received. The initial reporting may be based on estimated costs.

(ii) The initial Form ONRR-4292 shall be effective for a reporting period beginning the month that the lessee first is authorized to deduct a washing allowance and shall continue until the end of the calendar year, or until the washing under the non-arm's-length contract or the no contract situation terminates, whichever is earlier.

(iii) For calendar-year reporting periods succeeding the initial reporting period, the lessee shall submit a completed Form ONRR-4292 containing the actual costs for the previous reporting period. If coal washing is continuing, the lessee shall include on Form ONRR-4292 its estimated costs for the next calendar year. The estimated coal washing allowance shall be based on the actual costs for the previous period plus or minus any adjustments which are based on the lessee's knowledge of decreases or increases which will affect the allowance. Form ONRR-4292 must be received by ONRR within 3 months after the end of the previous reporting period, unless ONRR approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period).

(iv) For new wash plants, the lessee's initial Form ONRR-4292 shall include estimates of the allowable coal washing costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the plant, or if such data are not available, the lessee shall use estimates based upon industry data for similar coal wash plants.

(v) Washing allowances based on non-arm's-length or no contract situations which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by ONRR in writing shall qualify as being in effect at the time these regulations become effective.

(vi) Upon request by ONRR, the lessee shall submit all data used by the lessee to prepare its Forms ONRR-4292. The data shall be provided within a reasonable period of time, as determined by ONRR.

(vii) ONRR may establish, in appropriate circumstances, reporting requirements which are different from the requirements of this section.

(3) ONRR may establish coal washing allowance reporting dates for individual leases different from those specified in this subpart in order to provide more effective administration. Lessees will be notified of any change in their reporting period.

(4) Washing allowances must be reported as a separate line on the Form ONRR-4430, unless ONRR approves a different reporting procedure.

(d) Interest assessments for incorrect or late reports and failure to report. (1) If a lessee deducts a washing allowance on its Form ONRR-4430 without complying with the requirements of this section, the lessee shall be liable for interest on the amount of such deduction until the requirements of this section are complied with. The lessee also shall repay the amount of any allowance which is disallowed by this section.

(2) If a lessee erroneously reports a washing allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.

(3) Interest required to be paid by this section shall be determined in accordance with § 1218.202 of this subchapter.

(e) Adjustments. (1) If the actual coal washing allowance is less than the amount the lessee has taken on Form ONRR-4430 for each month during the allowance form reporting period, the lessee shall be required to pay additional royalties due plus interest computed pursuant to § 1218.202 of this subchapter, retroactive to the first month the lessee is authorized to deduct a washing allowance. If the actual washing allowance is greater than the amount the lessee has estimated and taken during the reporting period, the lessee shall be entitled to a credit, without interest.

(2) The lessee must submit a corrected Form ONRR-4430 to reflect actual costs, together with any payment, in accordance with instructions provided by ONRR.

(f) Other washing cost determinations. The provisions of this section shall apply to determine washing costs when establishing value using a net-back valuation procedure or any other procedure that requires deduction of washing costs.

§ 1206.459 Allocation of washed coal.

(a) When coal is subjected to washing, the washed coal must be allocated to the leases from which it was extracted.

(b) When the net output of coal from a washing plant is derived from coal obtained from only one lease, the quantity of washed coal allocable to the lease will be based on the net output of the washing plant.

(c) When the net output of coal from a washing plant is derived from coal obtained from more than one lease, unless determined otherwise by BLM, the quantity of net output of washed coal allocable to each lease will be based on the ratio of measured quantities of coal delivered to the washing plant and washed from each lease compared to the total measured quantities of coal delivered to the washing plant and washed.

§ 1206.460 Transportation allowances—general.

(a) For ad valorem leases subject to § 1206.456, where the value for royalty purposes has been determined at a point remote from the lease or mine, ONRR shall, as authorized by this section, allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to:

(1) Transport the coal from an Indian lease to a sales point which is remote from both the lease and mine; or

(2) Transport the coal from an Indian lease to a wash plant when that plant is remote from both the lease and mine and, if applicable, from the wash plant to a remote sales point. In-mine transportation costs shall not be included in the transportation allowance.

(b) Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero.

(c)(1) When coal transported from a mine to a wash plant is eligible for a transportation allowance in accordance with this section, the lessee is not required to allocate transportation costs between the quantity of clean coal output and the rejected waste material. The transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of cleaned coal transported.

(2) For coal that is not washed at a wash plant, the transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of coal transported.

(3) Transportation costs shall only be recognized as allowances when the transported coal is sold and royalties are reported and paid.

(d) If, after a review and/or audit, ONRR determines that a lessee has improperly determined a transportation allowance authorized by this section, then the lessee shall pay any additional royalties, plus interest, determined in accordance with § 1218.202 of this subchapter, or shall be entitled to a credit, without interest.

(e) Lessees shall not disproportionately allocate transportation costs to Indian leases.

§ 1206.461 Determination of transportation allowances.

(a) Arm's-length contracts. (1) For transportation costs incurred by a lessee pursuant to an arm's-length contract, the transportation allowance shall be the reasonable, actual costs incurred by the lessee for transporting the coal under that contract, subject to monitoring, review, audit, and possible future adjustment. ONRR's prior approval is not required before a lessee may deduct costs incurred under an arm's-length contract. However, before any deduction may be taken, the lessee must submit a completed page one of Form ONRR-4293, Coal Transportation Allowance Report, in accordance with paragraph (c)(1) of this section. A transportation allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that Form ONRR-4293 is filed with ONRR, unless ONRR approves a longer period upon a showing of good cause by the lessee.

(2) In conducting reviews and audits, ONRR will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the transporter for the transportation. If the contract reflects more than the total consideration paid, then ONRR may require that the transportation allowance be determined in accordance with paragraph (b) of this section.

(3) If ONRR determines that the consideration paid pursuant to an arm's-length transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then ONRR shall require that the transportation allowance be determined in accordance with paragraph (b) of this section. When ONRR determines that the value of the transportation may be unreasonable, ONRR will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's transportation costs.

(4) Where the lessee's payments for transportation under an arm's-length contract are not based on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.

(b) Non-arm's-length or no contract. (1) If a lessee has a non-arm's-length contract or has no contract, including those situations where the lessee performs transportation services for itself, the transportation allowance will be based upon the lessee's reasonable actual costs. All transportation allowances deducted under a non-arm's-length or no contract situation are subject to monitoring, review, audit, and possible future adjustment. Prior ONRR approval of transportation allowances is not required for non-arm's-length or no contract situations. However, before any estimated or actual deduction may be taken, the lessee must submit a completed Form ONRR-4293 in accordance with paragraph (c)(2) of this section. A transportation allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that Form ONRR-4293 is filed with ONRR, unless ONRR approves a longer period upon a showing of good cause by the lessee. ONRR will monitor the allowance deductions to ensure that deductions are reasonable and allowable. When necessary or appropriate, ONRR may direct a lessee to modify its estimated or actual transportation allowance deduction.

(2) The transportation allowance for non-arm's-length or no contract situations shall be based upon the lessee's actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the depreciable investment in the transportation system multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system.

(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.

(ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.

(iii) Overhead attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.

(iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this section. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without approval of ONRR.

(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the transportation system services, whichever is appropriate, or a unit of production method. After an election is made, the lessee may not change methods without ONRR approval. A change in ownership of a transportation system shall not alter the depreciation schedule established by the original transporter/lessee for purposes of the allowance calculation. With or without a change in ownership, a transportation system shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.

(B) ONRR shall allow as a cost an amount equal to the allowable capital investment in the transportation system multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to transportation facilities first placed in service or acquired after March 1, 1989.

(v) The rate of return shall be the industrial rate associated with Standard and Poor's BBB rating. The rate of return shall be the monthly average as published in Standard and Poor's Bond Guide for the first month of the reporting period of which the allowance is applicable and shall be effective during the reporting period. The rate shall be redetermined at the beginning of each subsequent transportation allowance reporting period (which is determined pursuant to paragraph (c)(2) of this section).

(3) A lessee may apply to ONRR for exception from the requirement that it compute actual costs in accordance with paragraphs (b)(1) and (2) of this section. ONRR will grant the exception only if the lessee has a rate for the transportation approved by a Federal agency for Indian leases. ONRR shall deny the exception request if it determines that the rate is excessive as compared to arm's-length transportation charges by systems, owned by the lessee or others, providing similar transportation services in that area. If there are no arm's-length transportation charges, ONRR shall deny the exception request if:

(i) No Federal regulatory agency cost analysis exists and the Federal regulatory agency has declined to investigate pursuant to ONRR timely objections upon filing; and

(ii) The rate significantly exceeds the lessee's actual costs for transportation as determined under this section.

(c) Reporting requirements—(1) Arm's-length contracts. (i) With the exception of those transportation allowances specified in paragraphs (c)(1)(v) and (vi) of this section, the lessee shall submit page one of the initial Form ONRR-4293 prior to, or at the same time as, the transportation allowance determined pursuant to an arm's-length contract is reported on Form ONRR-4430, Solid Minerals Production and Royalty Report.

(ii) The initial Form ONRR-4293 shall be effective for a reporting period beginning the month that the lessee is first authorized to deduct a transportation allowance and shall continue until the end of the calendar year, or until the applicable contract or rate terminates or is modified or amended, whichever is earlier.

(iii) After the initial reporting period and for succeeding reporting periods, lessees must submit page one of Form ONRR-4293 within 3 months after the end of the calendar year, or after the applicable contract or rate terminates or is modified or amended, whichever is earlier, unless ONRR approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period). Lessees may request special reporting procedures in unique allowance reporting situations, such as those related to spot sales.

(iv) ONRR may require that a lessee submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. Documents shall be submitted within a reasonable time, as determined by ONRR.

(v) Transportation allowances that are based on arm's-length contracts and which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by ONRR in writing shall qualify as being in effect at the time these regulations become effective.

(vi) ONRR may establish, in appropriate circumstances, reporting requirements that are different from the requirements of this section.

(2) Non-arm's-length or no contract. (i) With the exception of those transportation allowances specified in paragraphs (c)(2)(v) and (vii) of this section, the lessee shall submit an initial Form ONRR-4293 prior to, or at the same time as, the transportation allowance determined pursuant to a non-arm's-length contract or no contract situation is reported on Form ONRR-4430, Solid Minerals Production and Royalty Report. The initial report may be based on estimated costs.

(ii) The initial Form ONRR-4293 shall be effective for a reporting period beginning the month that the lessee first is authorized to deduct a transportation allowance and shall continue until the end of the calendar year, or until the transportation under the non-arm's-length contract or the no contract situation terminates, whichever is earlier.

(iii) For calendar-year reporting periods succeeding the initial reporting period, the lessee shall submit a completed Form ONRR-4293 containing the actual costs for the previous reporting period. If the transportation is continuing, the lessee shall include on Form ONRR-4293 its estimated costs for the next calendar year. The estimated transportation allowance shall be based on the actual costs for the previous reporting period plus or minus any adjustments that are based on the lessee's knowledge of decreases or increases that will affect the allowance. Form ONRR-4293 must be received by ONRR within 3 months after the end of the previous reporting period, unless ONRR approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period).

(iv) For new transportation facilities or arrangements, the lessee's initial Form ONRR-4293 shall include estimates of the allowable transportation costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the transportation system, or, if such data are not available, the lessee shall use estimates based upon industry data for similar transportation systems.

(v) Non-arm's-length contract or no contract-based transportation allowances that are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For purposes of this section, only those allowances that have been approved by ONRR in writing shall qualify as being in effect at the time these regulations become effective.

(vi) Upon request by ONRR, the lessee shall submit all data used to prepare its Form ONRR-4293. The data shall be provided within a reasonable period of time, as determined by ONRR.

(vii) ONRR may establish, in appropriate circumstances, reporting requirements that are different from the requirements of this section.

(viii) If the lessee is authorized to use its Federal-agency-approved rate as its transportation cost in accordance with paragraph (b)(3) of this section, it shall follow the reporting requirements of paragraph (c)(1) of this section.

(3) ONRR may establish reporting dates for individual lessees different than those specified in this paragraph in order to provide more effective administration. Lessees will be notified as to any change in their reporting period.

(4) Transportation allowances must be reported as a separate line item on Form ONRR-4430, unless ONRR approves a different reporting procedure.

(d) Interest assessments for incorrect or late reports and failure to report. (1) If a lessee deducts a transportation allowance on its Form ONRR-4430 without complying with the requirements of this section, the lessee shall be liable for interest on the amount of such deduction until the requirements of this section are complied with. The lessee also shall repay the amount of any allowance which is disallowed by this section.

(2) If a lessee erroneously reports a transportation allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.

(3) Interest required to be paid by this section shall be determined in accordance with § 1218.202 of this subchapter.

(e) Adjustments. (1) If the actual transportation allowance is less than the amount the lessee has taken on Form ONRR-4430 for each month during the allowance form reporting period, the lessee shall be required to pay additional royalties due plus interest, computed pursuant to § 1218.202 of this subchapter, retroactive to the first month the lessee is authorized to deduct a transportation allowance. If the actual transportation allowance is greater than the amount the lessee has estimated and taken during the reporting period, the lessee shall be entitled to a credit, without interest.

(2) The lessee must submit a corrected Form ONRR-4430 to reflect actual costs, together with any payment, in accordance with instructions provided by ONRR.

(f) Other transportation cost determinations. The provisions of this section shall apply to determine transportation costs when establishing value using a net-back valuation procedure or any other procedure that requires deduction of transportation costs.

§ 1206.462 [Reserved]

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

If an ad valorem Federal coal lease is developed by in-situ or surface gasification or liquefaction technology, the lessee shall propose the value of coal for royalty purposes to ONRR. ONRR will review the lessee's proposal and issue a value determination. The lessee may use its proposed value until ONRR issues a value determination.

§ 1206.464 Value enhancement of marketable coal.

If, prior to use, sale, or other disposition, the lessee enhances the value of coal after the coal has been placed in marketable condition in accordance with § 1206.456(h), the lessee shall notify ONRR that such processing is occurring or will occur. The value of that production shall be determined as follows:

(a) A value established for the feedstock coal in marketable condition by application of the provisions of § 1206.456(c)(2)(i) through (iv); or,

(b) In the event that a value cannot be established in accordance with paragraph (a) of this section, then the value of production will be determined in accordance with § 1206.456(c)(2)(v) and the value shall be the lessee's gross proceeds accruing from the disposition of the enhanced product, reduced by ONRR-approved processing costs and procedures including a rate of return on investment equal to two times the Standard and Poor's BBB bond rate applicable under § 1206.458(b)(2)(v).

§ 1207.1 Required recordkeeping.

(a) ONRR uses the information collected to determine a proper transportation allowance for the cost of transporting royalty oil from the lease to a delivery point remote from the lease. The information is required so that the lessee may obtain a benefit under the Federal Oil and Gas Royalty Management Act of 1982, 30 U.S.C. 1701 et seq. The Office of Management and Budget (OMB) approved the information collection requirements contained in this part under 44 U.S.C. 3501 et seq. ONRR identifies the approved OMB control number in 30 CFR 1210.10.

(b) Send comments regarding the burden estimates or any other aspect of this information collection, including suggestions for reducing burden, to the Office of Natural Resources Revenue, Attention: Rules & Regs Team, OMB Control Number 1012-0002, P.O. Box 25165, Denver, CO 80225-0165.

[78 FR 30204, May 22, 2013]

§ 1207.2 Definitions.

The definitions in part 1206 of this title are applicable to this part.

§ 1207.3 Contracts made pursuant to new form leases.

On November 29, 1950 (15 FR 8585), a new lease form was adopted (Form 4-1158, 15 FR 8585) containing provisions whereby the lessee agrees that nothing in any contract or other arrangement made for the sale or disposal of oil, gas, natural gasoline, and other products of the leased land, shall be construed as modifying any of the provisions of the lease, including, but not limited to, provisions relating to gas waste, taking royalty-in-kind, and the method of computing royalties due as based on a minimum valuation and in accordance with the oil and gas valuation regulations. A contract or agreement pursuant to a lease containing such provisions may be made without obtaining prior approval of the United States as lessor, but must be retained as provided in § 1207.5 of this subpart.

§ 1207.4 Contracts made pursuant to old form leases.

(a) Old form leases are those containing provisions prohibiting sales or disposal of oil, gas, natural gasoline, and other products of the lease except in accordance with a contract or other arrangement approved by the Secretary of the Interior, or by the Director of the Bureau of Ocean Energy Management (BOEM) or his/her representative. A contract or agreement made pursuant to an old form lease may be made without obtaining approval if the contract or agreement contains either the substance of or is accompanied by the stipulation set forth in paragraph (b) of this section, signed by the seller (lessee or operator).

(b) The stipulation, the substance of which must be included in the contract, or be made the subject matter of a separate instrument properly identifying the leases affected thereby, is as follows:

It is hereby understood and agreed that nothing in the written contract or in any approval thereof shall be construed as affecting any of the relations between the United States and its lessee, particularly in matters of gas waste, taking royalty in kind, and the method of computing royalties due as based on a minimum valuation and in accordance with the terms and provisions of the oil and gas valuation regulations applicable to the lands covered by said contract.

[53 FR 1225, Jan. 15, 1988, as amended at 78 FR 30204, May 22, 2013]

§ 1207.5 Contract and sales agreement retention.

Copies of all sales contracts, posted price bulletins, etc., and copies of all agreements, other contracts, or other documents which are relevant to the valuation of production are to be maintained by the lessee and made available upon request during normal working hours to authorized Office of Natural Resources Revenue (ONRR), State or Indian representatives, BOEM, Bureau of Safety and Environmental Enforcement (BSEE) or BLM officials, auditors of the General Accounting Office, or other persons authorized to receive such documents, or shall be submitted to ONRR within a reasonable period of time, as determined by ONRR. Any oral sales arrangement negotiated by the lessee must be placed in written form and retained by the lessee. Records shall be retained in accordance with 30 CFR part 1212.

[53 FR 1225, Jan. 15, 1988, as amended at 78 FR 30204, May 22, 2013]

§ 1208.1 General.

The regulations in this part govern the sale of royalty oil by the United States to eligible refiners. The regulations apply to royalty oil from leases on Federal lands onshore and on the Outer Continental Shelf (OCS).

§ 1208.2 Definitions.

Allotment means the quantity of royalty oil that DOI determines is available to each eligible refiner that has applied for a portion of the total volume of royalty oil offered in a given royalty oil sale.

Application means the formal written request to DOI on Form MMS-4070 by an eligible refiner interested in purchasing a quantity of royalty oil from the approximate volume announced by DOI in a given “Notice of Availability of Royalty Oil.”

Area or Region means the geographic territory having Federal oil and gas leases over which ONRR has jurisdiction, unless the context in which those words are used indicates that a different meaning is intended.

Contracting officer means the Director, his or her delegate, or the person designated under a royalty oil purchase contract.

Contracting officer's decision means an ONRR order or decision that a contracting officer issues under this part to a purchaser of oil under a royalty oil purchase contract.

Delivery point means the point where the lessor, in accordance with lease terms, directs the lessee to deliver royalty oil to a purchaser. Title to the royalty oil, or to the quantity thereof in a commingled stream, passes from the Federal Government to the purchaser at this designated point, which is specified in the royalty oil contract. For onshore leases, the delivery point will be on or adjacent to the lease, except as provided in § 1208.8(a) of this part. In instances where an onshore delivery point is designated for offshore royalty oil, such point generally will be the first onshore point where the price of the oil, including transportation costs, can be determined and where the purchaser can either exchange or take delivery of the oil. The Government does not guarantee physical access to the oil at such point.

Director means the Director of ONRR, who is responsible for its overall direction, or his or her delegate(s).

DOI means the Department of the Interior, including the Secretary or his or her delegate(s).

Eligible refiner means a refiner of crude oil that meets the following criteria for eligibility to purchase royalty oil:

(1) For the purchase of royalty oil from onshore leases, it means a refiner that qualifies as a small and independent refiner as those terms are defined in sections 3(3) and 3(4) of the Emergency Petroleum Allocation Act, 15 U.S.C. 751 et seq., except that the time period for determination contained in section 3(3)(A) would be the calendar quarter immediately preceding the date of the applicable “Notice of Availability of Royalty Oil.” A refiner that, together with all persons controlled by, in control of, under common control with, or otherwise affiliated with the refiner, inputs a volume of domestic crude oil from its own production exceeding 30 percent of its total refinery input of crude oil is ineligible to participate in royalty oil sales under this part. Crude oil received in exchange for such refiner's own production is considered to be that refiner's own production for purposes of this section.

(2) For the purchase of royalty oil from leases on the OCS, it means a refiner that qualifies as a small business enterprise under the rules of the Small Business Administration (13 CFR part 121).

Entitlement means the volume of royalty oil from the Federal Government's share of production from a Federal lease which a purchaser is entitled to receive under a royalty oil contract.

Exchange agreement means a written agreement between the purchaser and another person for the exchange of royalty oil purchased under this part for other oil on a volume or equivalent value basis.

Fair market value means the value of oil—(1) Computed at a unit price equivalent to the average unit price at which oil was sold pursuant to a lease during the period for which any royalty or net profit share is accrued or reserved to the United States pursuant to such lease, or

(2) If there were no such sales, or if the Secretary finds that there were an insufficient number of such sales to equitably determine such value, computed at the average unit price at which oil was sold pursuant to other leases in the same region of the OCS during such period, or

(3) If there were no sales of oil from such region during such period, or if the Secretary finds that there are an insufficient number of such sales to equitably determine such value, at an appropriate price determined by the Secretary.

Federal lease means a contractual agreement with the Federal Government which authorizes the exploration, development, and production of oil and gas on Federal lands onshore or on the OCS.

Interim sale means a sale conducted as a result of substantial additional royalty oil becoming available in a specific area prior to the scheduled expiration date of royalty oil contracts in effect for that area.

Lessee means any person to whom the United States issues a lease, or any person who has been assigned an obligation to make royalty or other payments required by the lease.

Notice of Availability of Royalty Oil means a notice published by DOI in the Federal Register (and in other printed media when appropriate, such as a newspaper or magazine of general or specialized circulation) to advise interested parties of the availability of royalty oil for purchase by eligible refiners and the approximate volume of royalty oil available to the applicants.

OCS means the Outer Continental Shelf, as defined in 43 U.S.C. 1331(a).

OCSLA means the Outer Continental Shelf Lands Act (43 U.S.C. 1331 et seq., as amended by 43 U.S.C. 1801 et seq.).

Oil means a mixture of hydrocarbons that existed in the liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities and is marketed or used as such. Condensate recovered in lease separators or field facilities is considered to be oil.

ONRR means the Office of Natural Resources Revenue of the Department of the Interior.

Operator means any person, including a lessee, who has control of or who manages operations on an oil and gas lease site on Federal onshore lands or on the OCS.

Payor means any person responsible for reporting royalties from a Federal lease or leases on Form MMS-2014.

Person means any individual, firm, corporation, association, partnership, consortium, or joint venture.

Preference eligible refiner means an eligible refiner with at least one operating refinery which is located within the area designated as the preference eligible area in the “Notice of Availability of Royalty Oil.” A refiner may be deemed to be a preference eligible refiner if it owns a refinery located in the preference eligible area which is not operational if the refiner meets the requirements of § 1208.7(g) of this part.

Purchaser means anyone who acquires royalty oil sold by DOI under the Federal Government's Royalty-in-Kind (RIK) Program and who has a contractual obligation under an agreement to purchase royalty oil.

Reallocation means an offering of royalty oil previously allocated in a specific sale but subsequently turned back to ONRR. A reallocation would only be made if substantial amounts of royalty oil are turned back.

Refined petroleum product means gasoline, kerosene, distillates (including Number 2 fuel oil), refined lubricating oils, or diesel fuel.

Royalty oil means that amount of oil that DOI takes in kind in partial or full satisfaction of a lessee's royalty or net profit share obligations as determined by whatever lease interest the lessee holds under an applicable mineral leasing law.

Secretary means the Secretary of the Department of the Interior or his/her delegate(s).

Section 6 lease means an oil and gas lease originally issued by any State and currently maintained in effect pursuant to section 6 of the OCSLA.

Section 8 lease means an oil and gas lease originally issued by the United States pursuant to section 8 of the OCSLA.

[52 FR 41913, Oct. 30, 1987; 52 FR 45528, Nov. 30, 1987, as amended at 58 FR 64901, Dec. 10, 1993; 64 FR 26251, May 13, 1999]

§ 1208.3 Information collection.

The information collection requirements contained in this part have been approved by OMB under 44 U.S.C. 3501 et seq. The form, filing date, and approved OMB clearance number are identified in 30 CFR 210.10.

[58 FR 64901, Dec. 10, 1993]

§ 1208.4 Royalty oil sales to eligible refiners.

(a) Determination to take royalty oil in kind. The Secretary may evaluate crude oil market conditions from time to time. The evaluation will include, among other things, the availability of crude oil and the crude oil requirements of the Federal Government, primarily those requirements concerning matters of national interest and defense. The Secretary will review these items and will determine whether eligible refiners have access to adequate supplies of crude oil and whether such oil is available to eligible refiners at equitable prices. Such determinations may be made on a regional basis. The determination by the Secretary shall be published in the Federal Register concurrent with or included in the “Notice of Availability of Royalty Oil” required by § 1208.5.

(b) Sale to eligible refiners. (1) Upon a determination by the Secretary under paragraph (a) of this section that eligible refiners do not have access to adequate supplies of crude oil at equitable prices, the Secretary, at his or her discretion, may elect to take in kind some or all of the royalty oil accruing to the United States from oil and gas leases on Federal lands onshore and on the OCS. The Secretary may authorize ONRR to offer royalty oil for sale to eligible refiners only for use in their refineries and not for resale (other than under an exchange agreement).

(2) All sales of royalty oil from onshore leases will be priced at the royalty value that would have been determined for that oil pursuant to 30 CFR part 1206 had the royalties been paid in value rather than taken in kind. All sales of royalty oil from OCS leases will be priced at the fair market value of the oil including associated transportation costs to the designated delivery point, if applicable.

(3) An eligible refiner must have a representative at a sale in order to participate. The Secretary may, at his or her discretion, establish purchase limitations and withhold any royalty oil from any offering.

(c) Upon a determination by the Secretary under paragraph (a) of this section that eligible refiners do have access to adequate supplies of crude oil at equitable prices, ONRR will not take royalties in kind from oil and gas leases for exclusive sale to such refiners. Such determinations may be made on a regional basis.

(d) Interim sales. The ONRR generally will not conduct interim sales. However, interim sales may be held at the discretion of the Secretary if substantial addition royalty oil becomes available. The potentially eligible refiners, individually or collectively, must submit documentation demonstrating that adequate supplies of crude oil at equitable prices are not available for purchase. Although sufficient documentation must be submitted, it is not mandatory for each potentially eligible refiner to participate in a submission of such documentation to be determined eligible. The documentation must be submitted to ONRR for a determination as to whether an interim sale is needed.

[52 FR 41913, Oct. 30, 1987, as amended at 66 FR 28657, May 24, 2001]

§ 1208.5 Notice of royalty oil sale.

If the Secretary decides to take royalty oil in kind for sale to eligible refiners, ONRR will issue a “Notice of Availability of Royalty Oil” specifying the manner in which the sale is to be effected, the approximate quantity of royalty oil to be offered, information required in applications, the closing date for the receipt of applications for royalty oil, and other general administrative details concerning the application, allocation, and contract award process for the royalty oil. The Notice will describe generally the terms under which the royalty oil contracts will be awarded and will specify which applicants will be deemed preference eligible refiners in the sale proceedings. The Notice will also contain guidelines for reallocation procedures in the event substantial quantities of royalty oil sold in that specific sale are subsequently turned back to ONRR. Only those purchasers that hold ongoing contracts from that specific sale will be allowed to participate in any reallocation, which would be voluntary, and then only if they continue to meet eligibility requirements as set forth in §§ 1208.2 and 1208.7. If a reallocation is held prior to the effective date of the contracts as specified in the “Notice of Availability of Royalty Oil”, all eligible refiners that selected a lease or leases in that specific sale would be allowed to participate, pursuant to the procedures in the Notice.

§ 1208.6 General application procedures.

(a) To apply for the purchase of royalty oil, an applicant must file a Form MMS-4070 with ONRR in accordance with instructions provided in the “Notice of Availability of Royalty Oil” and in accordance with any instructions issued by ONRR for completion of Form MMS-4070. The applicant will be required to submit a letter of intent from a qualified financial institution stating that it would be granted surety coverage for the royalty oil for which it is applying, or other such proof of surety coverage, as deemed acceptable by ONRR. The letter of intent must be submitted with a completed Form MMS-4070.

(b) In addition to any other application requirements specified in the Notice, the following information is required on Form MMS-4070 at the time of application:

(1) Name and address of the applicant, the location of the applicant's refinery or refineries, and disclosure of the applicant's affiliation with any other persons.

(2) The capacity of the applicant's refineries in barrels of crude oil throughput per calendar day and a tabulation for the past 12 months of oil processed for each refinery, identified as to source (from own production or from other sources).

(3) Identification of any Government royalty oil contracts under which the applicant is currently receiving royalty oil.

(4) Identification of the locations (area/region and State) where the applicant proposes to purchase royalty oil, the volume of oil requested, and the specific refineries in which the oil will be refined.

(5) A certification from the applicant that it is an eligible refiner for the purchase of Government royalty oil, as defined in § 1208.2 of this part.

[52 FR 41913, Oct. 30, 1987, as amended at 58 FR 64901, Dec. 10, 1993]

§ 1208.7 Determination of eligibility.

(a) The ONRR will examine each application and may request additional information if the information in the application is inadequate. An application received after the close of the application period will be rejected. If additional information is requested by ONRR, it must be received by the time specified or the application will be rejected.

(b) After the close of the application period and the receipt of any additional requested information, ONRR will determine which applicants may participate in the royalty oil sale and the quantity of royalty oil which each applicant is authorized to purchase.

(c) When applications are filed by two or more eligible refiners for the same royalty oil, the oil will be allocated among such applicants on an equitable basis as determined by ONRR. Preference eligible refiners will be given priority in the allocation procedures in sales and subsequent reallocations of royalty oil.

(d) No eligible refiner shall be awarded contracts for volumes of royalty oil that, when added to volumes of other Federal royalty oil being received, are in excess of 60 percent of the combined refinery capacity of that refiner.

(e) The ONRR may exclude any section 6 lease from a royalty oil sale.

(f) If two or more eligible refiners are related through common ownership or control or otherwise affiliated, only one of them shall be entitled to an allotment of royalty oil from a specific sale.

(g) Any applicant whose refinery is not in operation during the 60-day period prior to the date of the royalty oil sale shall not be entitled to participate in the sale unless such applicant self-certifies and demonstrates to the satisfaction of ONRR that it will begin operations by the first month in which oil becomes available under a royalty oil contract. If operations do not begin by that month, ONRR will terminate the contract.

(h) Applicants or purchasers that have delinquent balances with ONRR as of the date of a royalty oil sale or subsequent reallocation will not be allowed to participate in that sale or reallocation. If a person which is controlled by, in control of, under common control with, or otherwise affiliated with an applicant or purchaser has such delinquent balances, the applicant or purchaser will not be allowed to participate in a royalty oil sale or reallocation. To the extent a purchaser or affiliated person has appealed a billing and posted a surety instrument in accordance with the contract terms and applicable ONRR regulations or other law, the balance shall not be considered delinquent.

(i) A purchaser must meet the eligibility criteria on the date of contract issuance. However, a change in a purchaser's eligibility status during the term of the contract will not affect the purchaser's right to continue that contract until its term expires, including any extensions thereof.

[52 FR 41913, Oct. 30, 1987, as amended at 58 FR 64901, Dec. 10, 1993]

§ 1208.8 Transportation and delivery.

(a) The lessee shall deliver royalty oil from onshore leases to the purchaser at a point on or adjacent to the lease pursuant to the terms of the lease. If the purchaser does not have access to its onshore royalty oil entitlement at facilities on or adjacent to the lease, the operator of the lease must designate an alternate delivery point at no additional cost to the purchaser or the Government. The purchaser must have physical access to the oil at the alternate delivery point and such point must be approved by ONRR.

(b) The lessee shall deliver royalty oil from section 8 offshore leases issued after September 1969 at a delivery point to be designated by ONRR. The lessee shall deliver royalty oil from section 8 offshore leases issued before October 1969 or from section 6 leases at a delivery point to be designated by the lessee. If the delivery point is on or immediately adjacent to the lease, the royalty oil will be delivered without cost to the Federal Government as an undivided portion of production in marketable condition at pipeline connections or other facilities provided by the lessee, unless other arrangements are approved by ONRR. If the delivery point is not on or immediately adjacent to the lease, ONRR will reimburse the lessee for the reasonable cost of transportation to such point in an amount not to exceed the transportation allowance determined pursuant to 30 CFR part 1206. The ONRR will include such transportation costs in the price charged for the oil taken in kind to reflect the value of the oil at the delivery point. Arrangements for delivery of the royalty oil from, or exchange of the oil at, the delivery point, and related transportation costs, are the responsibility of the purchaser of the royalty oil. In addition, quality differentials between the royalty oil to which a purchaser is entitled and the oil which is made available at the delivery point are matters to be resolved between the purchaser and the operator.

(c) When the purchaser has physical access to the royalty oil at the delivery point, the lessee shall deliver such oil in marketable condition at pipeline connections or other facilities designated by ONRR. If the lessee is unable to provide the royalty portion of actual production from the lease, the lessee must provide crude oil to the purchaser which is equivalent in volume or value to the royalty oil to which the purchaser is entitled. The lessee will deliver the royalty oil to the purchaser during normal operating hours and in reasonable quantities and intervals. The lessee will make available and the purchaser will accept delivery of the royalty oil entitlement no later than the last day of the calendar month immediately following the calendar month in which the oil was produced. Failure to accept deliveries shall constitute grounds for the termination of the contract.

(d) Upon termination of deliveries under a royalty oil contract, the transportation allowance and delivery point designation authorized by this section no longer will remain in effect.

§ 1208.9 Agreements.

(a) A purchaser must submit to ONRR two copies of any written third-party agreements, or two copies of a full written explanation of any oral third-party agreements, relating to the method and costs of delivery of royalty oil, or crude oil exchanged for the royalty oil, from the point of delivery under the contract to the purchaser's refinery. In addition, the purchaser must submit copies of agreements pertaining to quality differentials which may occur between leases and delivery points.

(b) A purchaser may not sell royalty oil which it purchases pursuant to this part except for purposes of an exchange for other crude oil on a volume or equivalent value basis.

(c) Royalty oil purchased under this part, or crude oil received in exchange for such royalty oil, must be processed into refined petroleum products in the purchaser's refinery.

§ 1208.10 Notices.

(a) The ONRR shall notify each operator, by certified mail, of the Secretary's decision to take royalty oil in kind. This notice shall be mailed at least 45 days in advance of the effective date of delivery and will specify delivery points for offshore oil for OCS leases issued after September 1969.

(b) Deliveries of royalty oil may be partially terminated only with the written approval of the Director, ONRR.

(c) Before terminating the delivery of royalty oil taken in kind, ONRR, if possible, will notify each operator by certified mail of the change in requirements at least 30 days in advance of the effective date.

(d) After ONRR notification that royalty oil will be taken in kind, the operator shall be responsible for notifying each working interest on the Federal lease. As soon as practicable after the date of each royalty oil sale, ONRR will publish in the Federal Register a notice of the leases from which royalty oil will be taken, the purchasers of the royalty oil, and the leases from which royalty oil deliveries will be discontinued on terminated contracts.

(e) A purchaser cannot transfer, assign, or sell its rights or interest in a royalty oil contract without written approval of the Director, ONRR. If the purchaser changes ownership or its assets are sold or liquidated for any reason, it cannot transfer, assign, or sell its rights or interest in the royalty oil contract without written approval of the Director, ONRR. Without express written consent from ONRR for a change in ownership, the royalty oil contract shall be terminated. The successor company must meet the definition of an eligible refiner in § 1208.2 of this part for ONRR to consider assignment of the royalty oil contract.

§ 1208.11 Surety requirements.

(a) The eligible purchaser, prior to execution of the contract, shall furnish an “ONRR-specified surety instrument,” in an amount equal to the estimated value of royalty oil that could be taken by the purchaser in a 99-day period, plus related administrative charges. The ONRR may require the purchaser to increase the amount of the surety instrument when necessary to protect the Government's interest or may allow the purchaser to decrease the amount of the surety instrument where necessary to further the purposes of the Royalty-in-Kind Program.

(b) If a letter of credit is furnished as the surety instrument, it must be effective for a 9-month period beginning the first day the royalty oil contract is effective, with a clause providing for automatic renewal monthly for a new 9-month period. The purchaser or its surety company may elect not to renew the letter of credit at any monthly anniversary date, but must notify ONRR of its intent not to renew at least 30 days prior to the anniversary date. The ONRR may grant the purchaser 45 days to obtain a new surety instrument. If no replacement surety instrument is provided, ONRR will terminate the contract effective at least 6 months prior to the expiration date of the letter of credit. Notwithstanding the above provisions, the letter of credit also may contain a clause providing for automatic termination 6 months after the royalty oil contract terminates. If a certificate of deposit is furnished as the surety instrument, it must be effective for the life of the contract plus 6 months after the royalty oil contract terminates.

(c) For the purposes of this section, an “ONRR-specified surety instrument” means either: an ONRR-specified surety bond, an ONRR-specified irrevocable letter of credit, or a financial institution book-entry certificate of deposit.

(d) The “ONRR-specified surety instrument” shall be in a form specified by ONRR instructions or approved by ONRR. A bond must be issued by a qualified surety company that has been approved by the Department of the Treasury. An irrevocable letter of credit or a certificate of deposit must be from a financial institution acceptable to ONRR. The ONRR will use a bank rating service to determine whether a financial institution has an acceptable rating to provide a surety instrument deemed adequate to indemnify the Government from loss or damage.

(e) All surety instruments must be in a form acceptable to ONRR and must include such other specific requirements as ONRR may require adequately to protect the Government's interests.

[58 FR 64901, Dec. 10, 1993]

§ 1208.12 Payment requirements.

(a) All payments to ONRR by a purchaser of royalty oil will be due on the date and at the location specified in the contract, or, if there is no contractual provision, as specified by ONRR. The purchaser shall tender all payments to ONRR in accordance with § 1218.51 of this chapter. Payments made by a payor pursuant to the requirements of paragraph (b) of this section and § 1208.13 also shall be tendered in accordance with § 1218.51 of this chapter.

(b)(1) Payments from a purchaser of royalty oil not received by ONRR when due, or that portion of the payment less than the full amount due, will be subject to a late payment charge equivalent to an interest assessment on the amount past due for the number of days that the payment is late at the underpayment rate applicable under section 6621 of the Internal Revenue Code of 1954.

(2) The ONRR may assess interest to a payor for any underpayments which are the result of the payor's late or underreporting, or for adjustments reported by the payor, or made as a result of audit, reconciliation, or other procedures. The interest for late payment and underpayment will be assessed pursuant to § 1218.54 of this chapter.

(c) If payment for royalty oil is not received by the due date specified in the contract, a notice of nonreceipt will be sent to the purchaser by certified mail. If payment is not received by ONRR within 15 days from the date of such notice, ONRR may cancel the contract and collect under the ONRR-specified surety instrument. See § 1208.11.

(d) If the purchaser disagrees with the amount of payment due, it must pay the amount due as computed by ONRR, unless the purchaser appeals the amount and posts an ONRR-specified surety instrument pursuant to the provisions of 30 CFR part 1243. The ONRR may, at its discretion, waive the appeal surety requirements if it determines that the contract surety instrument is sufficient protection for an amount under appeal.

[52 FR 41913, Oct. 30, 1987, as amended at 64901, Dec. 10, 1993]

§ 1208.13 Reporting requirements.

If ONRR underbills a purchaser under a royalty oil contract because of a payor's underreporting or failure to report on Form MMS-2014 pursuant to § 1210.52 of this chapter, the payor will be liable for payment of such underbilled amounts plus interest if they are unrecoverable from the purchaser or the surety instrument related to the contract.

[58 FR 64902, Dec. 10, 1993]

§ 1208.14 Civil and criminal penalties.

Failure to abide by the regulations in this part may result in civil and criminal penalties being levied on that person as specified in sections 109 and 110 of the Federal Oil and Gas Royalty Management Act of 1982, 30 U.S.C. 1719-20, and regulations at 30 CFR part 241. Civil penalties applicable under the OCSLA and the Mineral Leasing Act of 1920 may also be imposed.

§ 1208.15 Audits.

Audits of the accounts and books of lessees, operators, payors, and/or purchasers of royalty oil taken in kind may be made annually or at such other times as may be directed by ONRR. Such audits will be for the purpose of determining compliance with applicable statutes, regulations, and royalty oil contracts. ONRR may require you to provide records for the audit by one or more of the methods specified in 30 CFR 1217.10.

[88 FR 53793, Aug. 9, 2023]

§ 1208.16 How to appeal a contracting officer's decision that you receive.

If you receive a contracting officer's decision, you may:

(a) Appeal that decision to the Board of Contract Appeals in the Office of Hearings and Appeals, Office of the Secretary, in accordance with the procedures provided in 43 CFR part 4, subpart C; or

(b) File an action in the United States Court of Federal Claims.

[64 FR 26251, May 13, 1999]

§ 1208.17 Suspensions for national emergencies.

The Secretary of the Department of the Interior, upon a recommendation by the Secretary of Defense or the Secretary of Energy and with the approval of the President, may suspend operations under these regulations and suspend royalty oil contracts during a national emergency declared by the Congress or the President.

§ 1210.01 What is the purpose of this subpart?

This subpart identifies information collections required by the Office of Natural Resources Revenue (ONRR), in the normal course of operations. This information is submitted by various parties associated with Federal and Indian leases such as lessees, designees, and operators. The information collected meets the ONRR congressionally mandated accounting and auditing responsibilities relating to Federal and Indian minerals revenue management. Information collected regarding production, royalties, and other payments due the Government from activities on leased Federal or Indian land is authorized by the Federal Oil and Gas Royalty Management Act of 1982, as amended (30 U.S.C. 1701 et seq.), as well as 43 U.S.C. 1334 and 30 U.S.C. 189, 359, 396, and 396d for oil and gas production; and by 30 U.S.C. 189, 359, 396, and 396d for solid minerals production.

§ 1210.02 To whom do these regulations apply?

The regulations apply to any person, referred to in this subpart as “you,” “your,” or “reporter/payor,” who is a lessee under any Federal or Indian lease for any mineral or who is assigned or assumes an obligation to report data or make payment to ONRR. The term reporter/payor may include lessees, designees, operators, purchasers, reporters, other payors, and working interest owners, but is not restricted to these parties. This section does not affect the liability to pay and report royalties as established by other regulations, laws, and the lease terms.

§ 1210.10 What are the OMB-approved information collections?

The information collection requirements identified in this subpart have been approved by the Office of Management and Budget (OMB) under 44 U.S.C. 3501 et seq. Detailed information about each information collection request (ICR), including CFR citations, is included on the ONRR Web site at http://www.onrr.gov/Laws_R_D/FRNotices/FRInfColl.htm-. The ICRs and associated ONRR form numbers, if applicable, are listed below:

OMB Control number and short title | Form or information collected

1012-0001, CFO Act of 1992, Accounts Receivable Confirmations | No form for the following collection: • Accounts receivable confirmations

1012-0002, 30 CFR Parts 1202, 1206, and 1207, Indian Oil and Gas Valuation | Form ONRR-4109, Gas Processing Allowance Summary Report Form ONRR-4110, Oil Transportation Allowance Report Form ONRR-4295, Gas Transportation Allowance Report

Form ONRR-4393, Request to Exceed Regulatory Allowance Limitation 1

Form ONRR-4410, Accounting for Comparison [Dual Accounting]

Form ONRR-4411, Safety Net Report

1012-0003, 30 CFR Parts 1227, 1228, and 1229, Delegated and Cooperative Activities with States and Indian Tribes | No forms for the following collections: • Written delegation proposal to perform auditing and investigative activities • Request for cooperative agreement and subsequent requirements

1012-0004, 30 CFR Parts 1210 and 1212, Royalty and Production Reporting | Form ONRR-2014, Report of Sales and Royalty Remittance Form ONRR-4054 (Parts A, B, and C), Oil and Gas Operations Report Form ONRR-4058, Production Allocation Schedule Report

1012-0005, 30 CFR Parts 1202, 1204, 1206, and 1210, Federal Oil and Gas Valuation | Form ONRR-4377, Stripper Royalty Rate Reduction Notification Form ONRR-4393, Request to Exceed Regulatory Allowance Limitation 1

No form for the following collection: • Federal oil valuation support information

1012-0006, 30 CFR Part 1243, Suspensions Pending Appeal and Bonding | Form ONRR-4435, Administrative Appeal Bond Form ONRR-4436, Letter of Credit Form ONRR-4437, Assignment of Certificate of Deposit

No forms for the following collections: • Self bonding • U.S. Treasury securities

1012-0008, 30 CFR Part 1218, Collection of Monies Due the Federal Government | Form ONRR-4425, Designation Form for Royalty Payment Responsibility

No forms for the following collections: • Cross-lease netting documentation • Indian recoupment approval

1012-0009, 30 CFR Part 1220, OCS Net Profit Share Payment Reporting | No form for the following collection: • Net profit share payment information

1012-0010, 30 CFR Parts 1202, 1206, 1210, 1212, 1217, and 1218, Solid Minerals and Geothermal Resources Collections | Form ONRR-4430, Solid Minerals Production and Royalty Report Form ONRR-4292, Coal Washing Allowance Report Form ONRR-4293, Coal Transportation Allowance Report

No forms for the following collections: • Facility data—solid minerals • Sales contracts—solid minerals • Sales summaries—solid minerals

1 Lessees use Form ONRR-4393 for both Federal and Indian oil and gas leases. The form resides with ICR 1012-0005, but ONRR includes the burden hours for Indian leases in ICR 1012-0002.

[73 FR 15892, Mar. 26, 2008, as amended at 73 FR 58875, Oct. 8, 2008; 76 FR 76615, Dec. 8, 2011; 78 FR 30204, May 22, 2013]

§ 1210.20 What if I disagree with the burden hour estimates?

Burden hour estimates are included on the ONRR Web site at http://www.onrr.gov/Laws_R_D/FRNotices/FRInfColl.htm-. Send comments on the accuracy of these burden estimates or suggestions on reducing the burden to the Office of Natural Resources Revenue, Attention: Rules & Regs Team. 1012-XXXX P.O. Box 25165, Denver, CO 80225-0165. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number.

[73 FR 15892, Mar. 26, 2008, as amended at 74 FR 46907, Sept. 14, 2009; 76 FR 76615, Dec. 8, 2011]

§ 1210.21 How do I report my taxpayer identification number?

(a) Before paying or reporting to ONRR, you must obtain a payor code (see the ONRR Minerals Revenue Reporter Handbook, which is available on the Internet at http://www.onrr.gov/FM/Handbooks/default.htm; also see § 1210.56 for further information on how to obtain a handbook). At the time you request a payor code, you must provide your Employer Identification Number (EIN) by submitting:

(1) An IRS Form W-9; or

(2) An equivalent certification containing:

(i) Your name;

(ii) The name of your business, if different from your name;

(iii) The form of your business entity; for example, a sole proprietorship, corporation, or partnership;

(iv) The address of your business;

(v) The EIN of your business; and

(vi) A signed and dated certification that you are a U.S. citizen or resident alien and that the EIN number provided is correct.

(b) If you are already paying or reporting to ONRR but do not have an EIN, ONRR may request that you submit an IRS Form W-9 or equivalent certification containing the information required under paragraph (a)(2) of this section.

(c) The collection of this data is not subject to the provisions of the Paperwork Reduction Act because only information necessary to identify the respondent [5 CFR 1320.3(h)] is required.

(d) The EIN you provide to ONRR under paragraph (a) of this section:

(1) Means the taxpayer identification number (TIN) of an individual or other person (whether or not an employer), which is assigned under 26 U.S.C. 6011(b), or a corresponding version of prior law, or under 26 U.S.C. 6109;

(2) Must contain nine digits separated by a hyphen as follows: 00-0000000; and

(3) May not be a Social Security Number.

[48 FR 35641, Aug. 5, 1983, as amended at 76 FR 76615, Dec. 8, 2011]

§ 1210.30 What are my responsibilities as a reporter/payor?

Each reporter/payor must submit accurate, complete, and timely information to ONRR according to the requirements in this part. If you discover an error in a previous report, you must file an accurate and complete amended report within 30 days of your discovery of the error. If you do not comply, ONRR may assess civil penalties under 30 CFR part 1241.

§ 1210.40 Will ONRR keep the information I provide confidential?

The ONRR will treat information obtained under this part as confidential to the extent permitted by law as specified at 43 CFR part 2.

§ 1210.50 What is the purpose of this subpart?

The purpose of this subpart is to explain royalty reporting requirements when energy and mineral resources are removed from Federal and Indian oil and gas and geothermal leases and federally approved agreements. This includes leases and agreements located onshore and on the Outer Continental Shelf (OCS).

§ 1210.51 Who must submit royalty reports?

(a) Any person who pays royalty to ONRR must submit royalty reports to ONRR.

(b) Before you pay or report to ONRR, you must obtain a payor code. To obtain a payor code, refer to the ONRR Minerals Revenue Reporter Handbook for instructions and ONRR contact information (also see § 1210.56 for information on how to obtain a handbook).

§ 1210.52 What royalty reports must I submit?

You must submit a completed Form ONRR-2014, Report of Sales and Royalty Remittance, to ONRR with:

(a) All royalty payments; and

(b) Rents on nonproducing leases, where specified in the lease.

§ 1210.53 When are my royalty reports and payments due?

(a) Completed Forms ONRR-2014 for royalty payments and the associated payments are due by the end of the month following the production month (see also § 1218.50 of this chapter).

(b) Completed Forms ONRR-2014 for rental payments, where applicable, and the associated payments are due as specified by the lease terms (see also § 1218.50 of this chapter).

(c) You may submit reports and payments early.

§ 1210.54 Must I submit this royalty report electronically?

(a) You must submit Form ONRR-2014 electronically unless you qualify for an exception under § 1210.55(a).

(b) As of December 31, 2011, all reporters/payors must report to ONRR electronically via the eCommerce Reporting Web site. All reporters/payors also must report royalty data directly or upload files using the ONRR electronic web form located at https://onrrreporting.onrr.gov. You must upload your files in one of the following formats: The American Standard Code for information interchange (ASCII) or Comma Separated Values (CSV) formats. You must create your external files in the proprietary ASCII and CSV file layout formats defined by ONRR. You can generate these external files from your system application. Reporters/payors also can access detailed information and instructions regarding how to use the eCommerce Reporting Web site at http://www.onrr.gov/FM/PDFDocs/eCommerce_FAQ.pdf.

(c) Refer to our electronic reporting guidelines in the ONRR Minerals Revenue Reporter Handbook, for the most current reporting options, instructions, and security measures. The handbook may be found on our Internet Web site or you may call your ONRR customer service representative (see § 1210.56 for further information on how to obtain a handbook).

[73 FR 15892, Mar. 26, 2008, as amended at 77 FR 25879, May 2, 2012]

§ 1210.55 May I submit this royalty report manually?

(a) The ONRR will allow you to submit Form ONRR-2014 manually if:

(1) You have never reported to ONRR before. You have 3 months from the date your first report is due to begin reporting electronically;

(2) You report only rent, minimum royalty, or other annual obligations on Form ONRR-2014; or

(3) You are a small business, as defined by the U.S. Small Business Administration, and you have no computer.

(b) If you meet the qualifications under paragraph (a) of this section, you may submit your form manually to ONRR by:

(1) U.S. Postal Service regular or express mail addressed to Office of Natural Resources Revenue, P.O. Box 25627, Denver, CO 80225-0627; or

(2) Special courier or overnight mail addressed to Office of Natural Resources Revenue, Building 85, Room A322, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.

[73 FR 15892, Mar. 26, 2008, as amended at 77 FR 25879, May 2, 2012; 87 FR 21745, Apr. 13, 2022]

§ 1210.56 Where can I find more information on how to complete the royalty report?

(a) Refer to the ONRR Minerals Revenue Reporter Handbook for specific guidance on how to prepare and submit Form ONRR-2014. You may find the handbook at http://www.onrr.gov/FM/Handbooks/default.htm or from the contacts on that Web page.

(b) Reporters/payors should refer to the handbook for specific guidance on royalty reporting requirements. If you require additional information, you should contact ONRR at the above address. A customer service telephone number is also listed in our handbook.

(c) You may find Form ONRR-2014 at http://www.onrr.gov/FM/Forms/AFSOil_Gas.htm or from contacts listed on that Web page.

[48 FR 35641, Aug. 5, 1983, as amended at 76 FR 76615, Dec. 8, 2011; 77 FR 25879, May 2, 2012]

§ 1210.60 What definitions apply to this subpart?

Terms used in this subpart have the same meaning as in 30 U.S.C. 1702.

§ 1210.61 What additional reporting requirements must I meet for Indian oil valuation purposes?

(a) If you must report and pay under § 1206.52 of this chapter, you must use Sales Type Code ARMS on Form ONRR-2014.

(b) If you must report and pay under § 1206.53 of this chapter, you must use Sales Type Code NARM on Form ONRR-2014.

(c) If you must report and pay under § 1206.54 of this chapter, you must use Sales Type Code OINX on Form ONRR-2014.

(d) You must report one of the following crude oil types in the product code field of Form ONRR-2014:

(1) Sweet (code 61);

(2) Sour (code 62);

(3) Asphaltic (code 63);

(4) Black Wax (code 64); or

(5) Yellow Wax (code 65).

(e) All of the remaining requirements of this subpart apply.

[80 FR 24814, May 1, 2015]

§ 1210.100 What is the purpose of this subpart?

The purpose of this subpart is to explain production reporting requirements when energy and mineral resources are removed from Federal and Indian oil and gas leases and federally approved agreements. This includes leases and unit and communitization agreements located onshore and on the Outer Continental Shelf (OCS).

§ 1210.101 Who must submit production reports?

(a) If you operate a Federal or Indian oil and gas lease or federally approved unit or communitization agreement, you must submit production reports.

(b) Before reporting production to ONRR, you must obtain an operator number. To obtain an operator number, refer to the ONRR Minerals Production Reporter Handbook for instructions and ONRR contact information (also see § 1210.106 for information on how to obtain a handbook).

§ 1210.102 What production reports must I submit?

(a) Form ONRR-4054, Oil and Gas Operations Report. If you operate a Federal or Indian onshore or OCS oil and gas lease or federally approved unit or communitization agreement that contains one or more wells that are not permanently plugged or abandoned, you must submit Form ONRR-4054 to ONRR:

(1) You must submit Form ONRR-4054 for each well for each calendar month, beginning with the month in which you complete drilling, unless:

(i) You have only test production from a drilling well; or

(ii) The ONRR tells you in writing to report differently.

(2) You must continue reporting until:

(i) The Bureau of Land Management (BLM) or ONRR approves all wells as permanently plugged or abandoned or the lease or unit or communitization agreement is terminated; and

(ii) You dispose of all inventory.

(b) Form ONRR-4058, Production Allocation Schedule Report. If you operate an offshore facility measurement point (FMP) handling production from a Federal oil and gas lease or federally approved unit agreement that is commingled (with approval) with production from any other source prior to measurement for royalty determination, you must file Form ONRR-4058.

(1) You must submit Form ONRR-4058 for each calendar month beginning with the month in which you first handle production covered by this section.

(2) Form ONRR-4058 is not required whenever all of the following conditions are met:

(i) All leases involved are Federal leases;

(ii) All leases have the same fixed royalty rate;

(iii) All leases are operated by the same operator;

(iv) The facility measurement device is operated by the same person as the leases/agreements;

(v) Production has not been previously measured for royalty determination; and

(vi) The production is not subsequently commingled and measured for royalty determination at an FMP for which Form ONRR-4058 is required under this part.

§ 1210.103 When are my production reports due?

(a) The ONRR must receive your completed Forms ONRR-4054 and ONRR-4058 by the 15th day of the second month following the month for which you are reporting.

(b) A report is considered received when it is delivered to ONRR by 4 p.m. mountain time at the addresses specified in § 1210.105. Reports received after 4 p.m. mountain time are considered received the following business day.

§ 1210.104 Must I submit these production reports electronically?

(a) You must submit Forms ONRR-4054 and ONRR-4058 electronically unless you qualify for an exception under § 1210.105.

(b) As of December 31, 2011, all reporters/payors must report to ONRR electronically via the eCommerce Reporting Web site. All reporters/payors also must report production data directly or upload files using the ONRR electronic web form located at https://onrrreporting.onrr.gov. You must upload your files in one of the following formats: The American Standard Code for information interchange (ASCII) or Comma Separated Values (CSV) formats. You must create your external files in the proprietary ASCII and CSV file layout formats defined by ONRR. You can generate these external files from your system application. Reporters/payors also can access detailed information and instructions regarding how to use the eCommerce Reporting Web site at http://www.onrr.gov/FM/PDFDocs/eCommerce_FAQ.pdf.

(c) Refer to our electronic reporting guidelines in the ONRR Minerals Production Reporter Handbook for the most current reporting options, instructions, and security measures. The handbook may be found on our Internet Web site or you may call your ONRR customer service representative (see § 1210.106 for further information on how to obtain a handbook).

[73 FR 15892, Mar. 26, 2008, as amended at 77 FR 25880, May 2, 2012]

§ 1210.105 May I submit these production reports manually?

(a) The ONRR will allow you to submit Forms ONRR-4054 and ONRR-4058 manually if:

(1) You have never reported to ONRR before. You have 3 months from the day your first report is due to begin reporting electronically; and

(2) You are a small business, as defined by the U.S. Small Business Administration, and you have no computer.

(b) If you meet the qualifications under paragraph (a) of this section, you may submit your forms manually to ONRR by:

(1) U.S. Postal Service regular or express mail addressed to Office of Natural Resources Revenue, P.O. Box 25627, Denver, CO 80225-0627; or

(2) Special courier or overnight mail addressed to Office of Natural Resources Revenue, Building 85, Room A322, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.

[73 FR 15892, Mar. 26, 2008, as amended at 77 FR 25879, May 2, 2012; 87 FR 21745, Apr. 13, 2022]

§ 1210.106 Where can I find more information on how to complete these production reports?

(a) Refer to the ONRR Minerals Production Reporter Handbook for specific guidance on how to prepare and submit Forms ONRR-4054 and ONRR-4058. You may find the handbook at http://www.onrr.gov/FM/Handbooks/default.htm or from contacts listed on that Web page.

(b) Production reporters should refer to the handbook for specific guidance on production reporting requirements. If you require additional information, you should contact ONRR at the above address. A customer service telephone number is also listed in our handbook.

(c) You may find Forms ONRR-4054 and ONRR-4058 at http://www.onrr.gov/FM/Forms/AFSOil_Gas.htm or from contacts listed on that Web page.

[48 FR 35641, Aug. 5, 1983, as amended at 76 FR 76615, Dec. 8, 2011; 77 FR 25880, May 2, 2012]

§ 1210.150 What is the purpose of this subpart?

This subpart identifies specific special-purpose reports and provides general information, reporting options, and reporting addresses. See § 1210.10 for a complete listing of all information collections, including forms and references for specific information collections.

§ 1210.151 What reports must I submit to claim an excess allowance?

(a) General. If you are a lessee, you must submit Form ONRR-4393, Request to Exceed Regulatory Allowance Limitation, to request approval from ONRR to exceed prescribed transportation and processing allowance limits on Federal oil and gas leases and prescribed transportation allowance limits on Indian oil and gas leases under part 1206 of this chapter.

(b) Reporting options. You may find Form ONRR-4393 at http://www.onrr.gov/FM/Forms/AFSOil_Gas.htm or from contacts listed on that Web page.

(c) Reporting address. Submit completed Form ONRR-4393 as follows:

(1) Complete and submit the form electronically as an email attachment to royaltyvaluation@onrr.gov;

(2) Send the form by U.S. Postal Service regular or express mail addressed to Office of Natural Resources Revenue, P.O. Box 25165, MS 643000B, Denver, CO 80225-0165; or

(3) Deliver the form to ONRR by special courier or overnight mail addressed to Office of Natural Resources Revenue, Building 85, Room A322, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.

[48 FR 35641, Aug. 5, 1983, as amended at 76 FR 76615, Dec. 8, 2011; 77 FR 25879, 25880, May 2, 2012; 87 FR 21745, Apr. 13, 2022]

§ 1210.152 What reports must I submit to claim allowances on an Indian lease?

(a) General. You must submit three additional forms to ONRR to claim transportation or processing allowances on Indian oil and gas leases:

(1) You must submit Form ONRR-4110, Oil Transportation Allowance Report, to claim an allowance for expenses incurred by a reporter/payor to transport oil from the lease site to a point remote from the lease where value is determined under § 1206.55 of this chapter.

(2) You must submit Form ONRR-4109, Gas Processing Allowance Summary Report, to claim an allowance for the reasonable, actual costs of removing hydrocarbon and nonhydrocarbon elements or compounds from a gas stream under § 1206.180 of this chapter.

(3) You must submit Form ONRR-4295, Gas Transportation Allowance Report, to claim an allowance for the reasonable, actual costs of transporting gas from the lease to the point of first sale under § 1206.178 of this chapter.

(b) Reporting options. You must submit Forms ONRR-4110, ONRR-4109, and ONRR-4295 manually. You may find the forms at http://www.onrr.gov/FM/Forms/AFSOil_Gas.htm or from contacts listed on that Web page.

(c) Reporting address. You may submit completed Forms ONRR-4110, ONRR-4109, and ONRR-4295 by:

(1) U.S. Postal Service regular or express mail addressed to Office of Natural Resources Revenue, P.O. Box 25165, MS 634000B, Denver, CO 80225-0165;

(2) Special courier or overnight mail addressed to Office of Natural Resources Revenue, Building 85, Room A322, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225; or

(3) Complete and submit the form electronically as an email attachment to onrrindianforms@onrr.gov.

[48 FR 35641, Aug. 5, 1983, as amended at 76 FR 76615, Dec. 8, 2011; 77 FR 25879, 25880, May 2, 2012; 87 FR 21745, Apr. 13, 2022]

§ 1210.153 What reports must I submit for Indian gas valuation purposes?

(a) General. For Indian gas valuation, under certain conditions under § 1206.172 of this chapter, lessees must submit the following forms:

(1) Form ONRR-4410, Accounting for Comparison (Dual Accounting), Part A or part B; and/or

(2) Form ONRR-4411, Safety Net Report.

(b) Reporting options. You must submit Forms ONRR-4410 and ONRR-4411 manually. You may find the forms at http://www.onrr.gov/FM/Forms/AFSOil_Gas.htm or from contacts listed on that Web page.

(c) Reporting address. You must submit completed Forms ONRR-4410 and ONRR-4411 by:

(1) U.S. Postal Service regular or express mail addressed to Office of Natural Resources Revenue, P.O. Box 25165, MS 634000B, Denver, CO 80225-0165;

(2) Special courier or overnight mail addressed to Office of Natural Resources Revenue, Building 85, Room A322, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225; or

(3) Complete and submit the form electronically as an email attachment to onrrindianforms@onrr.gov.

[48 FR 35641, Aug. 5, 1983, as amended at 76 FR 76615, Dec. 8, 2011; 77 FR 25879, 25880, May 2, 2012; 87 FR 21745, 21746, Apr. 13, 2022]

§ 1210.154 What documents or other information must I submit for Federal oil valuation purposes?

(a) General. The ONRR may require you to submit documents or other information to ONRR to support your valuation of Federal oil under part 1206 as part of audit compliance.

(b) Reporting options. You must submit the documents or other information manually.

(c) Reporting address. You must submit required documents or other information by:

(1) U.S. Postal Service regular or express mail addressed to Office of Natural Resources Revenue, P.O. Box 25165, MS 63240B, Denver, CO 80225-0165; or

(2) Special courier or overnight mail addressed to Office of Natural Resources Revenue, Building 85, Room A322, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.

[73 FR 15892, Mar. 26, 2008, as amended at 77 FR 25879, May 2, 2012; 87 FR 21745, Apr. 13, 2022]

§ 1210.155 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 ONRR-4377, Stripper Royalty Rate Reduction Notification, under 43 CFR 3103.4-2(b)(3).

(b) Reporting options. You may find Form ONRR-4377 at http://www.onrr.gov/FM/Forms/AFSOil_Gas.htm. You may file the form:

(1) Electronically by filling the form out in electronic format and submitting it to ONRR as an e-mail attachment; or

(2) Manually by filling out the form and submitting it by:

(i) U.S. Postal Service regular or express mail addressed to Office of Natural Resources Revenue (ONRR), P.O. Box 25165, Denver, CO 80225-0165; or

(ii) Special courier or overnight mail addressed to Office of Natural Resources Revenue, Building 85, Room A-614, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.

[48 FR 35641, Aug. 5, 1983, as amended at 76 FR 76615, Dec. 8, 2011; 77 FR 25879, 25880, May 2, 2012]

§ 1210.156 What reports must I submit for net profit share leases?

(a) General. After entering into a net profit share lease (NPSL) agreement, a lessee must report under part 1220 of this chapter.

(b) Reporting options. You must submit the required report manually.

(c) Reporting address. You must submit the required documents by:

(1) U.S. Postal Service regular or express mail addressed to Office of Natural Resources Revenue, P.O. Box 25165, MS 633000B, Denver, CO 80225-0165; or

(2) Special courier or overnight mail addressed to Office of Natural Resources Revenue, Building 85, Room A322, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.

[73 FR 15892, Mar. 26, 2008, as amended at 77 FR 25879, May 2, 2012; 87 FR 21745, Apr. 13, 2022]

§ 1210.157 What reports must I submit to suspend an ONRR order under appeal?

(a) General. Reporters/payors or other recipients of ONRR Office of Natural Resources (MRM) Revenue orders who appeal an order may be required to post a bond or other surety, under part 1243 of this chapter. The ONRR accepts the following surety types: Form ONRR-4435, Administrative Appeal Bond; Form ONRR-4436, Letter of Credit; Form ONRR-4437, Assignment of Certificate of Deposit; Self-bonding; and U.S. Treasury Securities.

(b) Reporting options. You must submit these forms and other documents manually. You may find the forms and other documents under Surety Instrument Posting Instructions on our Internet Web site at http://www.onrr.gov/Laws_R_D/FRNotices/ICR0122.htm.

(c) Reporting address. You may submit the required forms and other documents as specified in the Surety Instrument Posting Instructions or by:

(1) U.S. Postal Service regular or express mail addressed to Office of Natural Resources Revenue, P.O. Box 25165, MS 63230B, Denver, CO 80225-0165;

(2) Special courier or overnight mail addressed to Office of Natural Resources Revenue, Building 85, Room A322, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.

[48 FR 35641, Aug. 5, 1983, as amended at 76 FR 76615, Dec. 8, 2011; 77 FR 25879, May 2, 2012; 87 FR 21745, Apr. 13, 2022]

§ 1210.158 What reports must I submit to designate someone to make my royalty payments?

(a) General. You must submit Form ONRR-4425, Designation Form for Royalty Payment Responsibility, if you want to designate a person to make royalty payments on your behalf under § 1218.52 of this chapter.

(b) Reporting options. You must submit Form ONRR-4425 manually. You may find the form at http://www.onrr.gov/FM/Forms/AFSOil_Gas.htm.

(c) Reporting address. You must submit completed Form ONRR-4425 by:

(1) U.S. Postal Service regular or express mail addressed to Office of Natural Resources Revenue, P.O. Box 25165, MS 633000B, Denver, CO 80225-0165; or

(2) Special courier or overnight mail addressed to Office of Natural Resources Revenue, Building 85, Room A322, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.

[48 FR 35641, Aug. 5, 1983, as amended at 76 FR 76615, Dec. 8, 2011; 77 FR 25879, 25880, May 2, 2012; 87 FR 21745, Apr. 13, 2022]

§ 1210.200 What is the purpose of this subpart?

This subpart explains your reporting requirements if you produce coal or other solid minerals from Federal or Indian leases. Included are your requirements for reporting production, sales, and royalties.

§ 1210.201 How do I submit Form ONRR-4430, Solid Minerals Production and Royalty Report?

(a) What to submit. (1) You must submit a completed Form ONRR-4430 for—

(i) Production of all coal and other solid minerals from any Federal or Indian lease;

(ii) Sale of any such mineral;

(iii) Any such mineral held in stockpile or inventory; and

(iv) Payment of rents (other than those for which you receive from ONRR a Courtesy Notice as defined in § 1218.51(a) of this chapter), minimum royalty, deferred bonus, advance royalty, minimum royalty payable in advance, settlements, recoupments, and other financial obligations.

(2) You must submit a completed Form ONRR-4430 for any product you sell from a remote storage site. If you sell from five or fewer remote storage sites, you must report sales from each site on separate Forms ONRR-4430. If you sell from more than five remote storage sites, you must total the data from all sites and report the summarized data on one Form ONRR-4430.

(3) Instructions for completing and submitting Form ONRR-4430 are available on our Internet reporting web site or you may contact us toll free at 1-888-201-6416.

(b) When to submit. (1) Unless your lease terms specify a different frequency for royalty payments, you must submit your Form ONRR-4430 on or before the end of the month following the month in which you produce any solid mineral, sell any solid mineral, or hold any solid mineral production in stockpile or inventory. However, if the last day of the month falls on a weekend or holiday, your Form ONRR-4430 is due on the next business day.

(2) If your lease terms specify a different frequency for royalty payment, then you must submit your Form ONRR-4430 on or before the date on which you must pay royalty under the terms of the lease.

(3) You must submit your Form ONRR-4430 for payment of rents (other than those for which you receive from ONRR a Courtesy Notice as defined in § 1218.51(a) of this chapter), minimum royalty, deferred bonus, advance royalty, minimum royalty payable in advance, settlements, recoupments, and other financial obligations on or before the date on which you must pay those obligations under the terms of the lease.

(4) If the information on a previously reported Form ONRR-4430 is no longer correct, you must submit a revised Form ONRR-4430 by the last day of the month in which you learn that the previously reported information is no longer correct, except when the last day of the month falls on a weekend or holiday. If the last day of the month falls on a weekend or holiday, your revised Form ONRR-4430 is due on the first business day of the following month.

(c) How to submit. (1) You must submit Form ONRR-4430 electronically using our Internet reporting web site unless you meet the conditions in paragraph (c)(2). We will provide written instructions and a valid login and password before you begin reporting.

(2) You are not required to report electronically if you are a small business as defined by the U.S. Small Business Administration (13 CFR 121.201) and you have no computer, no plans to purchase a computer, and no contract with an electronic reporting service.

(3) If you do not report electronically, you must submit the completed Form ONRR-4430 to us at one of the following addresses, unless ONRR publishes notice in the Federal Register giving a different address:

(i) For U.S. Postal Service regular mail or Express Mail: Office of Natural Resources Revenue (ONRR), P.O. Box 25165, MS 633000B, Denver, CO 80225-0165; or

(ii) For courier service or overnight mail (excluding Express Mail): Office of Natural Resources Revenue, Building 85, Denver Federal Center, Room A322, Denver, Colorado 80225.

[66 FR 45771, Aug. 30, 2001; 66 FR 50827, Oct. 5, 2001, as amended at 77 FR 25879, May 2, 2012; 87 FR 21745, Apr. 13, 2022]

§ 1210.202 How do I submit sales summaries?

(a) What to submit. (1) You must submit sales summaries for all coal and other solid minerals produced from Federal and Indian leases and for any remote storage site from which you sell Federal or Indian solid minerals. You do not have to submit a sales summary for those months in which you do not sell any Federal or Indian production.

(2) If you sell from five or fewer remote storage sites, you must submit a sales summary for each site. If you sell from more than five remote storage sites, you may total the data from all sites and submit the summarized data as one sales summary. The details you report on the sales summary are for the same sales reported on Form ONRR-4430.

(3) Use the following table to determine the time frames for submitting sales summaries and the data elements you must include. Your submitted sales summaries must include the following data but may be internally generated documents from your own records. You do not need to re-format them before submitting them to us:

Data element | Coal | Sodium/potassium | Western phosphate | Metals | All other leases with ad valorem royalty terms | All other leases with no ad valorem royalty terms

(i) Purchaser Name or Unique Identification | Monthly | Monthly | Monthly | Monthly | Monthly | As Requested

(ii) Sales Units | Monthly | Monthly | Monthly | Monthly | Monthly | Monthly

(iii) Gross Proceeds | Monthly | Monthly | Not Required | Monthly | Monthly | Not Required

(iv) Processing or washing costs | Monthly | Monthly | Not Required | Monthly | Monthly | Not Required

(v) Transportation costs | Monthly | Monthly | Not Required | Monthly | Monthly | Not Required

(vi) Name of product type sold | Not Required | Monthly | Not Required | Monthly | Monthly | As Requested

(vii) Btu/lb | Monthly | Not Required | Not Required | Not Required | Not Required | Not Required

(viii) Ash % | Monthly | Not Required | Not Required | Not Required | Not Required | Not Required

(ix) Sulfur % | Monthly | Not Required | Not Required | Not Required | Not Required | Not Required

(x) lbs SO2 | Monthly | Not Required | Not Required | Not Required | Not Required | Not Required

(xi) Moisture % | Monthly | Not Required | Monthly | Not Required | Not Required | Not Required

(xii) By-product Units | Not Required | As Requested | Monthly | As Requested | As Requested | Not Required

(xiii) P2O5 % | Not Required | Not Required | Monthly | Not Required | Not Required | Not Required

(xiv) Size | Not Required | Not Required | Not Required | Not Required | As Requested | Not Required

(xv) Net Smelter Return data | Not Required | Not Required | Not Required | Monthly | Not Required | Not Required

(xvi) Other Data e.g., Royalty Calculation Worksheet | As Requested | Monthly | As Requested | As Requested | As Requested | As Requested.

(b) When to submit. (1) For leases with ad valorem royalty terms (that is, leases for which royalty is a percentage of the value of production), you must submit your sales summaries monthly at the same time you submit Form ONRR-4430. You do not have to submit a sales summary for any month in which you did not sell Federal or Indian production.

(2) For leases with no ad valorem royalty terms (that is, leases in which the royalty due is not a function of the value of production, such as cents-per-ton or dollars-per-unit), you must submit monthly sales summaries only if we specifically request you to do so.

(c) How to submit. (1) You should provide the sales summary data via electronic mail where possible. We will provide instructions and the proper email address for these submissions.

(2) If you submit sales summaries by paper copy, mail them to one of the following addresses, unless ONRR publishes notice in the Federal Register giving a different address:

(i) For U.S. Postal Service regular mail or Express Mail: Office of Natural Resources Revenue, P.O. Box 25165, MS 633000B, Denver, CO 80225-0165.

(ii) For courier service or overnight mail (excluding Express Mail): Office of Natural Resources Revenue, MS 633000B, Room A322, Bldg. 85, DFC, Denver, Colorado 80225-0165.

[48 FR 35641, Aug. 5, 1983, as amended at 76 FR 76615, Dec. 8, 2011; 87 FR 21745, Apr. 13, 2022]

§ 1210.203 How do I submit sales contracts?

(a) What to submit. You must submit sales contracts, agreements, and contract amendments for the sale of all coal and other solid minerals produced from Federal and Indian leases with ad valorem royalty terms.

(b) When to submit. (1) For coal and metal production, you must submit the required documents semi-annually, no later than March 30 and September 30 of each year.

(2) For sodium, potassium, and phosphate production, and production from any other lease with ad valorem royalty terms, you must submit the required documents only if you are specifically requested to do so.

(c) How to submit. You must submit complete copies of the sales contracts and amendments to us at the applicable address given in § 1210.202(c)(2), unless ONRR publishes notice in the Federal Register giving a different address.

§ 1210.204 How do I submit facility data?

(a) What to submit. (1) You must submit facility data if you operate a wash plant, refining, ore concentration, or other processing facility for any coal, sodium, potassium, metals, or other solid minerals produced from Federal or Indian leases with ad valorem royalty terms, regardless of whether the facility is located on or off the lease.

(2) You do not have to submit facility data for those months in which you do not process solid minerals produced from Federal or Indian leases and do not have any such minerals in stockpile inventory.

(3) You must include in your facility data all production processed in the facility from all properties, not just production from Federal and Indian leases.

(4) Facility data submissions must include the following minimum information:

(i) Identification of your facility;

(ii) Mines served;

(iii) Input quantity;

(iv) Input quality or ore grade (except for coal);

(v) Output quantity; and

(vi) Output quality or product grades.

(5) Your submitted facility data may be internally generated documents from your own records. You do not need to re-format them before submitting them to us.

(b) When to submit. You must submit your facility data monthly at the same time you submit your Form ONRR-4430.

(c) How to submit. (1) You should provide the facility data via electronic mail where possible. We will provide instructions and the proper email address for these submissions before you begin reporting.

(2) If you submit facility data by paper copy, send it to the applicable address given in § 1210.202(c)(2).

§ 1210.205 What reports must I submit to claim allowances on Indian coal leases?

(a) General. You must submit the following ONRR forms to claim a transportation or washing allowance, as applicable, on Indian coal leases:

(1) Form ONRR-4292, Coal Washing Allowance Report, to claim an allowance for the reasonable, actual costs incurred to wash coal under § 1206.458 of this chapter.

(2) Form ONRR-4293, Coal Transportation Allowance Report, to claim an allowance for the reasonable, actual costs of transporting coal to a sales point or a washing facility remote from the mine or lease under § 1206.461 of this chapter.

(b) Reporting options. You must submit the forms manually. You may find the forms at http://www.onrr.gov/FM/Forms/AFSSol_Min.htm.

(c) Reporting address. You must submit completed Forms ONRR-4292 and ONRR-4293 by:

(1) U.S. Postal Service regular or express mail addressed to Office of Natural Resources Revenue, P.O. Box 25165, MS 633000B, Denver, CO 80225-0165;

(2) Special courier or overnight mail addressed to Office of Natural Resources Revenue, Building 85, Room A322, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225; or

(3) Complete and submit the form electronically as an email attachment to onrrindianforms@onrr.gov.

[73 FR 15897, Mar. 26, 2008, as amended at 76 FR 76615, Dec. 8, 2011; 77 FR 25879, 25880, May 2, 2012; 78 FR 30205, May 22, 2013; 87 FR 21745, 21746, Apr. 13, 2022]

§ 1210.206 Will I need to submit additional documents or evidence to ONRR?

(a) Federal and Indian lease terms allow us to request detailed statements, documents, or other evidence necessary to verify compliance with lease terms and conditions and applicable rules.

(b) We will request this additional information as we need it, not as a regular submission.

[66 FR 45771, Aug. 30, 2001. Redesignated at 73 FR 15897, Mar. 26, 2008]

§ 1210.207 How will information submissions be kept confidential?

Information submitted under this part that constitutes trade secrets or commercial and financial information that is identified as privileged or confidential, or that is exempt from disclosure under the Freedom of Information Act, 5 U.S.C. 552, shall not be available for public inspection or made public or disclosed without the consent of the lessee, except as otherwise provided by law or regulation.

[66 FR 45771, Aug. 30, 2001. Redesignated at 73 FR 15897, Mar. 26, 2008]

§ 1210.350 Definitions.

Terms used in this subpart shall have the same meaning as in § 1206.351 of this chapter.

§ 1210.351 Required recordkeeping.

Information required by ONRR shall be filed using the forms prescribed in this subpart, which are available from ONRR. Records may be maintained on microfilm, microfiche, or other recorded media that are easily reproducible and readable. See subpart H of 30 CFR part 1212.

§ 1210.352 Special forms and reports.

The ONRR may require submission of additional information on special forms or reports. When special forms or reports other than those referred to in this subpart are necessary, ONRR will give instructions for the filing of such forms or reports. Requests for the submission of such forms will be made in conformity with the requirements of the Paperwork Reduction Act of 1980 and other applicable laws.

[56 FR 57286, Nov. 8, 1991. Redesignated at 72 FR 24467, May 2, 2007]

§ 1210.353 Monthly report of sales and royalty.

You must submit a completed Report of Sales and Royalty Remittance (Form ONRR-2014) each month once sales or use of production occur, even though sales may be intermittent, unless ONRR otherwise authorizes. This report is due on or before the last day of the month following the month in which production was sold or used, together with the royalties due to the United States.

[78 FR 30206, May 22, 2013]

§ 1210.354 Reporting instructions.

Refer to ONRR's Minerals Revenue Reporter Handbook—Oil, Gas, and Geothermal Resources for specific guidance on how to prepare and submit required information collection reports and forms to ONRR. You may find the handbook at http://www.onrr.gov/FM/Handbooks/default.htm or from contacts listed on that Web page.

[77 FR 25880, May 2, 2012]

§ 1212.50 Required recordkeeping and reports.

All records pertaining to offshore and onshore Federal and Indian oil and gas leases shall be maintained by a lessee, operator, revenue payor, or other person for 6 years after the records are generated unless the recordholder is notified, in writing, that records must be maintained for a longer period. When an audit or investigation is underway, records shall be maintained until the recordholder is released by written notice of the obligation to maintain records.

[49 FR 37345, Sept. 21, 1984]

§ 1212.51 Records and files maintenance.

(a) Records. Each lessee, operator, revenue payor, or other person shall make and retain accurate and complete records necessary to demonstrate that payments of rentals, royalties, net profit shares, and other payments related to offshore and onshore Federal and Indian oil and gas leases are in compliance with lease terms, regulations, and orders. Records covered by this section include those specified by lease terms, notices and orders, and by the various parts of this chapter. Records also include computer programs, automated files, and supporting systems documentation used to produce automated reports or magnetic tape submitted to the Office of Natural Resources Revenue (ONRR).

(b) Period for keeping records. Lessees, operators, revenue payors, or other persons required to keep records under this section shall maintain and preserve them for 6 years from the day on which the relevant transaction recorded occurred unless the Secretary notifies the record holder of an audit or investigation involving the records and that they must be maintained for a longer period. When an audit or investigation is underway, records shall be maintained until the recordholder is released in writing from the obligation to maintain the records. Lessees, operators, revenue payors, or other persons shall maintain the records generated during the period for which they have paying or operating responsibility on the lease for a period of 6 years.

(c) Inspection of records. The lessee, operator, revenue payor, or other person required to keep records shall be responsible for making the records available for inspection. Records shall be provided at a business location of the lessee, operator, revenue payor, or other person during normal business hours upon the request of any officer, employee or other party authorized by the Secretary. Lessees, operators, revenue payors, and other persons will be given a reasonable period of time to produce historical records.

[49 FR 37345, Sept. 21, 1984; 49 FR 40576, Oct. 17, 1984, as amended at 67 FR 19111, Apr. 18, 2002]

§ 1212.52 Definitions.

Terms used in this subpart shall have the same meaning as in 30 U.S.C. 1702.

[49 FR 37345, Sept. 21, 1984]

§ 1212.200 Maintenance of and access to records.

(a) All records pertaining to Federal and Indian solid minerals leases shall be maintained by a lessee, operator, revenue payor, or other person for 6 years after the records are generated unless the record holder is notified, in writing, that records must be maintained for a longer period. When an audit or investigation is underway, records shall be maintained until the record holder is released by written notice of the obligation to maintain records.

(b) The ONRR shall have access to all records of the operator/lessee pertaining to compliance to Federal royalties, including, but not limited to:

(1) Qualities and quantities of all products mined, processed, sold, delivered, or used by the operator/lessee.

(2) Prices received for mined or processed products, prices paid for like or similar products, and internal transfer prices.

(3) Costs of mining, processing, handling, and transportation.

[47 FR 33193, July 30, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, and amended at 51 FR 15767, Apr. 28, 1986; 54 FR 1532, Jan. 13, 1989]

§ 1212.350 Definitions.

Terms used in this subpart shall have the same meaning as in § 1206.351.

§ 1212.351 Required recordkeeping and reports.

(a) Records. Each lessee, operator, revenue payor, or other person shall make and retain accurate and complete records necessary to demonstrate that payments of royalties, rentals, and other amounts due under Federal geothermal leases are in compliance with laws, lease terms, regulations, and orders. Records covered by this section include those specified by lease terms, notices, and orders, and those identified in paragraph (c) of this section. Records also include computer programs, automated files, and supporting systems documentation used to produce automated reports or magnetic tapes submitted to ONRR.

(b) Period for keeping records. All records pertaining to Federal geothermal leases shall be maintained by a lessee, operator, revenue payor, or other person for 6 years after the records are generated unless the recordholder is notified, in writing, before the expiration of that 6-year period that records must be maintained for a longer period for purposes of audit or investigation. When an audit or investigation is underway, records shall be maintained until the recordholder is released by written notice of the obligation to maintain records.

(c) Access to records. The Director for Office of Natural Resources Revenue shall have access to all records in the possession of the lessee, operator, revenue payor, or other person pertaining to compliance with royalty obligations under Federal geothermal leases (regardless of whether such records were generated more than 6 years before a request or order to produce them and they otherwise were not disposed of), including, but not limited to:

(1) Qualities and quantities of all products extracted, processed, sold, delivered, or used by the operator/lessee;

(2) Prices received for products, prices paid for like or similar products, and internal transfer prices; and

(3) Costs of extraction, power generation, electrical transmission, and byproduct transportation.

(d) Inspection of Records. The lessee, operator, revenue payor, or other person required to keep records shall be responsible for making the records available for inspection. Records shall be made available at a business location of the lessee, operator, revenue payor, or other person during normal business hours upon the request of any officer, employee, or other party authorized by the Secretary. Lessees, operators, revenue payors, and other persons will be given a reasonable period of time to produce records.

[56 FR 57286, Nov. 8, 1991, as amended at 67 FR 19111, Apr. 18, 2002]

§ 1217.10 Providing records during an audit.

(a) ONRR or an authorized State or Tribe may specify the method an auditee must use to provide records for all audits conducted under this chapter, statute, or agreement. The methods may include one or more of the following:

(1) Inspect records at an auditee's place of business during normal business hours;

(2) Send records using secure electronic means. When requesting that records be provided electronically, ONRR or the authorized State or Tribe will specify the format in which the records shall be produced, directions for electronic transmission, and instructions to ensure secure transmission; or

(3) Deliver hard copy records using the U.S. Postal Service, special courier, overnight mail, or other delivery service to an address specified by ONRR or an authorized State or Tribe.

(b) [Reserved]

§ 1217.50 Audits of records.

The Secretary, or his/her authorized representative, shall initiate and conduct audits relating to the scope, nature and extent of compliance by lessees, operators, revenue payors, and other persons with rental, royalty, net profit share and other payment requirements on a Federal or Indian oil and gas lease. Audits also will relate to compliance with applicable regulations and orders. All audits will be conducted in accordance with the notice and other requirements of 30 U.S.C. 1717.

§ 1217.51 Lease account reconciliation.

Specific lease account reconciliations shall be performed with priority being given to reconciling those lease accounts specifically identified by a State or Indian tribe as having significant potential for underpayment.

§ 1217.52 Definitions.

Terms used in this subpart shall have the same meaning as in 30 U.S.C. 1702.

§ 1217.200 Audits.

An audit of the accounts and books of operators/lessees for the purpose of determining compliance with Federal lease terms relating to Federal royalties may be required annually or at other times as directed by the Director for Office of Natural Resources Revenue. The audit shall be performed by a qualified independent certified public accountant or by an independent public accountant licensed by a State, territory, or insular possession of the United States or the District of Columbia, and at the expense of the operator/lessee. The operator/lessee shall furnish, free of charge, duplicate copies of audit reports that express opinions on such compliance to the Director for Office of Natural Resources Revenue within 30 days after the completion of each audit. Where such audits are required, the Director for Office of Natural Resources Revenue will specify the purpose and scope of the audit and the information which is to be verified or obtained.

[47 FR 33195, July 30, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, as amended at 67 FR 19112, Apr. 18, 2002]

§ 1217.250 Audits.

An audit of the lessee's accounts and books may be made annually or at such other times as may be directed by the mining supervisor, by certified public accountants, and at the expense of the lessee. The lessee shall furnish free of cost duplicate copies of such annual or other audits to the mining supervisor, within 30 days after the completion of each auditing.

[37 FR 11041, June 1, 1972. Redesignated at 48 FR 35641, Aug. 5, 1983]

§ 1217.300 Audit or review of records.

The Secretary, or his/her authorized representative, will initiate and conduct audits or reviews relating to the scope, nature, and extent of compliance by lessees, operators, revenue payors, and other persons with rental, royalty, fees, and other payment requirements on a Federal geothermal lease. Audits or reviews will also relate to compliance with applicable regulations and orders. All audits or reviews will be conducted in accordance with this part.

§ 1217.301 Lease account reconciliations.

Specific lease account reconciliations will be performed with priority being given to reconciling those lease accounts specifically identified by a State as having significant potential for underpayment.

§ 1217.302 Definitions.

Terms used in this subpart will have the same meaning as in 30 U.S.C. 1702.

§ 1218.10 Information collection.

The information collection requirements contained in this part have been approved by OMB under 44 U.S.C. 3501 et seq. The forms, filing date, and approved OMB clearance numbers are identified in § 1210.10 of this chapter.

[57 FR 41867, Sept. 14, 1992]

§ 1218.40 Assessments for incorrect or late reports and failure to report.

(a) An assessment of an amount not to exceed $10 per day may be charged for each report not received by Office of Natural Resources Revenue (ONRR) by the designated due date for geothermal, solid minerals, and Indian oil and gas leases.

(b) An assessment of an amount not to exceed $10 per day may be charged for each incorrectly completed report for geothermal, solid minerals, and Indian oil and gas leases.

(c) For purpose of assessments discussed in this section, a report is defined as follows:

(1) For coal and other solid minerals leases, a report is each line on Form ONRR-4430, Solid Minerals Production and Royalty Report; or on Form ONRR-2014, Report of Sales and Royalty Remittance, as appropriate.

(2) For Indian oil and gas and all geothermal leases, a report is each line on Form ONRR-2014.

(d) An assessment under this section shall not be shared with a State, Indian tribe, or Indian allottee.

(e) The amount of the assessment to be imposed pursuant to paragraphs (a) and (b) of this section shall be established periodically by ONRR. The assessment amount for each violation will be based on ONRR's experience with costs and improper reporting. The ONRR will publish a Notice of the assessment amount to be applied in the Federal Register.

[49 FR 37346, Sept. 21, 1984. Redesignated and amended at 51 FR 15767, Apr. 28, 1986; 52 FR 27546, July 22, 1987; 52 FR 37452, Oct. 7, 1987; 57 FR 52720, Nov. 5, 1992; 59 FR 38906, Aug. 1, 1994; 66 FR 45773, Aug. 30, 2001; 73 FR 15897, Mar. 26, 2008]

§ 1218.41 Assessments for failure to submit payment of same amount as Form ONRR-2014 or bill document or to provide adequate information.

(a) The ONRR may assess an amount not to exceed $250 when the amount of a payment submitted by a reporter/payor for geothermal, solid minerals, and Indian oil and gas leases is not equivalent in amount to the total of individual line items on the associated Form ONRR-2014, Form ONRR-4430, or a bill document, unless ONRR has authorized the difference in amount.

(b) The ONRR may assess an amount not to exceed $250 for each payment for geothermal, solid minerals, and Indian oil and gas leases submitted by a reporter/payor that cannot be automatically applied to the associated Form ONRR-2014, Form ONRR-4430, or a bill document because of inadequate or erroneous information submitted by the reporter/payor.

(c) For purposes of this section, inadequate or erroneous information is defined as:

(1) Absent or incorrect payor-assigned document number, required to be identified by the reporter/payor in Block 4 on Form ONRR-2014 (document 4 number), or the reuse of the same incorrect payor-assigned document 4 number in a subsequent reporting period.

(2) Absent or incorrect bill document invoice number (to include the three-character alpha prefix and the nine-digit number) or the payor-assigned document 4 number required to be identified by the reporter/payor on the associated payment document, or the reuse of the same incorrect payor-assigned document 4 number in a subsequent reporting period.

(3) Absent or incorrect name of the administering Bureau of Indian Affairs Agency/Area office; or the word “allotted” or the tribe name on payment documents remitted to ONRR for an Indian tribe or allottee. If the payment is made by EFT, the reporter/payor must identify the tribe/allottee on the EFT message by a pre-established five-digit code.

(4) Absent or incorrect ONRR-assigned payor code on a payment document.

(5) Absent or incorrect identification on a payment document.

(d) For purposes of this section, the term “Form ONRR-2014” includes submission of reports of royalty information, such as Form ONRR-4430.

(e) For purposes of this section, a bill document is defined as any invoice that ONRR has issued for assessments, late-payment interest charges, or other amount owed. A payment document is defined as a check or wire transfer message.

(f) The amount of the assessment to be imposed pursuant to paragraphs (a) and (b) of this section shall be established periodically by ONRR. The assessment amount will be based on ONRR's experience with costs and improper reporting and/or payment as specified in this section. The ONRR will publish a Notice in the Federal Register of the assessment amount to be applied with the effective date.

[58 FR 45438, Aug. 30, 1993, as amended at 73 FR 15897, Mar. 26, 2008]

§ 1218.42 Cross-lease netting in calculation of late-payment interest.

(a) Interest due from a payor on any underpayment for any Federal mineral lease or leases (onshore or offshore) and on any Indian tribal mineral lease or leases for any production month shall not be reduced by offsetting against that underpayment any overpayment made by the payor on any other lease or leases, except as provided in paragraph (b) of this section. Interest due from a payor or any underpayment on any Indian allotted lease shall not be reduced by offsetting against any overpayment on any other Indian allotted lease under any circumstances.

(b) Royalties attributed to production from a lease or leases which should have been attributed to production from a different lease or leases may be offset to determine whether and to what extent an underpayment exists on which interest is due if the following conditions are met:

(1) The error results from attributing and reporting an equal volume of production, produced from a lease or leases during a particular production month, to a different lease or leases from which it was not produced for the same or another production month;

(2) The payor is the same for the lease or leases to which production was attributed and the lease or leases to which it should have been attributed;

(3) The payor submits production reports, pipeline allocation reports, or other similar documentary evidence pertaining to the specific production involved which verifies the correct production information;

(4) The lessor is the same for the leases involved (in the case of Indian tribal leases, the same tribe is the lessor); and

(5) The ultimate recipients of any royalty or other lease revenues under any applicable permanent indefinite appropriations are the same for, and receive the same percentage of revenue from, the leases.

(c) If ONRR assesses late-payment interest and the payor asserts that some or all of the interest assessed is not owed pursuant to the exception set forth in paragraph (b) of this section, the burden is on the payor to demonstrate that the exception applies in the specific circumstances of the case.

(d) The exception set forth in paragraph (b) of this section shall not operate to relieve any payor of liability imposed by statute or regulation for erroneous reporting.

[57 FR 62206, Dec. 30, 1992]

§ 1218.50 Timing of payment.

(a) Royalty payments are due at the end of the month following the month during which the oil and gas is produced and sold except when the last day of the month falls on a weekend or holiday. In such cases, payments are due on the first business day of the succeeding month. Rental payments are due as specified by the lease terms.

(b) Invoices will be issued and payable as final collection actions. Payments made on an invoice are due as specified by the invoice.

(c) All payments to ONRR are due as specified and are not deferred or suspended by reason of an appeal having been filed unless such deferral or suspension is approved in writing by an authorized ONRR official.

(d)(1) Notwithstanding the provisions of paragraph (a) of this section and corresponding lease terms and § 1210.52 of this chapter, the due date for submittal of royalty payments and Reports of Sales and Royalty Remittance (Form ONRR-2014) for the production months of July, August, September, and October 2005 for Federal offshore and onshore oil and gas leases by oil and gas lessees or royalty payors who make the certification required under paragraph (d)(2) of this section is extended until January 3, 2006.

(2) The extended due dates in paragraph (d)(1) of this section will apply to royalty payments and Reports of Sales and Royalty Remittance (Form ONRR-2014) by any lessee or royalty payor who certifies that a hurricane that struck the Gulf of Mexico coast of the United States in August or September 2005 disrupted the lessee's or payor's operations to the extent that it prevented the lessee or royalty payor from making an accurate royalty payment or submitting an accurate Form ONRR-2014.

(3) A lessee's or royalty payor's certification under paragraph (d)(2) of this section that it is unable to generate and submit either an accurate royalty report or an accurate royalty payment will extend the due date for both royalty reporting and royalty payment.

(4) Paragraphs (d)(1) through (d)(3) of this section do not apply to Indian leases or to Federal leases for minerals other than oil and gas.

(5) You should submit your certifications under paragraph (d)(2) of this section to Financial Management, Office of Natural Resources Revenue, P.O. Box 25627, Denver, CO 80225-0627.

(e)(1) A lessee or royalty payor who submits a certification required under paragraph (d)(2) of this section may rely on the extended due dates prescribed in paragraph (d)(1) of this section unless and until ONRR notifies the lessee or royalty payor or operator that ONRR does not accept the certification.

(2) If ONRR notifies the lessee or royalty payor that ONRR does not accept the lessee's or royalty payor's certification under paragraph (d)(2) of this section, the due date for royalty payments and Reports of Sales and Royalty Remittance will be the date specified in the notice.

[49 FR 37346, Sept. 21, 1984, as amended at 70 FR 56853, Sept. 29, 2005; 73 FR 15898, Mar. 26, 2008; 77 FR 25880, May 2, 2012]

§ 1218.51 How to make payments.

(a) Definitions.

ACH—Automated Clearing House. A type of EFT using the ACH bank-to-bank network.

Courtesy Notice—An ONRR-issued notice of rental or bonus due.

Deferred Bonus Payment—Lease bonus paid in equal annual installments over a specified number of years.

EFT—Electronic Funds Transfer. Any paperless transfer of funds initiated through an electronic terminal. For ONRR purposes, EFT includes Fedwire and ACH transfers, such as Pay.gov.

Fedwire—A type of EFT using the Federal Reserve Wire network.

Invoice document identification—The ONRR-assigned invoice document identification (three-alpha and nine-numeric characters).

Pay.gov—A type of EFT using the ACH network that is initiated by a payor on the Pay.gov Web site.

Payment—Any monies for royalty, bonus, rental, late payment charge, assessment, penalty, or other money sent to ONRR.

Person—Any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity). The term does not include Federal agencies.

Report—Form ONRR-2014, Report of Sales and Royalty Remittance.

(b) General instructions. You must make all payments to ONRR electronically to the extent it is cost effective and practical. If you pay money to ONRR or to an Indian tribe or allottee, you must follow these procedures:

(1) If ONRR instructs you to use EFT, you must use EFT for all payments to ONRR and/or a tribe.

(2) Contact ONRR before using EFT. ONRR will provide you with EFT payment instructions.

(3) Separate any payments on a Federal lease from any payments on an Indian lease.

(4) If you are not required to use EFT, use one of the following types of payment documents. ONRR prefers that you use these payment documents in the order presented:

(i) Commercial check drawn on a solvent bank;

(ii) Certified check;

(iii) Cashier's check;

(iv) Money order;

(v) Bank draft drawn on a solvent bank; or

(vi) Federal Reserve check.

(5) You must include your payor code on all payments.

(6) You must pay in U.S. dollars.

(c) How to complete a non-EFT payment. (1) Make any payment on a Federal lease payable to: “Department of the Interior—Office of Natural Resources Revenue” or “DOI-ONRR.”

(2) For an Indian allottee payment, send a separate payment for each Bureau of Indian Affairs (BIA) agency or area office represented by the leases on your report or invoice document. You must include the name of the applicable BIA agency or area office on your payment. Make your payment document payable to: “Department of the Interior—Office of Natural Resources Revenue for BIA [Name] Agency (allotted)” or “DOI-ONRR for BIA [Name] Agency (allotted).”

(3) For an Indian tribal payment other than a lockbox payment, send a separate payment for each tribe represented by the leases on your report or invoice document. You must include the name of the Indian tribe on your payment. Make it payable to: “Department of the Interior—Office of Natural Resources Revenue for BIA [Name of Tribe]” or “DOI-ONRR for BIA [Name of Tribe].”

(4) For an Indian tribal lockbox payment, follow the instructions ONRR provides you on how to report and make the lockbox payment. These instructions are specific to each tribe's lockbox written agreement with the bank authorized to receive payments on the tribe's mineral leases. You will receive these instructions from ONRR when you are required to use a tribal lockbox for reports and payments.

(d) Where to send a non-EFT payment when you use the U.S. Postal Service. (1) For a payment to an Indian tribal lockbox, send your payment to the appropriate tribal lockbox address.

(2) For a Federal nonproducing lease rental or deferred bonus payment, send it to: Office of Natural Resources Revenue, P.O. Box 25627, Denver, CO 80225-0627.

(e) Where to send a non-EFT payment when you use a courier or overnight delivery service. You should send this type of payment to: Office of Natural Resources Revenue, Building 85, Denver Federal Center, 6th Avenue and Kipling Street, Room A322, Denver, CO 80225.

(f) How to prepare and what to include on your payment document. (1) For Form ONRR-2014 payments, you must include both your payor code and your payor-assigned document number.

(2) For invoice payments, including RIK invoice payments, you must include both your payor code and invoice document identification.

(3) For bonus payments:

(i) For one-fifth bonus payments for offshore oil, gas, and sulphur leases, follow the instructions in the Notice of Lease Offering.

(ii) For payment of the four-fifths bonus for an offshore lease, use EFT and follow the instructions in § 1218.155(c).

(iii) For the successful bidder's bonus in the competitive sale of a coal, geothermal, or offshore mineral (other than oil, gas or sulfur) lease, follow the instructions and terms of the Notice of Competitive Lease Sale.

(iv) For installment payments of deferred bonuses, you must use EFT.

(4) If you are paying a lease rental you must:

(i) See § 1218.155(c) for instructions on how to pay first-year rentals of an offshore oil, gas, or sulfur lease;

(ii) See the Notice of Lease Offering for instructions on how to pay first-year rentals other than those covered in paragraph (f)(4)(i) of this section.

(iii) Include the ONRR Courtesy Notice, when provided, or write your payor code and government-assigned lease number on the payment document when paying a rental that is not reported on Form ONRR-2014 and not paid by EFT.

(g) When is a payment to ONRR due? (1) All payments are due to ONRR at the time law, regulation, or lease terms require unless ONRR approves a change according to part 1243 of this chapter. If you file an appeal, and the requirement to submit payment is suspended, the original payment due date for purposes such as calculating late payment interest is not changed.

(2) If you use the U.S. Postal Service, courier, or overnight mail to send your payment, it is due at the ONRR addresses in paragraphs (d) and (e) of this section before 4 p.m. Mountain Time on the due date, regardless of when you sent it.

(3) If you use EFT to send your payment, it is due in the ONRR account by the payment due date. You are responsible for your actions or your bank's actions that cause a late or incorrect payment. You will not be held responsible for mechanical or system failures of EFT payments.

(h) What happens if payments are late or overdue? (1) If ONRR receives your payment late, ONRR will impose a late-payment interest charge under § 1218.54.

(2) If you do not pay an amount you owe, ONRR may assess civil penalties under part 1241 of this chapter or other applicable regulations.

[62 FR 19498, Apr. 22, 1997, as amended at 66 FR 45773, Aug. 30, 2001; 67 FR 19112, Apr. 18, 2002; 73 FR 15898, Mar. 26, 2008; 77 FR 25880, May 2, 2012; 87 FR 21746, Apr. 13, 2022]

§ 1218.52 How does a lessee designate a Designee?

(a) If you are a lessee under 30 U.S.C. 1702(7), and you want to designate a person to make all or part of the payments due under a lease on your behalf under 30 U.S.C. 1712(a), you must notify ONRR or the applicable delegated state in writing of such designation by submitting Form ONRR-4425, Designation Form for Royalty Payment Responsibility. Your notification for each lease must include the following:

(1) The lease number for the lease;

(2) The type of products you make payments for e.g., oil, gas.

(3) The type of payments you are responsible for e.g., royalty, minimum royalty, rental.

(4) Whether you are:

(i) A lessee of record (record title owner) in the lease; or

(ii) An operating rights owner (working interest owner) in the lease, and the percentage of your operating rights ownership in the lease;

(5) The name, address, Taxpayer Identification Number (TIN), and phone number of your Designee;

(6) The name, address, and phone number of the individual to contact for the person you named in paragraph (a)(5) of this section;

(7) Your TIN;

(8) The date the designation is effective;

(9) The date the designation terminates, if applicable, and

(10) A copy of the written designation;

(b) The person you designate under paragraph (a) of this section is your Designee under 30 U.S.C. 1701(24) and 30 U.S.C. 1712(a).

(c) If you want to terminate a designation you made under paragraph (a) of this section, you must submit a revised Form ONRR-4425 before the termination stating:

(1) The date the designation is due to terminate; and

(2) If you are not reporting and paying royalties and making other payments to ONRR, a new designation under paragraph (a) of this section.

(d) ONRR may require you to provide notice when there is a change in the percentage of your record title or operating rights ownership.

[62 FR 42066, Aug. 5, 1997, as amended at 73 FR 15898, Mar. 26, 2008]

§ 1218.53 Recoupment of overpayments on Indian mineral leases.

(a) Whenever an overpayment is made under an Indian oil and gas lease, a payor may recoup the overpayment through a recoupment on Form ONRR-2014 against the current month's royalties or other revenues owed on the same lease. However, for any month a payor may not recoup more than 50 percent of the royalties or other revenues owed in that month under an individual allotted lease or more than 100 percent of the royalties or other revenues owed in that month under a tribal lease.

(b) With written permission authorized by tribal statute or resolution, a payor may recoup an overpayment against royalties or other revenues owed in that month under other leases for which that tribe is the lessor. A copy of the tribe's written permission must be furnished to ONRR pursuant to instructions for reporting recoupments in the ONRR revenue reporter handbook. See part 1210 of this chapter. Recouping overpayments on one allotted lease from royalties paid to another allotted lease is specifically prohibited.

(c) Overpayments subject to recoupment under this section include all payments made in excess of the required payment for royalty, rental, bonus, or other amounts owed as specified by statute, regulation, order, or terms of an Indian mineral lease.

(d) The ONRR Director or his/her designee may order any payor to not recoup any amount for such reasonable period of time as may be necessary for ONRR to review the nature and amount of any claimed overpayment.

[60 FR 3087, Jan. 13, 1995, as amended at 67 FR 19112, Apr. 18, 2002]

§ 1218.54 Late payments.

(a) An interest charge shall be assessed on unpaid and underpaid amounts from the date the amounts are due.

(b) The interest charge on late payments shall be at the underpayment rate established by the Internal Revenue Code, 26 U.S.C. 6621(a)(2) (Supp. 1987).

(c) Interest will be charged only on the amount of the payment not received. Interest will be charged only for the number of days the payment is late.

(d) A portion of the interest collected will be paid to a State where the State shares in mineral revenues from Federal leases.

(e) An overpayment on a lease or leases may be offset against an underpayment on a different lease or leases to determine a net underpayment on which interest is due pursuant to conditions specified in § 1218.42.

[49 FR 37346, Sept. 21, 1984, as amended at 55 FR 37230, Sept. 10, 1990; 57 FR 62206, Dec. 30, 1992]

§ 1218.55 Interest payments to Indians.

(a) All interest collected from unpaid or underpayments on Indian tribal or allotted leases will be paid to the tribe or allottee.

(b) Any disbursement of Indian mineral revenues not made by the due date as required in § 1219.103 of this chapter shall accrue interest.

(c) Interest shall be computed at the underpayment rate established by the Internal Revenue Code, 26 U.S.C. 6621(a)(2) (Supp. 1987).

(d) The interest shall be payable only for the number of days the disbursement is late.

[49 FR 37346, Sept. 21, 1984, as amended at 55 FR 37230, Sept. 10, 1990]

§ 1218.56 Definitions.

Terms used in this subpart shall have the same meaning as in 30 U.S.C. 1702.

[49 FR 37346, Sept. 21, 1984. Redesignated at 51 FR 15767, Apr. 28, 1986]

§ 1218.100 Royalty and rental payments.

(a) Payment of royalties and rentals. As specified under the provisions of the lease, the lessee shall submit all rental payments when due and shall pay in value or deliver in production all royalties in the amounts of value or production determined by ONRR to be due.

(b) If the lessor elects to take royalty in oil or gas, unless otherwise agreed upon, such royalty shall be delivered on the leasehold, by the lessee to the order of and without cost to the lessor, as instructed by the Director.

(c) Method of payment. The payor shall tender all payments in accordance with § 1218.51.

[47 FR 47773, Oct. 27, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, and amended at 52 FR 23815, June 25, 1987]

§ 1218.101 Royalty and rental remittance (naval petroleum reserves).

Remittance covering payments of royalty or rental on naval petroleum reserves must be accomplished by necessary identification information and sent direct to the Director, Naval Petroleum Reserves in California.

[47 FR 47773, Oct. 27, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983]

§ 1218.102 Late payment or underpayment charges.

(a) The failure to make timely or proper payments of any monies due pursuant to leases, permits, and contracts subject to these regulations will result in the collection by the ONRR of the full amount past due plus a late payment charge. Exceptions to this late payment charge may be granted when estimated payments on minerals production have already been made timely and otherwise in accordance with instructions provided by ONRR to the payor. However, late payment charges assessed with respect to any Indian lease, permit, or contract shall be collected and paid to the Indian or tribe to which the amount overdue is owed.

(b) Late payment charges will be assessed on any late payment or underpayment from the date that the payment was due until the date that the payment was received at the ONRR addresses specified in § 1218.51. Payments received at the specified ONRR addresses after 4 p.m. mountain time are considered received the following business day.

(c) Late payment charges apply to all underpayments and payments received after the date due. The charges include production and minimum royalties; assessments for liquidated damages; administrative fees and payments by purchasers of royalty taken-in-kind; or any other payments, fees, or assessments that a lessee/operator/permittee/payor/royalty taken-in-kind purchaser is required to pay by a specified date. The failure to pay past due amounts, including late-payment charges, will result in the initiation of other enforcement proceedings.

(d) An overpayment on a lease or leases may be offset against an underpayment on a different lease or leases to determine a net underpayment on which interest is due pursuant to conditions specified in § 1218.42.

[47 FR 47773, Oct. 27, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, and amended at 49 FR 37347, Sept. 21, 1984; 57 FR 41868, Sept. 14, 1992; 57 FR 62206, Dec. 30, 1992; 67 FR 19112, Apr. 18, 2002]

§ 1218.103 Payments to States.

(a) Any amount that is payable by ONRR to a State but is not paid on the due date, as specified in § 1219.100 of this chapter, or that is held in a suspense account pending resolution of a dispute as specified in § 1219.101 of this chapter, shall accrue interest payable to the State.

(b) Interest shall be computed at the underpayment rate established by the Internal Revenue Code, 26 U.S.C. 6621(a)(2) (Supp. 1987).

(c) Interest shall be computed only for the number of days the disbursement is late. In the case of suspended amounts subject to interest, it shall be computed beginning with the calendar day following the day that the monies normally would have been paid to the State had they not been in suspense.

[49 FR 37347, Sept. 21, 1984, as amended at 55 FR 37230, Sept. 10, 1990]

§ 1218.104 Exemption of States from certain interest and penalties.

(a) States are exempt from being assessed for any interest or penalties found to be due against the Department of the Interior for failure to comply with the Emergency Petroleum Allocation Act of 1973, as amended, or any regulation issued by the Secretary of Energy thereunder concerning the certification or processing of crude oil taken in-kind as royalty by the Secretary.

(b) Any State shall be assessed for its share of any overcharge resulting from a determination that DOI failed to comply with the Emergency Petroleum Allocation Act of 1973, as amended. Each State's share shall be assessed against monies owed to the State. Such assessment shall be first against monies owed to such State as a result of royalty audits prior to January 12, 1983, the enactment date of the Federal Oil and Gas Royalty Management Act of 1982, then against other monies owed. The State shall be liable for any balance.

(c) A State's liability for repayment of an overcharge under this section shall exist for any amounts resulting from a judgment in a civil suit or as the result of settlement of a claim through a negotiated agreement. State liability would be offset against future mineral revenue distributions to the State.

[49 FR 37347, Sept. 21, 1984]

§ 1218.105 Definitions.

Terms used in this subpart have the same meaning as in 30 U.S.C. 1702.

[49 FR 37347, Sept. 21, 1984]

§ 1218.150 Royalties, net profit shares, and rental payments.

(a) As specified under the provisions of the lease, the lessee shall submit all rental payments when due and shall pay in value or deliver in production all royalties and net profit shares in the amounts of value or production determined by ONRR to be due.

(b) The failure to make timely or proper payments of any monies due pursuant to leases, permits, and contracts subject to these regulations will result in the collection of the amount past due plus a late payment charge. Exceptions to this late payment charge may be granted when estimated payments on minerals production have already been made timely and otherwise in accordance with instructions provided by ONRR to the payor.

(c) Late payment charges will be assessed on any late payment or underpayment from the date that the payment was due until the date that the payment was received at the ONRR addresses specified in § 1218.51. Payments received at the specified ONRR addresses after 4 p.m. mountain time are considered received the following business day.

(d) Late payment charges apply to all underpayments and payments received after the date due. These charges include production and minimum royalties; assessments for liquidated damages; administrative fees and payments by purchasers of royalty taken-in-kind; or any other payments, fees, or assessments that a lessee/operator/payor/permittee/royalty taken-in-kind purchaser is required to pay by a specified date. The failure to pay past due amounts, including late payment charges, will result in the initiation of other enforcement proceedings.

(e) An overpayment on a lease or leases, excluding rental payments, may be offset against an underpayment on a different lease or leases to determine a net underpayment on which interest is due pursuant to conditions specified in § 1218.42.

[47 FR 22528, May 25, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, and amended at 49 FR 37347, Sept. 21, 1984; 52 FR 23815, June 25, 1987; 57 FR 41868, Sept. 14, 1992; 57 FR 62206, Dec. 30, 1992; 67 FR 19112, Apr. 18, 2002]

§ 1218.151 Rental fees.

The annual rental paid in any year is in addition to, and is not credited against, any royalties due from production. The lessee must pay an annual rental as shown in paragraphs (a), (b), and (c) of this section. Discovery means one or more wells on the lease that meet the requirements in part 250, subpart A of this title.

(a) This paragraph applies to any lease not covered by paragraph (b) or paragraph (c) of this section.

For— | Issued as a result of a sale held— | The lessee must pay rental—

(1) An oil and gas lease | Before March 26, 2001 | On or before the first day of each lease year before the discovery of oil or gas on the lease.

(2) An oil and gas lease | After March 26, 2001 | On or before the first day of each lease year before the discovery of oil or gas on the lease, then on or before the last day of each lease year in any full year in which royalties on production are not due.

(3) A mineral lease for other than oil or gas | Before March 26, 2001 | On or before the first day of each lease year before the discovery of paying quantities.

(4) A mineral lease for other than oil or gas | After March 26, 2001 | On or before the first day of each lease year before the date the first royalty payment is due on the lease, then on or before the last day of each lease year in any full year in which royalties on production are not due.

(b) This paragraph applies to any lease created by segregating a portion of a producing lease when there is no actual or allocated production on the segregated portion. The lessee must pay an annual rental for the segregated portion at the rate specified in the lease. The lessee must pay the rental as shown in the following table.

If the lease results from a segregation— | The lessee must pay rental—

(1) Before March 26, 2001 | On or before the first day of each lease year before the discovery of oil or gas on the segregated portion.

(2) After March 26, 2001 | On or before the first day of each lease year before the discovery of oil or gas on the lease, then on or before the last day of each lease year in any full year in which royalties on production are not due.

(c) For leases issued subject to the net profit sharing provisions, annual rental payments shall be due and payable in advance, on the first day of each lease year which commences prior to the date the first profit share payment becomes due. The owner of any lease created by the segregation of a portion of a lease subject to net profit sharing provisions, shall pay an annual rental for such segregated portion at the rate per acre or hectare specified in the lease. This rental shall be payable each year following the year in which the segregation becomes effective and shall continue to be due and payable, in advance, on the first day of each year which commences prior to the date the first profit share payment becomes due.

[44 FR 38276, June 29, 1979, as amended at 45 FR 69175, Oct. 17, 1980; 47 FR 25972, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982, and at 48 FR 35641, Aug. 5, 1983; 66 FR 11518, Feb. 23, 2001; 67 FR 19112, Apr. 18, 2002]

§ 1218.152 Fishermen's Contingency Fund.

Upon the establishment of the Fishermen's Contingency Fund, any holder of a lease issued or maintained under the Outer Continental Shelf Lands Act and any holder of an exploration permit or of an easement or right-of-way for the construction of a pipeline, shall pay an amount specified by the Director, ONRR, who shall assess and collect the specified amount from each holder and deposit it into the Fund. With respect to prelease exploratory drilling permits, the amount will be collected at the time of issuance of the permit.

[52 FR 5458, Feb. 23, 1987]

§ 1218.153 [Reserved]

§ 1218.154 Effect of suspensions on royalty and rental.

(a) ONRR will not relieve the lessee of the obligation to pay rental or minimum royalty for or during the suspension if the Bureau of Safety and Environmental Enforcement (BSEE) Regional Supervisor:

(1) Grants a suspension of operations or production, or both, at the request of the lessee; or

(2) Directs a suspension of operations or production, or both, under 30 CFR 250.173(a).

(b) ONRR will not require a lessee to pay rental or minimum royalty for or during the suspension if the BSEE Regional Supervisor directs a suspension of operations or production, or both, except as provided in (a)(2) of this section.

(c) If the lease anniversary date falls within a period of suspension for which no rental or minimum royalty payments are required under paragraph (b) of this section, the prorated rentals or minimum royalties are due and payable as of the date the suspension period terminates. These amounts shall be computed and notice thereof given the lessee. The lessee shall pay the amount due within 30 days after receipt of such notice. The anniversary date of a lease shall not change by reason of any period of lease suspension or rental or royalty relief resulting therefrom.

[44 FR 38276, June 29, 1979; 44 FR 55380, Sept. 26, 1979. Redesignated and amended at 47 FR 47006, 47007, Oct. 22, 1982. Further redesignated at 48 FR 35641, Aug. 5, 1983 and amended at 51 FR 19063, May 27, 1986; 54 FR 50616, Dec. 8, 1989; 64 FR 72775, Dec. 28, 1999; 73 FR 15898, Mar. 26, 2008; 76 FR 38561, July 1, 2011; 78 FR 30206, May 22, 2013]

§ 1218.155 Method of payment.

(a) Payment of royalties and rentals. With the exception of first-year rental, the payor shall tender all payments in accordance with § 1218.51. First-year rental shall be paid in accordance with paragraph (c) of this section.

(b) Payment of the one-fifth bonus bid amount. (1) Each lease bid must include a payment for the one-fifth bonus bid deposit amount unless the bidder is otherwise directed by the Secretary. Further instructions on how to make payment with the bid will be included in the notice of each lease offering. EFT may be used as a method of payment for the one-fifth bonus bid amount.

(2) Beginning with lease offerings held after February 1, 1984, the one-fifth bonus amount received from a high bidder shall be deposited into an escrow account created pursuant to an agreement between the Departments of the Interior and Treasury, pending acceptance or rejection of the bid. The one-fifth bonus funds will be invested in public debt securities. Investment of this amount by the U.S. Government does not indicate acceptance of the bid. The one-fifth bonus amounts submitted with bids other than the highest valid bid will be returned to respective bidders after bids are opened, recorded, and ranked. Return of such amounts will not affect the status, validity, or ranking of bids. The one-fifth bonus bid amount received from any high bidder and held by the Government pending acceptance or rejection, will be returned with actual interest earned, if the bid is subsequently rejected. The interest accrued during the period held in the account pending acceptance or rejection of the bid will accrue to the Government when the bid is accepted.

(c) Payment of the four-fifths bonus bid amount and the first year's rental. Payment shall be made to ONRR by EFT unless otherwise directed by the Secretary. The payment by EFT via the FRCS must be received by the Federal Reserve Bank of New York no later than noon, eastern standard time, on the 11th business day after receipt of the lease forms by the successful bidder. A “business day” is considered to be a day on which the OCS regional office issuing the lease is open for business. The lease will not be executed by the appropriate ONRR official until payment is received. Failure to remit by EFT or as directed by the Secretary within the time specified above will result in forfeiture of the one-fifth bonus bid amount and the lease will not be executed by the appropriate ONRR official. Payors will not be held responsible for late payment due to actions beyond their control, such as mechanical or systems failure of FRCS or FDS. Payors will be held responsible for incorrect actions of their bank which result in late payments. A 2-day grace period will be allowed to make up a deficient payment, but a late payment charge will be assessed for this late payment and a penalty will also be assessed if appropriate. Late payment charges will be assessed in accordance with subpart B of this part.

(d) General. (1) Payors using the appropriate means of payment (EFT, check, etc.) may pay for multiple lease obligations with a single remittance but must ensure that the payment complies with subpart B of this part and the remittance advice adequately identifies the single payment. The format to be used for such identification will be provided by the ONRR Accounting Center.

(2) Where to pay.

(3) The ONRR mailing addresses for payments to ONRR are specified in § 1218.51.

(4) Payments received at the ONRR addresses after 4 p.m. mountain time are considered received the following business day.

(e) Miscellaneous payments. Payments shall be made to the manager of the appropriate Outer Continental Shelf field office by cash, check or bank draft payable to “Department of the Interior—ONRR” for miscellaneous payments such as:

(1) Pipeline rights-of-way application filing fees and rentals, pipeline accessory site rentals and application fees, and other related costs.

(2) Filing and approval fees for transfers of interest in leases.

[49 FR 8605, Mar. 8, 1984, as amended at 52 FR 23815, June 25, 1987; 53 FR 43201, Oct. 26, 1988; 57 FR 41868, Sept. 14, 1992; 62 FR 19499, Apr. 22, 1997; 67 FR 19112, Apr. 18, 2002; 73 FR 15898, Mar. 26, 2008]

§ 1218.156 Definitions.

Terms used in this subpart have the same meaning as in 30 U.S.C. 1702.

[52 FR 23815, June 25, 1987]

§ 1218.200 Payment of royalties, rentals, and deferred bonuses.

As specified under the provisions of the lease, the lessee shall submit all rental and deferred bonus payments when due and shall pay in value all royalties in the amount determined by ONRR to be due.

[52 FR 23815, June 25, 1987]

§ 1218.201 Method of payment.

You must tender all payments in accordance with § 1218.51, except as follows:

(a) For purposes of this section, report means the Solid Minerals Production and Royalty Report, Form ONRR-4430, rather than the Form ONRR-2014.

(b) For Form ONRR-4430 payments, include both your customer identification and your customer document identification numbers on your payment document, rather than the information required under § 1218.51(f)(1).

(c) For a rental payment that is not reported on Form ONRR-4430, include the ONRR Courtesy Notice when provided or write your customer identification number and Government-assigned lease number on the payment document, rather than the information required under § 1218.51(f)(4)(iii).

[66 FR 45773, Aug. 30, 2001]

§ 1218.202 Late payment or underpayment charges.

(a) The failure to make timely or proper payment of any monies due pursuant to leases and contracts subject to these rules will result in the collection by ONRR of the full amount past due plus a late payment charge. Exceptions to this late payment charge may be granted when estimated payments on minerals production have already been made timely and otherwise in accordance with instructions provided by ONRR to the operator/lessee. However, late payment charges assessed with respect to any Indian lease, permit, or contract shall be collected and paid to the Indian or tribe to which the amount overdue is owed.

(b) Late payment charges will be assessed on any late payment or underpayment from the date that the payment was due until the date that the payment was received at the ONRR addresses specified in § 1218.51. Payments received at the specified ONRR addresses after 4 p.m. mountain time are considered received the following business day.

(c) Late payment charges are calculated on the basis of a percentage assessment rate. In the absence of a specific lease, permit, license or contract provision prescribing a different rate, this percentage assessment rate is prescribed by the Department of the Treasury as the “Treasury Current Value of Funds Rate.”

(d) This rate is available in the Treasury Fiscal Requirements Manual Bulletins that are published prior to the first day of each calendar quarter for application to overdue payments or underpayments in the new calendar quarter. The rate is also published in the Notices section of the Federal Register and indexed under “Fiscal Service/Notices/Funds Rate; Treasury Current Value.”

(e) Late payment charges apply to all underpayments and payments received after the date due. These charges include production, minimum, or advance royalties; assessments for liquidated damages; or any other payments, fees, or assessments that an operator/lessee is required to pay by a specified date. The failure to pay past due payments, including late payment charges, will result in the initiation of other enforcement proceedings.

(f) An overpayment on a lease or leases may be offset against an underpayment on a different lease or leases to determine a net underpayment on which interest is due pursuant to conditions specified in § 1218.42.

[47 FR 33195, July 30, 1982; 47 FR 53366, Nov. 26, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, and further redesignated at 52 FR 23815, June 25, 1987, as amended at 57 FR 41868, Sept. 14, 1992; 57 FR 62207, Dec. 30, 1992; 59 FR 14559, Mar. 29, 1994; 65 FR 55189, Sept. 13, 2000; 67 FR 19112, Apr. 18, 2002]

§ 1218.203 Recoupment of overpayments on Indian mineral leases.

(a) Whenever an overpayment is made under an Indian solid mineral lease, a payor may recoup the overpayment through a recoupment on Form ONRR-4430 against the current month's royalties or other revenues owed on the same lease. However, for any month a payor may not recoup more than 50 percent of the royalties or other revenues owed in that month under an individual allotted lease or more than 100 percent of the royalties or other revenues owed in that month under a tribal lease.

(b) With written permission authorized by tribal statute or resolution, a payor may recoup an overpayment against royalties or other revenues owed in that month under other leases for which that tribe is the lessor. A copy of the tribe's written permission must be furnished to ONRR for reporting recoupments. Call 1-888-201-6416 for instructions. Recouping overpayments on one allotted lease from royalties paid to another allotted lease is specifically prohibited.

(c) Overpayments subject to recoupment under this section include all payments made in excess of the required payment for royalty, rental, bonus, or other amounts owed as specified by statute, regulation, order, or terms of an Indian mineral lease.

(d) The ONRR Director or his/her designee may order any payor to not recoup any amount for such reasonable period of time as may be necessary for ONRR to review the nature and amount of any claimed overpayment.

[60 FR 3087, Jan. 13, 1995, as amended at 66 FR 45773, Aug. 30, 2001; 66 FR 50827, Oct. 5, 2001]

§ 1218.300 Payment of royalties, rentals, and deferred bonuses.

As specified under the provisions of the lease, the lessee shall submit all rental and deferred bonus payments when due and shall pay in value all royalties in the amount determined by ONRR to be due.

[52 FR 23815, June 25, 1987]

§ 1218.301 Method of payment.

The payor shall tender all payments in accordance with § 1218.51.

[52 FR 23815, June 25, 1987]

§ 1218.302 Late payment or underpayment charges.

(a) The failure to make timely or proper payment of any monies due pursuant to leases and contracts subject to these regulations will result in the collection by the ONRR of the full amount past due plus a late payment charge. Exceptions to this late payment charge may be granted when estimated payments on minerals production have already been made timely and otherwise in accordance with the instructions provided by the ONRR to the payor.

(b) Late payment charges will be assessed on any late payment or underpayment from the date that the payment was due until the date that the payment was received at the ONRR addresses specified in § 1218.51. Payments received at the specified ONRR addresses after 4 p.m. Mountain Time are considered received the following business day.

(c) Late payment charges are calculated on the basis of a percentage assessment rate. In the absence of a specific lease, permit, license or contract provision prescribing a different rate, this percentage assessment rate is prescribed by the Department of the Treasury as the “Treasury Current Value of Funds Rate.”

(d) This rate is available in the Treasury Fiscal Requirements Manual Bulletins that are published prior to the first day of each calendar quarter for application to overdue payments or underpayments in the new calendar quarter. The rate is also published in the Notices section of the Federal Register and indexed under “Fiscal Service/Notices/Funds Rate; Treasury Current Value.”

(e) Late payment charges apply to all underpayments and payments received after the date due. These charges include production, minimum, and compensatory royalties; assessments for liquidated damages; administrative fees and payments by purchasers of royalty taken-in-kind; or any other payments, fees, or assessments that a lessee/operator/payor/royalty taken-in-kind purchaser is required to pay by a specified date. The failure to pay past due payments, including late payment charges, will result in the initiation of other enforcement proceedings.

(f) An overpayment on a lease or leases may be offset against an underpayment on a different lease or leases to determine a net underpayment on which interest is due pursuant to conditions specified in § 1218.42.

[47 FR 22528, May 25, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, and further redesignated at 51 FR 15767, Apr. 28, 1986 and 52 FR 23815, June 25, 1987, as amended at 57 FR 41868, Sept. 14, 1992; 57 FR 62207, Dec. 30, 1992; 59 FR 14559, Mar. 29, 1994; 65 FR 55189, Sept. 13, 2000; 67 FR 19112, Apr. 18, 2002]

§ 1218.303 May I credit rental towards royalty?

(a)(1) For Class II leases as defined in § 1206.351 of this chapter, and for Class III leases as defined in that section that elect under 43 CFR 3200.7(a)(2) to be subject to all of the BLM regulations promulgated for leases issued after August 8, 2005 you may credit the annual rental that you paid before the first day of the year for which the annual rental is owed against the royalty due for the lease year for which the rental was paid. You may not apply any annual rental paid in excess of the royalty due for a particular lease year as a credit against any royalty due in any subsequent lease year.

(2) For purposes of this section, the term “royalty” includes any advanced royalty payable under 30 U.S.C. 1004(f) for a cessation of production.

(b) If portions of your lease are located both within and outside of a participating area, you may credit against royalty under paragraph (a) only that percentage of the rental you paid that corresponds to the percentage of the lease within the participating area on a per-acre basis.

[72 FR 24468, May 2, 2007]

§ 1218.304 May I credit rental towards direct use fees?

You may not credit annual rental toward direct use fees you are required to pay that year under § 1206.356 of this chapter. You must pay the direct use fees in addition to the annual rental due.

[72 FR 24468, May 2, 2007]

§ 1218.305 How do I pay advanced royalties I owe under BLM regulations?

If you pay advanced royalties under 43 CFR 3212.15(a)(1) to retain your lease:

(a) You must pay an advanced royalty monthly equal to the average monthly royalty you paid under 30 CFR part 1206, subpart H (including the amount against which you applied the annual rental as a credit) for the last 3 years the lease was producing. If your lease has been producing for less than 3 years, then use the average monthly royalty payment for the entire period your lease has been producing continuously;

(b) The ONRR must receive your advanced royalty payment before the end of each full calendar month in which no production occurs;

(c) You may credit any advanced royalty you pay against production royalties you owe after your lease resumes production. You may not reduce the amount of any production royalty paid for any year below zero.

[72 FR 24468, May 2, 2007]

§ 1218.306 May I receive a credit against production royalties for in-kind deliveries of electricity I provide under contract to a State or county government?

(a) You may receive a credit against royalties for in-kind deliveries of electricity you provide under contract to a State or county government if:

(1) The State or county to which you provide electricity would receive a portion of the royalties you paid in money for the lease under 30 U.S.C. 191 or 30 U.S.C. 1019, except as otherwise provided under the Mineral Leasing Act for Acquired Lands, 30 U.S.C. 355, because your lease is located in that State or county. If your lease is located in more than one State or county, the revenues are paid to the respective States or counties based on their proportionate shares of the total acres in the lease;

(2) The ONRR approves in advance your contract with the State or county to which you are providing in-kind electricity; and

(3) Your contract provides that you will use the wholesale value of the electricity for the area where your lease is located to establish the specific methodology to determine the amount of the credit; and

(b) The maximum credit you may take under this section is equal to the portion of the royalty revenue that ONRR would have paid to the State or county that is a party to the contract had you paid royalty in money on all of the electricity you delivered to the State or county based on the wholesale value of the electricity. You must pay in money any royalty amount that is not offset by the credit allowed under this section, calculated based on the wholesale value of the electricity.

(c) The electricity the State or county government receives from you satisfies the Secretary's payment obligation to the State or county under 30 U.S.C. 191 or 30 U.S.C. 1019.

[72 FR 24468, May 2, 2007]

§ 1218.307 How do I pay royalties due for my existing leases that qualify for near-term production incentives under BLM regulations?

If you qualify for a production incentive under BLM regulations at 43 CFR subpart 3212, your royalty due on the production BLM determines to be qualified for a production incentive under 43 CFR 3212.23 and 3212.24 is 50 percent of the amount of the total royalty that would otherwise be due under 30 CFR part 1206, subpart H.

[72 FR 24468, May 2, 2007]

§ 1218.500 What is the purpose of this subpart?

This subpart contains instructions for designating a specific addressee of record for service of official correspondence using Form ONRR-4444, Addressee of Record Designation for Service of Official Correspondence.

§ 1218.520 What definitions apply to this subpart?

Address of record is the address to which official correspondence is served.

Addressee of record for service of official correspondence is the person or position to whom official correspondence is served, as specified on Form ONRR-4444, or in the absence of such a form, as established in § 1218.540(b)(2). The addressee of record in a part 1290, appeal will be the person or representative making the appeal.

Official correspondence is all correspondence from ONRR or our delegates, served on companies related to matters such as: forms reporting, audit and compliance, enforcement notices, rental courtesy notices, and invoices.

§ 1218.540 How does ONRR serve official correspondence?

ONRR will serve all Notices of Noncompliance or Civil Penalty following the procedures in part 1241. We will serve all other documents following the procedures in this section.

(a) Method of service. ONRR will serve all official correspondence to the addressee of record by one of the following methods:

(1) U.S. Postal Service mail;

(2) Personal delivery made pursuant to the law of the State in which the service is effected; or

(3) Private mailing service (such as the United Parcel Service or Federal Express), with signature and date upon delivery acknowledging the addressee of record's receipt of the official correspondence document.

(b) Selection of addressee of record information. (1) We will address official correspondence to the party shown on the most recently received Form ONRR-4444 for the type of correspondence at issue. The company or reporting entity is responsible for notifying ONRR of any name or address changes on Form ONRR-4444. The addressee of record in a part 1290, appeal will be the person or representative making the appeal.

(2) If we do not receive addressee of record information from you on Form ONRR-4444, we may use the individual name and address, position title, or department name and address in our database, based on previous formal or informal communications or correspondence for the type of official correspondence at issue. Alternately, we may obtain contact information from public records and send correspondence to:

(i) The registered agent;

(ii) Any corporate officer; or

(iii) The addressee of record shown in the files of any State Secretary; Corporate Commission; Federal or state agency that keeps official records of business entities or corporations; or other appropriate public records for individuals, business entities, or corporations.

(c) Dates of service. Except as provided in paragraph (d) of this section, ONRR considers official correspondence as served on the date that it is received at the address of record. A receipt, signed and dated by any person at that address, is evidence of service and of the date of service. If official correspondence is served in more than one manner and the dates differ, the date of the earliest service is used[smc1].

(d) Constructive service. If we cannot make delivery to the addressee of record after making a reasonable effort, we deem official correspondence as constructively served seven days after the date when we mail the document. This provision covers situations such as those where no delivery occurs because:

(1) The addressee of record has moved without filing a forwarding address;

(2) The forwarding order has expired;

(3) Delivery was expressly refused; or

(4) The document was unclaimed and the attempt to deliver it is substantiated by:

(i) The U.S. Postal Service;

(ii) A private mailing service, as described in this section; or

(iii) The person who attempted to make delivery using some other method of service.

[71 FR 51751, Aug. 31, 2006, as amended at 78 FR 52433, Aug. 23, 2013; 83 FR 3077, Jan. 23, 2018]

§ 1218.560 How do I submit Form ONRR-4444?

You may obtain a copy of Form ONRR-4444 and instructions from ONRR. This form is posted at http://www.onrr.gov/FM/Forms/default.htm. Submit the completed, signed form to the address designated on Form ONRR-4444 instructions.

[77 FR 25881, May 2, 2012]

§ 1218.580 When do I submit Form ONRR-4444?

Initially, you must submit Form ONRR-4444 by November 29, 2006, and subsequently, within 2 weeks of any change of your address.

§ 1218.700 What definitions apply to the regulations in this subpart?

As used in this subpart:

Administrative offset means the withholding of funds payable by the United States (including funds payable by the United States on behalf of a state government) to any person, or the withholding of funds held by the United States for any person, in order to satisfy a debt owed to the United States.

Agency means a department, agency, court, court administrative office, or instrumentality in the executive, judicial, or legislative branch of government, including a government corporation.

Day means calendar day. To count days, include the last day of the period unless it is a Saturday, Sunday, or Federal legal holiday.

Debt and claim are synonymous and interchangeable. They refer to, among other things, royalties, rentals, and any other monies due to, or collectible by, the United States as well as fines, fees, assessments, penalties, and any other monies that have been determined to be legally enforceable and due to the United States from any person, organization, or entity, except another Federal agency. For the purposes of administrative offset under 31 U.S.C. 3716 and this subpart, the terms “debt” and “claims” include money, funds, or property owed to, or collectible by, the United States.

Debtor means a lessee, payor, or other person that owes a debt to the United States or ONRR, or from whom ONRR collects debts on behalf of the United States, the Department, or an Indian lessor.

Delinquent or past due refers to the status of a debt and means a debt that is legally enforceable and has not been paid within the time limit prescribed by the applicable act, law, regulation, lease, order, demand, notice of noncompliance, and/or assessment of civil penalties, contract, decision, or any other agreement.

Department means the Department of the Interior, and any of its bureaus or offices.

Director means the Director of the Office of Natural Resources Revenue, or his or her designee.

DOJ means the U.S. Department of Justice.

FCCS means the Federal Claims Collection Standards, which are published at 31 CFR parts 900 through 904.

FMS means the Financial Management Service, a bureau of the U.S. Department of the Treasury.

Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States under any statutory authority including, but not limited to, a mineral leasing law that authorizes exploration for and development or extraction of oil, gas, coal, any other mineral or geothermal resources, or power generation from renewable energy sources, on Federal or Indian tribal or allotted lands or the Outer Continental Shelf. Depending on the context, lease may also refer to the land area covered by that authorization.

Legally enforceable means that there has been a final non-appealable agency determination that the debt, in the amount stated, is due, and there are no legal bars to collection by offset.

Lessee means any person to whom the United States or an Indian tribe or individual Indian mineral owner issues a Federal or Indian mineral or other resource lease, easement, right-of-way, or other agreement, an assignee of all or a part of the record title interest, or any person to whom operating rights have been assigned.

ONRR means the Office of Natural Resources Revenue, an office of the Department.

Other agreement means any agreement other than a lease and includes, but is not limited to, any agreement between you and the Department to pay the Department money, funds, or property, regardless of form.

Past due has the same meaning as “delinquent” as defined above.

Payor means any person who reports and pays royalties under a lease, regardless of whether that person is also a lessee.

Person includes a natural person or persons, profit or nonprofit corporation, partnership, association, limited liability company, trust, estate, consortium, or other entity that owes a debt to the United States.

Tax refund offset means the reduction of a tax refund by the amount of a past-due, legally enforceable debt.

You and your refer to the debtor.

§ 1218.701 What is ONRR's authority to issue these regulations?

(a) The ONRR is issuing the regulations in this subpart under the authority of the FCCS, the Debt Collection Act of 1982, and the Debt Collection Improvement Act of 1996, 31 U.S.C. 3711, 3716-3718, and 3720A.

(b) The regulations in this subpart adopt and supplement the FCCS as necessary.

§ 1218.702 What happens to delinquent debts you owe ONRR?

(a) The ONRR will collect debts from you under the regulations in this subpart in addition to other applicable statutory and regulatory authorities.

(b) The ONRR will transfer to the U.S. Department of the Treasury any past due, legally enforceable nontax debt that is delinquent within 180 days from the date the debt becomes delinquent so that Treasury may take appropriate action to collect the debt or terminate the collection action under 26 U.S.C. 6402(d)(1) and (2); 31 U.S.C. 3711, 3716, and 3720A; the FCCS; and 31 CFR 285.2 and 285.5.

§ 1218.703 What notice will ONRR give you of our intent to refer a matter to Treasury to collect a debt?

(a) When the Director determines that you owe, or may owe, a legally enforceable debt to ONRR, the Director will send a written notice to you informing you that ONRR intends to refer the debt to Treasury. We will send the notice by facsimile or mail to the most current address known to us. The notice will inform you of the following:

(1) The amount, nature, and basis of the debt.

(2) The methods of offset that ONRR or Treasury may use.

(3) Your opportunity to inspect and copy agency records related to the debt.

(4) Your opportunity to enter into a written agreement with us to repay the debt.

(5) Our policy concerning interest and administrative costs under § 1218.704, including a statement that we will make such assessments against you unless we determine otherwise under the criteria of the FCCS and this part.

(6) The date by which you must remit payment to avoid additional late charges and enforced collection.

(7) The name, address, and telephone number of a contact person (or office) at ONRR who is available to discuss your debt.

(b)(1) You may not appeal the notice issued under this section unless the notice specifically provides you with the opportunity for review under 30 CFR parts 1290 or 1241 because you did not previously receive a notice of the order, decision on appeal, or any other notice or decision that is the basis of the debt that ONRR intends to refer to Treasury, and for which you may be liable in whole or in part under applicable law. You may not dispute matters related to your delinquent debt that were the subject of a final order or appeal decision of which you were the recipient, or to which you were a party that is the basis of your delinquent debt.

(2) This section applies whether or not you appealed the order, demand, notice of noncompliance, or assessment of civil penalties under 30 CFR parts 1290 or 1241.

§ 1218.704 What is ONRR's policy on interest and administrative costs?

(a) Interest. (1) The ONRR will assess interest on all delinquent debts as prescribed by applicable statutes and regulations.

(i) Interest will accrue on debts involving Federal and Indian oil and gas leases under 30 CFR 1218.54, 1218.102, and 1218.150.

(ii) Interest will accrue on debts involving Federal and Indian solid mineral and geothermal resource leases under 30 CFR 1218.202 and 1218.302.

(iii) Interest will accrue on civil penalties ONRR assesses under 30 CFR part 1241.

(2) Interest begins to accrue on all debts from the date that the payment was due unless otherwise specified by law or lease terms.

(b) Penalties. The ONRR will assess penalties under our authority in 30 U.S.C. 1719 and 1720a, and implementing regulations at 30 CFR part 1241.

(c) Administrative costs. The ONRR initially will assess $436 for administrative costs incurred as a result of your failure to pay a delinquent debt. We will publish a notice of any increase in administrative costs assessed under this section in the Federal Register. The ONRR also may assess $436 for administrative costs that continue to accrue during any appeal process if:

(1) The notice we provide you under 30 CFR 1218.703 grants you the right to appeal and you exercise that right; and

(2) Your appeal is denied and we refer the delinquent debt to Treasury under this subpart.

(d) Allocation of payments. The ONRR will apply a partial or installment payment you make on a delinquent debt sent to Treasury, first to outstanding penalty assessments, second to administrative costs, third to accrued interest, and fourth to the outstanding debt principal.

(e) Additional authority. The ONRR may assess interest, penalty charges, and administrative costs on debts that are not subject to 31 U.S.C. 3717 to the extent authorized under common law or other applicable statutory or regulatory authority.

(f) Waiver. The Director may decide to waive collection of all or part of the administrative costs under paragraph (c) of this section either in compromise of the delinquent debt or if the Director determines collection of this charge would be against equity and good conscience or not in the Government's best interest.

(g) The ONRR's decision whether to collect or waive collection of administrative costs under paragraph (f) of this section is the final decision for the Department and is not subject to administrative review.

§ 1218.705 What is ONRR's policy on recommending revocation of your ability to engage in Federal or Indian leasing, licensing, or granting of easements, permits, or rights-of-way?

The Director may recommend that the leasing or issuing agency, under statutory or regulatory authority applicable to that agency, revoke your ability to engage in Federal or Indian leasing, licensing, or granting of easements, permits, or rights-of-way if you inexcusably or willfully fail to pay a debt. The Director will recommend that any revocation of your ability to engage in Federal or Indian leasing, licensing, or granting of easements, permits, or rights-of-way should last only as long as your debt remains unpaid or unresolved.

§ 1218.706 What debts may ONRR refer to Treasury to collect by administrative offset or tax refund offset?

(a) The ONRR may refer any past due, legally enforceable debt you owe to ONRR to Treasury to collect through administrative offset or tax refund offset at least 60 days after we give you notice under 30 CFR 1218.703 if the debt:

(1) Is at least $25.00 or another amount established by Treasury; and

(2) Does not involve Federal oil and gas lease obligations for which offset is precluded under 30 U.S.C. 1724(b)(3).

(b) The ONRR may refer debts reduced to judgment to Treasury for tax refund offset at any time.

§ 1219.100 What is ONRR's timing of payment to the States?

ONRR will pay a State's share of mineral leasing revenues to the State not later than the last business day of the month in which the U.S. Treasury issues a warrant authorizing the disbursement, except for any portion of such revenues which is under challenge and placed in a suspense account pending resolution of a dispute.

§ 1219.101 What receipts are subject to an interest charge?

(a) Subject to the availability of appropriations, the Office of Natural Resources Revenue (ONRR) will pay the State its proportionate share of any interest charge for royalty and related monies that are placed in a suspense account pending resolution of any matters that may disallow distribution and disbursement. Such monies not disbursed by the last business day of the month following receipt by ONRR will accrue interest until paid.

(b) Upon resolution of any matters that may disallow distribution and disbursement, ONRR will disburse the suspended monies found due in paragraph (a) of this section, plus interest, to the State, under the provisions of § 1219.100.

(c) ONRR will apply paragraph (a) of this section to revenues that ONRR cannot disburse to the State because the payor/lessee provided to ONRR incorrect, inadequate, or incomplete information, which prevented ONRR from identifying the proper recipient of the payment.

§ 1219.102 What is ONRR's method of payment to the States?

ONRR will disburse monies to a State by Electronic Funds Transfer (EFT).

§ 1219.103 How will ONRR manage payments to Indian accounts?

ONRR will transfer mineral revenues received from Indian leases to the appropriate Indian accounts that the Bureau of Indian Affairs (BIA) manages for allotted and Tribal revenues. These accounts are specifically designated Treasury accounts. ONRR will transfer these revenues to the Indian accounts at the earliest practicable date after such funds are received, but in no case later than the last business day of the month in which ONRR receives these revenues.

§ 1219.104 What are Explanation of Payments to the States and Indian Tribes?

(a) ONRR will describe the payments to States and BIA, on behalf of Indian Tribes or Indian allottees, discussed in this part, in ONRR-prepared Explanation of Payment reports. ONRR will prepare these reports at the lease level and will include a description of the type of payment made, the period covered by the payment, the source of the payment, sales amounts upon which the payment is based, the royalty rate, and the unit value. If any State or Indian Tribe needs additional information pertaining to mineral revenue payments, the State or Tribe may request this information from ONRR.

(b) ONRR will provide these reports to:

(1) States, not later than the 10th day of the month following the month in which ONRR disburses the State's share of royalties and related monies.

(2) BIA, on behalf of Tribes and Indian allottees, not later than the 10th day of the month following the month in which ONRR disburses the funds.

(c) ONRR will not include in these reports revenues that we cannot distribute to States, Tribes, or Indian allottees because the payor/lessee provided incorrect, inadequate, or incomplete information about the proper recipient of the payment, until the payor/lessee has submitted to ONRR the missing information.

§ 1219.105 What definitions apply to this subpart?

Terms that ONRR uses in this subpart will have the same meaning as in 30 U.S.C. 1702.

§ 1219.410 What does this subpart contain?

(a) The Gulf of Mexico Energy Security Act of 2006 (GOMESA) directs the Secretary of the Interior to disburse a portion of the rentals, royalties, bonus bids, and other sums derived from certain Outer Continental Shelf (OCS) leases in the Gulf of Mexico (GOM) to the States of Alabama, Louisiana, Mississippi, and Texas (collectively identified as the Gulf producing States); to eligible coastal political subdivisions (CPSs) within those States; and to the Land and Water Conservation Fund (LWCF). Shared GOMESA revenues are reserved for the following purposes:

(1) Projects and activities for the purpose of coastal protection, including conservation, coastal restoration, hurricane protection, and infrastructure directly affected by coastal wetland losses;

(2) Mitigation of damage to fish, wildlife, or natural resources;

(3) Implementation of a federally-approved marine, coastal, or comprehensive conservation management plan;

(4) Mitigation of the impact of OCS activities through the funding of onshore infrastructure projects; and

(5) Planning assistance and administrative costs not-to-exceed 3 percent of the amounts received.

(b) This subpart sets forth the formula and methodology ONRR uses to determine the amount of revenues allocated and disbursed to each Gulf producing State and each eligible CPS for each of fiscal years 2007 through 2016. Leasing revenues disbursed under this subpart originate from leases issued on or after December 20, 2006, in the 181 Area in the Eastern Planning Area and the 181 South Area, subject to restrictions identified in GOMESA. We collectively refer to the revenue sharing from these areas for these fiscal years as GOMESA Phase I revenue sharing. For questions related to the revenue-sharing provisions in this subpart, please contact: Program Manager, Financial Management, Office of Natural Resources Revenue, P.O. Box 25165, Denver Federal Center, Building 85, Denver, CO 80225-0165.

§ 1219.411 What definitions apply to this subpart?

For purposes of this subpart:

181 Area means the area identified in map 15, page 58, of the “Proposed Final Outer Continental Shelf Oil and Gas Leasing Program for 1997-2002,” dated August 1996, excluding the area offered in OCS Lease Sale 181, held on December 5, 2001.

181 Area in the Eastern Planning Area is comprised of the area of overlap of the two geographic areas defined as the “181 Area” and the “Eastern Planning Area.”

181 South Area means any area—

(1) Located:

(i) South of the 181 Area;

(ii) West of the Military Mission Line; and

(iii) In the Central Planning Area;

(2) Excluded from the “Proposed Final Outer Continental Shelf Oil and Gas Leasing Program for 1997-2002,” dated August 1996, of the Bureau of Ocean Energy Management; and

(3) Included in the areas considered for oil and gas leasing, as identified in map 8, page 84, of the document entitled, “Revised Outer Continental Shelf Oil and Gas Leasing Program 2007-2012,” approved December 2010.

Applicable leased tract (Phase I) means a tract that is subject to a lease under section 8 of the Outer Continental Shelf Lands Act (OCSLA), 43 U.S.C. 1337, for the purpose of drilling for, developing, and producing oil or natural gas resources, issued on or after December 20, 2006, and located fully or partially in either the 181 Area in the Eastern Planning Area or in the 181 South Area.

Central Planning Area means the Central Gulf of Mexico Planning Area of the Outer Continental Shelf, as designated in the document entitled, “Revised Outer Continental Shelf Oil and Gas Leasing Program 2007-2012,” approved December 2010.

Coastal political subdivision means a political subdivision of a Gulf producing State, any part of which is:

(1) Within the coastal zone (as defined in section 304 of the Coastal Zone Management Act of 1972 (16 U.S.C. 1453)) of the Gulf producing State as of December 20, 2006; and

(2) Not more than 200 nautical miles from the geographic center of any leased tract.

Coastline means the line of ordinary low water along that portion of the coast which is in direct contact with the open sea and the line marking the seaward limit of inland waters. This is the same definition used in section 2 of the Submerged Lands Act (43 U.S.C. 1301).

Distance means the minimum great circle distance.

Eastern Planning Area means the Eastern Gulf of Mexico Planning Area of the Outer Continental Shelf, as designated in the document entitled, “Revised Outer Continental Shelf Oil and Gas Leasing Program 2007-2012,” approved December 2010.

Gulf producing State means each of the States of Alabama, Louisiana, Mississippi, and Texas.

Leased tract means any tract that is subject to a lease under section 6 or 8 of the Outer Continental Shelf Lands Act for the purpose of drilling for, developing, and producing oil or natural gas resources.

Military Mission Line means the north-south line at 86°41′ W. longitude.

Qualified OCS revenues (Phase I) means—

(1) In the case of each of the fiscal years 2007 through 2016, all rentals, royalties, bonus bids, and other sums received by the United States from leases issued on or after December 20, 2006, located:

(i) In the 181 Area in the Eastern Planning Area.

(ii) In the 181 South Area.

(2) For applicable leased tracts intersected by the planning area administrative boundary line (e.g., separating the GOM Central Planning Area from the Eastern Planning Area), only the percent of revenues equivalent to the percent of surface acreage in the 181 Area in the Eastern Planning Area will be considered qualified OCS revenues (Phase I).

(3) Exclusions from the term qualified OCS revenues (Phase I) are:

(i) Revenues from the forfeiture of a bond or other surety securing obligations other than royalties;

(ii) Civil penalties;

(iii) Royalties “taken by the Secretary in-kind and not sold.” (Pub. L. 109-432, Dec. 20, 2006);

(iv) Revenues generated from leases subject to section 8(g) of the Outer Continental Shelf Lands Act (43 U.S.C. 1337(g));

(v) User fees; and

(vi) Lease revenues explicitly excluded from GOMESA revenue sharing by statute or appropriations law.

§ 1219.412 How will ONRR divide the qualified OCS revenues (Phase I)?

For each of the fiscal years 2007 through 2016, the Secretary of the Treasury will deposit 50 percent of the qualified OCS revenues (Phase I) into a special U.S. Treasury account, from which ONRR will disburse 75 percent to the Gulf producing States and 25 percent to the Land and Water Conservation Fund (LWCF). Of the revenues disbursed to a Gulf producing State, we will disburse 20 percent directly to the CPSs within that State. Each Gulf producing State will receive at least 10 percent of the qualified OCS revenues (Phase I) available for allocation to the Gulf producing States each fiscal year. The following table summarizes the resulting revenue shares (adding to 100 percent):

Revenue Distribution of Qualified OCS Revenues Under GOMESA Phase I

Recipient of qualified OCS revenues | Percentage of qualified OCS revenues

U.S. Treasury (General Fund) | 50

Land and Water Conservation Fund | 12.5

Gulf Producing States | 30

Gulf Producing State Coastal Political Subdivisions | 7.5

§ 1219.413 How will ONRR determine each Gulf producing State's share of the qualified OCS revenues (Phase I) from leases in the 181 Area in the Eastern Planning Area and the 181 South Area?

(a) ONRR will determine the great circle distance between:

(1) The geographic center of each applicable leased tract (Phase I); and

(2) The point on the coastline of each Gulf producing State that is closest to the geographic center of each applicable leased tract (Phase I).

(b) Based on these distances, we will calculate the qualified OCS revenues (Phase I) to disburse to each Gulf producing State as follows:

(1) For each Gulf producing State, we will calculate and total, over all applicable leased tracts (Phase I), the mathematical inverses of the distances between the points on the State's coastline that are closest to the geographic centers of the applicable leased tracts (Phase I), and the geographic centers of the applicable leased tracts (Phase I). For applicable leased tracts intersected by the planning area administrative boundary line, we will use the geographic center of the entire lease for the inverse distance determination.

(2) For each Gulf producing State, we will divide the sum of each State's inverse distances from all applicable leased tracts (Phase I) calculated under paragraph (1), by the sum of the inverse distances from all applicable leased tracts (Phase I) across all four Gulf producing States. In the formulas below, IAL, ILA, IMS, and ITX represent the sum of the inverses of the shortest distances between Alabama, Louisiana, Mississippi, and Texas and all applicable leased tracts (Phase I), respectively. We will multiply the result by the amount of shareable, qualified OCS revenues (Phase I).

Alabama Share = (IAL ÷ (IAL + ILA + IMS + ITX)) × qualified OCS revenues (Phase I) Louisiana Share = (ILA ÷ (IAL + ILA + IMS + ITX)) × qualified OCS revenues (Phase I) Mississippi Share = (IMS ÷ (IAL + ILA + IMS + ITX)) × qualified OCS revenues (Phase I) Texas Share = (ITX ÷ (IAL + ILA + IMS + ITX)) × qualified OCS revenues (Phase I)

(3) If, in any fiscal year, this calculation results in less than a 10-percent allocation of the qualified OCS revenues (Phase I) to any Gulf producing State, we will recalculate the distribution. We will allocate 10 percent of the qualified OCS revenues (Phase I) to the affected State and recalculate the other States' shares of the remaining qualified OCS revenues (Phase I), omitting from the calculation the State receiving the 10-percent minimum share.

§ 1219.414 How will ONRR allocate the qualified OCS revenues (Phase I) to coastal political subdivisions within the Gulf producing States?

(a) Of the qualified OCS revenues (Phase I) allocated to a Gulf producing State's CPSs, ONRR will allocate 25 percent based on the proportion that each CPS's population bears to the population of all CPSs in the State.

(b) Of the qualified OCS revenues (Phase I) allocated to a Gulf producing State's CPSs, we will allocate 25 percent based on the proportion that each CPS's miles of coastline bears to the total miles of coastline across all CPSs in the State. However, for the State of Louisiana, we will deem CPSs without a coastline to each have a coastline one-third the average length of the coastline of all CPSs within Louisiana that have a coastline.

(c)(1) Of the qualified OCS revenues (Phase I) allocated to a Gulf producing State's CPSs, we will allocate 50 percent in amounts that are inversely proportional to the respective distances between:

(i) The point in each CPS that is closest to the geographic center of each applicable leased tract (Phase I); and

(ii) The geographic center of each applicable leased tract (Phase I).

(2) However, we will exclude distances to an applicable leased tract (Phase I) from this calculation if any portion of the tract is located in a geographic area that was subject to a leasing moratorium on January 1, 2005, unless the leased tract was in production on that date.

§ 1219.415 How will ONRR allocate qualified OCS revenues (Phase I) to the coastal political subdivisions if, during any fiscal year, there are no applicable leased tracts in the 181 Area in the Eastern Gulf of Mexico Planning Area?

If, during any fiscal year, there are no applicable leased tracts in the 181 Area in the Eastern Gulf of Mexico Planning Area, ONRR will allocate revenues to the CPSs in accordance with the following criteria:

(a) Of the qualified OCS revenues (Phase I) allocated to a Gulf producing State's CPSs, we will allocate 50 percent based on the proportion that each CPS's population bears to the population of all CPSs in the State.

(b) Of the qualified OCS revenues (Phase I) allocated to a Gulf producing State's CPSs, we will allocate 50 percent based on the proportion that each CPS's miles of coastline bears to the total miles of coastline across all CPSs within the State. However, for the State of Louisiana, we will deem CPSs without a coastline to each have a coastline one-third the average length of the coastline of all CPSs within Louisiana that have a coastline.

§ 1219.416 When will ONRR disburse funds to Gulf producing States and coastal political subdivisions?

ONRR will disburse GOMESA revenues as soon as authorized and practicable within the fiscal year following the year that we collect qualified OCS revenues (Phase I).

§ 1219.510 What does this subpart contain?

(a) GOMESA directs the Secretary of the Interior to disburse a portion of the rentals, royalties, bonus bids, and other sums derived from certain OCS leases in the GOM to the States of Alabama, Louisiana, Mississippi, and Texas (collectively identified as the Gulf producing States); to eligible CPSs within those States; and to the LWCF. GOMESA directs the Gulf producing States and CPSs to use the shared revenues for the following purposes:

(1) Projects and activities for the purpose of coastal protection, including conservation, coastal restoration, hurricane protection, and infrastructure directly affected by coastal wetland losses;

(2) Mitigation of damage to fish, wildlife, or natural resources;

(3) Implementation of a federally-approved marine, coastal, or comprehensive conservation management plan;

(4) Mitigation of the impact of OCS activities through the funding of onshore infrastructure projects; and

(5) Planning assistance and administrative costs not-to-exceed 3 percent of the amounts received.

(b) This subpart sets forth the formula and methodology ONRR will use to determine the amount of revenues allocated and disbursed to each Gulf producing State and each eligible CPS for fiscal year 2017 and each fiscal year thereafter. Leasing revenues disbursed under this subpart (also referred to as GOMESA Phase II) originate from leases issued on or after December 20, 2006, in the 181 Area, the 181 South Area, and the GOM 2002-2007 Planning Area, subject to restrictions and caps identified in GOMESA. For questions related to the revenue-sharing provisions in this subpart, please contact: Program Manager, Financial Management, Office of Natural Resources Revenue, P.O. Box 25165, Denver Federal Center, Building 85, Denver, CO 80225-0165, or at (303) 231-3217.

§ 1219.511 What definitions apply to this subpart?

For purposes of this subpart:

181 Area is defined at § 1219.411.

181 South Area is defined at § 1219.411.

“181 Area in the Central Planning Area” is comprised of the area of overlap of the two geographic areas defined at § 1219.411 as the “181 Area” and the “Central Planning Area.”

2002-2007 Planning Area means any area—

(1) Located in—

(i) The Eastern Planning Area, as designated in the “Proposed Final Outer Continental Shelf Leasing Program 2002-2007,” dated April 2002;

(ii) The Central Planning Area, as designated in the “Proposed Final Outer Continental Shelf Leasing Program 2002-2007,” dated April 2002; or

(iii) The Western Planning Area, as designated in the “Proposed Final Outer Continental Shelf Leasing Program 2002-2007,” dated April 2002; and

(2) Not located in—

(i) An area in which no funds may be expended to conduct offshore preleasing, leasing, and related activities under sections 104 through 106 of the Department of the Interior, Environment, and Related Agencies Appropriations Act, 2006 (Pub. L. 109-54; 119 Stat. 521) (as in effect on August 2, 2005);

(ii) An area withdrawn from leasing under the “Memorandum on Withdrawal of Certain Areas of the United States Outer Continental Shelf from Leasing Disposition,” from 34 Weekly Comp. Pres. Doc. 1111, dated June 12, 1998; or

(iii) The 181 Area or 181 South Area.

Applicable leased tract (Phase II) means a tract that is subject to a lease under section 8 of the OCSLA, for the purpose of drilling for, developing, and producing oil or natural gas resources, issued on or after December 20, 2006, and located fully or partially in either the 181 Area or the 181 South Area.

Central Planning Area is defined at § 1219.411.

Coastal political subdivision is defined at § 1219.411.

Coastline is defined at § 1219.411.

Distance is defined at § 1219.411.

Eastern Planning Area is defined at § 1219.411.

Gulf producing State is defined at § 1219.411.

Historical lease site means any tract in the 2002-2007 Planning Area leased on or after October 1, 1982, under section 8 of the OCSLA, for the purpose of drilling for, developing, and producing oil or natural gas resources.

Leased tract is defined at § 1219.411.

Military Mission Line is defined at § 1219.411.

Qualified OCS revenues (Phase II) means—

(1) In the case of fiscal year 2017 and each fiscal year thereafter, all rentals, royalties, bonus bids, and other sums received by the United States from leases that lessees enter(ed) into on or after December 20, 2006, located:

(i) In the 181 Area;

(ii) In the 181 South Area;

(iii) In the 2002-2007 Planning Area.

(2) Exclusions from the term “Qualified OCS revenues (Phase II)” are:

(i) Revenues from the forfeiture of a bond or other surety instrument securing obligations other than royalties;

(ii) Civil penalties;

(iii) Royalties “taken by the Secretary in-kind and not sold” (Pub. L. 109-432, Dec 20, 2006);

(iv) Revenues generated from leases subject to section 8(g) of the Outer Continental Shelf Lands Act (43 U.S.C. 1337(g));

(v) User fees; and

(vi) Lease revenues explicitly excluded from GOMESA revenue sharing by statute or appropriations law.

(3) The term “Qualified OCS revenues (Phase II)” consists wholly of the two subsets defined as “Qualified OCS revenues (Phase II—capped)” and “Qualified OCS revenues (Phase II—uncapped).”

(i) Qualified OCS revenues (Phase II—capped) means, in the case of fiscal year 2017 and each fiscal year thereafter, the subset of qualified OCS revenues (Phase II) received by the United States from leases that lessees enter(ed) into on or after December 20, 2006, located:

(A) In the 181 Area in the Central Planning Area; or

(B) In the 2002-2007 Planning Area.

(ii) Qualified OCS revenues (Phase II—uncapped) means, in the case of fiscal year 2017 and each fiscal year thereafter, the subset of qualified OCS revenues (Phase II) received by the United States from leases that lessees enter(ed) into on or after December 20, 2006, located:

(A) In the 181 Area in the Eastern Planning Area, or

(B) In the 181 South Area.

§ 1219.512 How will ONRR divide the qualified OCS revenues (Phase II)?

(a) For fiscal year 2017 and each fiscal year thereafter, the Secretary of the Treasury will deposit 50 percent of the qualified OCS revenues (Phase II—uncapped) into a special U.S. Treasury account, from which ONRR will disburse 75 percent to the Gulf producing States and 25 percent to the LWCF. Of the revenues disbursed to a Gulf producing State, we will disburse 20 percent directly to the CPSs within that State. Each Gulf producing State will receive at least 10 percent of the qualified OCS revenues (Phase II—uncapped) available for allocation to the Gulf producing States each fiscal year. The following table summarizes the resulting revenue shares (adding to 100 percent):

Revenue Distribution of Qualified OCS Revenues (Phase II—Uncapped) Under GOMESA Phase II

Recipient of qualified OCS revenues | Percentage of qualified OCS revenues

U.S. Treasury (General Fund) | 50

Land and Water Conservation Fund | 12.5

Gulf Producing States | 30

Gulf Producing State Coastal Political Subdivisions | 7.5

(b) For fiscal years 2017 through 2024 and 2035 through 2055, the Secretary of the Treasury will deposit 50 percent of the qualified OCS revenues (Phase II—capped) into a special U.S. Treasury account. The total amount of qualified OCS revenues (Phase II—capped) deposited in the special U.S. Treasury account and available for allocation to the Gulf producing States, the CPSs and the LWCF, under this subpart, cannot exceed $500,000,000 for each of the fiscal years 2017 through 2024 and 2035 through 2055. After applying the cap, if applicable, ONRR will disburse 75 percent to the Gulf producing States and 25 percent to the LWCF. Of the revenues disbursed to a Gulf producing State, we will disburse 20 percent directly to the CPSs within that State. Each Gulf producing State will receive at least 10 percent of the qualified OCS revenues (Phase II—capped) available for allocation to the Gulf producing States each fiscal year.

(c) For fiscal years 2025 through 2034, the total amount of qualified OCS revenues (Phase II—capped) deposited in the special U.S. Treasury account and available for allocation to the Gulf producing States, the CPSs and the LWCF, under this subpart, cannot exceed $650,000,000 for each fiscal year. After applying the cap, if applicable, ONRR will disburse the amounts pursuant to paragraph (b) of this section.

[80 FR 81458, Dec. 30, 2015, as amended at 90 FR 38939, Aug. 13, 2025]

§ 1219.513 How will ONRR determine each Gulf producing State's share of the qualified OCS revenues (Phase II) from leases in the 181 Area, the 181 South Area, and the 2002-2007 Planning Area?

(a) ONRR will determine the great circle distance between:

(1) The geographic center of each applicable leased tract (Phase II) or historical lease site; and

(2) The point on the coastline of each Gulf producing State that is closest to the geographic center of each applicable leased tract (Phase II) or historical lease site.

(b) Based on a specific subset of these distances, we will calculate the qualified OCS revenues (Phase II—uncapped) to disburse to each Gulf producing State as follows:

(1) For each Gulf producing State, we will calculate and total, over all applicable leased tracts (Phase II) located in the 181 Area in the Eastern Planning Area or the 181 South Area, the mathematical inverses of the distances between the points on the State's coastline that are closest to the geographic centers of the applicable leased tracts (Phase II) located in the 181 Area in the Eastern Planning Area or the 181 South Area, and the geographic centers of the applicable leased tracts (Phase II) located in the 181 Area in the Eastern Planning Area or the 181 South Area.

(2) For each Gulf producing State, we will divide the sum of each State's inverse distances from all applicable leased tracts (Phase II) located in the 181 Area in the Eastern Planning Area or the 181 South Area calculated under paragraph (1), by the sum of the inverse distances from all applicable leased tracts (Phase II) located in the 181 Area in the Eastern Planning Area or the 181 South Area across all four Gulf producing States. In the formulas below, IAL, ILA, IMS, and ITX represent the sum of the inverses of the shortest distances between Alabama, Louisiana, Mississippi, and Texas and all applicable leased tracts (Phase II), respectively. We will multiply the result by the amount of shareable, qualified OCS revenues (Phase II—uncapped).

Alabama Share = (IAL ÷ (IAL + ILA + IMS + ITX)) × qualified OCS revenues (Phase II—uncapped) Louisiana Share = (ILA ÷ (IAL + ILA + IMS + ITX)) × qualified OCS revenues (Phase II—uncapped) Mississippi Share = (IMS ÷ (IAL + ILA + IMS + ITX)) × qualified OCS revenues (Phase II—uncapped) Texas Share = (ITX ÷ (IAL + ILA + IMS + ITX)) × qualified OCS revenues (Phase II—uncapped)

(3) If, in any fiscal year, this calculation results in less than a 10-percent allocation of the qualified OCS revenues (Phase II—uncapped) to any Gulf producing State, we will recalculate the distribution. We will allocate 10 percent of the qualified OCS revenues (Phase II—uncapped) to the affected State and recalculate the other States' shares of the remaining qualified OCS revenues (Phase II—uncapped), omitting from the calculation the State receiving the 10-percent minimum share.

(c) Based on a specific subset of these distances, we will calculate the qualified OCS revenues (Phase II—capped) to disburse to each Gulf producing State as follows:

(1) For each Gulf producing State, we will calculate and total, over all applicable leased tracts (Phase II) located in the 181 Area in the Central Planning Area and historical lease sites, the mathematical inverses of the distances between the points on the State's coastline that are closest to the geographic centers of the applicable leased tracts (Phase II) located in the 181 Area in the Central Planning Area and historical lease sites, and the geographic centers of the applicable leased tracts (Phase II) located in the 181 Area in the Central Planning Area and historical lease sites.

(2) For each Gulf producing State, we will divide the sum of each State's inverse distances from all applicable leased tracts (Phase II) located in the 181 Area in the Central Planning Area and historical lease sites calculated under paragraph (1), by the sum of the inverse distances from all applicable leased tracts (Phase II) located in the 181 Area in the Central Planning Area and historical lease sites across all four Gulf producing States. In the formulas below, IAL, ILA, IMS, and ITX represent the sum of the inverses of the shortest distances between Alabama, Louisiana, Mississippi, and Texas and all applicable leased tracts (Phase II) and historical lease sites, respectively. We will multiply the result by the amount of shareable, qualified OCS revenues (Phase II—capped).

Alabama Share = (IAL ÷ (IAL + ILA + IMS + ITX)) × qualified OCS revenues (Phase II—capped) Louisiana Share = (ILA ÷ (IAL + ILA + IMS + ITX)) × qualified OCS revenues (Phase II—capped) Mississippi Share = (IMS ÷ (IAL + ILA + IMS + ITX)) × qualified OCS revenues (Phase II—capped) Texas Share = (ITX ÷ (IAL + ILA + IMS + ITX)) × qualified OCS revenues (Phase II—capped)

(3) If, in any fiscal year, this calculation results in less than a 10-percent allocation of the qualified OCS revenues (Phase II—capped) to any Gulf producing State, we will recalculate the distribution. We will allocate 10 percent of the qualified OCS revenues (Phase II—capped) to the affected State and recalculate the other States' shares of the remaining qualified OCS revenues (Phase II—capped), omitting from the calculation the State receiving the 10-percent minimum share.

§ 1219.514 How will ONRR allocate the qualified OCS revenues (Phase II) to coastal political subdivisions within the Gulf producing States?

(a) Of the qualified OCS revenues (Phase II) allocated to a Gulf producing State's CPSs, ONRR will allocate 25 percent based on the proportion that each CPS's population bears to the population of all CPSs in the State.

(b) Of the qualified OCS revenues (Phase II) allocated to a Gulf producing State's CPSs, we will allocate 25 percent based on the proportion that each CPS's miles of coastline bears to the total miles of coastline across all CPSs in the State. However, for the State of Louisiana, we will deem CPSs without a coastline to each have a coastline one-third the average length of the coastline of all CPSs within Louisiana that have a coastline.

(c)(1) Of the qualified OCS revenues (Phase II) allocated to a Gulf producing State's CPSs, we will allocate 50 percent in amounts that are inversely proportional to the respective distances between:

(i) The point in each CPS that is closest to the geographic center of the applicable leased tract (Phase II) or historical lease site; and

(ii) The geographic center of each applicable leased tract (Phase II) or historical lease site.

(2) However, we will exclude distances to an applicable leased tract (Phase II) from this calculation if any portion of the tract is located in a geographic area that was subject to a leasing moratorium on January 1, 2005, unless the leased tract was in production on that date.

§ 1219.515 How will ONRR update the group of “historical lease sites” and “applicable leased tracts (Phase II)” used for determining the allocation of shared revenues?

(a) As GOMESA directs, ONRR will update the group of historical lease sites in the 2002-2007 Planning Area as follows:

(1) On December 31, 2015, we will freeze the group of historical lease sites, subject to the adjustment under paragraph (a)(2) of this section.

(2) Beginning January 1, 2022, and every fifth year thereafter, we will extend the ending date for determining the group of historical lease sites for an additional five calendar years by adding any new historical lease sites to the existing group.

(b) Each year we will update the group of applicable leased tracts (Phase II) to include only leases that were in effect at any time during the previous fiscal year.

§ 1219.516 When will ONRR disburse funds to Gulf producing States and coastal political subdivisions?

ONRR will disburse GOMESA revenues as soon as authorized and practicable within the fiscal year following the year that we collect qualified OCS revenues (Phase II).

§ 1220.001 Purpose and scope.

(a) This part 1220 establishes accounting procedures for determining the net profit share base and calculating net profit share payments due the United States for the production of oil and gas from OCS leases.

(b) The procedures established by this part 1220 apply to any OCS lease issued by the Department of the Interior under any bidding system established by § 1260.110(a) of this title which has a net profit share component.

[45 FR 36800, May 30, 1980, as amended at 46 FR 29689, June 2, 1981. Redesignated at 48 FR 1182, Jan. 11, 1983. Amended at 48 FR 35642, Aug. 5, 1983]

§ 1220.002 Definitions.

For purposes of this part 220:

Allowance for capital recovery means the amount calculated according to procedures specified in § 1220.020. This amount allows a premium for risk initially undertaken by the lessee and a return on investment made during the capital recovery period. It is provided in lieu of interest on equipment and materiel charged to the NPSL capital account.

Capital recovery period means the period of time that begins on the date of issuance of the NPSL and ends on the last day of the month during which the sooner of the following occurs:

(1) The lessee completes the last well on the first platform specified in the development and production plan originally approved by the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE), with any approved amendments thereto, and installation of wellhead equipment. In the event the last well is dry, then the capital recovery period shall be deemed to have ended with the determination that the last well is non-productive;

(2) The balance in the NPSL capital account changes from a debit balance to a credit balance; or

(3) The lessee, at his election, chooses to terminate the capital recovery period. A decision to terminate the capital recovery period prior to the events specified in paragraphs (a) (1) and (2) of this definition shall be communicated in writing to the BOEM Director and shall be irrevocable.

Controllable materiel means materiel which at the time is so classified in the Materiel Classification Manual as most recently recommended by the Council of Petroleum Accountants Societies of North America.

Cost means an expenditure or an accrual incurred by a lessee in conducting NPSL operations.

Cost pool means a grouping of costs identified with more than one OCS lease, whether the leases are NPSLs or other types of leases.

Credit means a payment, rebate, reimbursement to a lessee, or other reduction in cost or increase in revenue attributable to NPSL operations.

Direct cost means any cost listed in § 1220.011 that benefits only NPSL operations.

Field employee means an employee below a first level supervisor who is directly employed in the NPSL project area.

First level supervisor means an employee whose primary function in NPSL operations is the direct supervision of other employees and/or contract labor directly employed on the NPSL project area in a field operating capacity.

G & G means geological, geophysical, geochemical and other similar investigations carried out on the NPSL tract.

Joint cost means any cost listed in § 1220.011 that benefits NPSL operations and one or more other operations of the lessee or an outside party.

Lessee means a person authorized by an OCS lease, or an approved assignment thereof, to develop and produce oil and gas, including all parties holding such authority by or through the lessee, and the person designated to conduct NPSL operations.

Lessee's cost of allowed employee absence means the lessee's cost of holiday, vacation, sickness, disability benefits, jury duty and other customary excused allowances.

Materiel means equipment, apparatus, and supplies.

Net profit share base means the end of the month credit balance in the NPSL capital account determined pursuant to § 1220.021. The net profit share base is the production revenue remaining after subtracting all allowable costs and adding all allowable credits (including production revenue) in accordance with the procedures established by this part 1220.

Net profit share payment means the portion of the net profit share base payable to the United States.

Net profit share rate means the percentage share of the net profit share base payable to the United States. The percentage share may be fixed in the notice of OCS lease sale or be the bid variable, depending upon the bidding system used, as established by § 1260.110(a) of this title.

NPSL means a net profit share lease, which is an OCS lease that provides for payment to the United States of a percentage share of the net profits for production of oil and gas from the tract. This percentage share may be fixed in the notice of OCS lease sale or be the bid variable, depending on the bidding system used, as established by § 1260.110(a) of this title.

NPSL operations means all activities subsequent to issuance of the NPSL necessary and proper for the exploration, development, operation, maintenance, and final abandonment of the NPSL property.

NPSL project area means the NPSL tract, offshore facilities, and shore base facilities.

NPSL property means the NPSL tract, and materiel and offshore facilities acquired for use in NPSL operations and that are installed and/or used on the NPSL tract.

NPSL tract means a tract subject to an NPSL.

OCS lease means a Federal lease for oil and gas issued under the OCSLA.

OCS lease sale means the DOI proceeding by which leases for certain OCS tracts are offered for sale by competitive bidding and during which bids are received, announced, and recorded.

Offshore facilities means platform and support systems located offshore that are necessary to conduct NPSL operations, e.g., oil and gas handling facilities, living quarters, offices, shops, cranes, electrical supply equipment and systems, fuel and water storage and piping, heliport, marine docking installations, communication facilities, and navigation aids.

Outside party means any person who is not a lessee.

Person means person as defined in part 1260 of this title.

Personal expenses means travel and other reasonable reimbursable expenses of lessee's employees.

Production means all oil, gas, or other hydrocarbon products produced, removed, saved, or sold from the NPSL property. Gas and liquids of all kinds are included in production. Production includes the allocated share of production from a unit of which the NPSL is a part.

Production revenue means the value of all production attributable to an NPSL property, which value is determined in accordance with § 1260.110(b) of this title.

Railway receiving point or recognized barge terminal means the location that a vendor would use in determining the sale price to the lessee of new materiel to be delivered to the NPSL project area.

Reliable supply store means a recognized source or common stock point for the particular materiel involved.

Shore base facilities means onshore facilities necessary for NPSL operations, including:

(1) Shore base support facilities, e.g., a receiving and trans-shipment point for materiel, staging area for shuttling personnel to and from the NPSL tract, a communication, scheduling, and dispatching center; and

(2) Shore base production facilities, e.g., pumps, separating facilities, gas plants, and tankage for production from the NPSL tract.

Technical employees means those employees having special and specific engineering, geological or other professional skills, and whose primary function in NPSL operations is the handling and resolution of specific operating conditions and problems for the benefit of NPSL operations.

Tract means land located on the OCS that is offered for lease through an OCS lease sale and that is identified by a leasing map or an official protraction diagram prepared by DOI.

[45 FR 36800, May 30, 1980, as amended at 46 FR 29689, June 2, 1981. Redesignated and amended at 48 FR 1182, Jan. 11, 1983. Redesignated at 48 FR 35642, Aug. 5, 1983. Amended at 75 FR 61087, Oct. 4, 2010; 78 FR 30206, May 22, 2013]

§ 1220.003 Information collection.

(a) The Office of Management and Budget (OMB) approved the information collection requirements contained in this part under 44 U.S.C. 3501 et seq. The approved OMB control number is identified in 30 CFR 1210.10. The information will be used to determine all allowable direct and allocable joint costs incurred during the term of the lease, appropriate overhead allowances permitted on these costs pursuant to § 1220.012, and allowances for capital recovery calculated pursuant to § 1220.020. The information collection is mandatory in accordance with the Federal Oil and Gas Royalty Management Act of 1982, 30 U.S.C. 1701 et seq.

(b) Send comments regarding the burden estimates or any other aspect of this information collection, including suggestions for reducing burden, to the Office of Natural Resources Revenue, Attention: Rules & Regs Team, OMB Control Number 1012-0009, P.O. Box 25165, Denver, CO 80225-0165.

[57 FR 41868, Sept. 14, 1992, as amended at 58 FR 64903, Dec. 10, 1993 75 FR 61087, Oct. 4, 2010; 76 FR 76616, Dec. 8, 2011]

§ 1220.010 NPSL capital account.

(a) For each NPSL tract, an NPSL capital account shall be established and maintained by the lessee for NPSL operations. The NPSL capital account shall include debit entries for all allowable direct and allocable joint costs incurred during the term of the lease, appropriate overhead allowances permitted on these costs pursuant to § 1220.012, and allowances for capital recovery calculated pursuant to § 1220.020. The NPSL capital account shall be credited with production revenues attributable to the NPSL and any other credits arising from NPSL activities.

(b) The NPSL capital account shall be kept on an accrual basis.

[45 FR 36800, May 30, 1980, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1220.011 Schedule of allowable direct and allocable joint costs and credits.

The costs and credits specified in paragraphs (a) through (p) of this section may be charged direct, or allocated to NPSL operations, as appropriate, in accordance with § 1220.014.

(a) Lease rental. The rent paid by the lessee for the NPSL tract is allowable.

(b) Labor. (1)(i) Salaries and wages of lessee's field employees, first level supervisors and technical employees employed in the NPSL project area in NPSL operations are allowable if such costs are not charged under paragraph (g) of this section.

(ii) Salaries and wages of technical employees within technical branches of the lessee's organization who are either temporarily or permanently assigned to, and directly employed in NPSL operations are allowable provided that such employees work “full time” on some particular aspect of NPSL operations or some specific technical problem. Excluded from this category are employees assigned a role in NPSL operations as a duty collateral with other duties that do not directly benefit NPSL operations.

(iii) Salaries and wages of technical employees within technical branches of the lessee's organization who are assigned technical tasks directly related to NPSL operations may be allowable. Costs may be charged to the NPSL if supported by adequate time records showing the nature of the task and the hours spent on that task.

(2) Lessee's cost of allowed employee absence paid to employees whose salaries and wages are chargeable to NPSL operations under paragraphs (b)(1) (i) and (ii) of this section are allowable.

(3) Expenditures or contributions made pursuant to assessments imposed by governmental authority that are applicable to lessee's costs chargeable to NPSL operations under paragraphs (b)(1) (i) and (ii) and (b)(2) of this section are allowable.

(4) Reasonable personal expenses, including allowable relocation costs of employees whose salaries and wages are chargeable to NPSL operations under paragraphs (b)(1) (i) and (ii) of this section and that are paid by the lessee or for which the employees are reimbursed under the lessee's normal practice are allowable except as limited by § 1220.013(g).

(i) Allowable relocation costs include:

(A) Travel expenses, including transportation, lodging, subsistence, and reasonable incidental expenses of the employee and members of his immediate family and transportation of his household and personal effects to the new location.

(B) Other necessary and reasonable expenses normally incident to relocation, such as costs of cancelling an unexpired lease, disconnecting and reinstalling household appliances, and purchases of insurance against damages to or loss of personal property are allowable. Costs of cancelling an unexpired lease shall not exceed three times the monthly rental.

(C) Closing costs (i.e., brokerage fees, legal fees, appraisal fees, etc.) for the sale of the employee's actual residence when notified of the transfer are allowable; and

(D) Continuing costs of ownership of the vacant former actual residence being sold, such as continuing mortgage principal and interest payments, maintenance of building and grounds (exclusive of fixing-up expenses), utilities, taxes, property insurance, etc., after settlement date of lease or date of new permanent residence are allowable.

(ii) The combined total of costs listed in paragraphs (b)(4)(i) (C) through (D) of this section shall not exceed 8 percent of the sales price of the property sold.

(iii) Section 1220.013(g) specifies employee relocation expenses that are not allowable as a charge to NPSL operations.

(5) Lessee's current costs of established plans for employee's group life insurance, hospitalization, pension, retirement, stock purchase, thrift, bonds, and other benefit plans of a like nature that are made available to all of lessee's employees on an equitable basis, applicable to lessee's labor cost chargeable to NPSL operations under paragraphs (b)(1) (i) and (ii) and (b)(2) of this section, are allowable. The amount of these charges shall be lessee's actual cost not to exceed 23 percent of the total charges under paragraphs (b)(1) (i) and (ii) and (b)(2) except that the Director may from time to time establish a different maximum percentage.

(6) Charges for expenses incurred under paragraphs (b)(2) through (b)(5) of this section may be made to NPSL accounts on a “when and as paid” basis or by a percentage assessment method. If the percentage assessment method is used, it shall be based upon the lessee's actual cost experience expressed as a percentage of costs chargeable under paragraphs (b)(1) (i) and (ii) and (b)(2) of this section. Under either method the lessee's own cost of administering the plans and paying the salaries and benefits defined in this paragraph shall be excluded. In determining actual cost experience of an employee benefit plan, any dividend or refunds received that are applicable to insurance or annuity policies shall be used to reduce the cost of such policies.

(c) Materiel. (1) Materiel purchased or furnished by a lessee as NPSL property shall be charged or credited at amounts specified in § 1220.015. The purchase and inventorying of materiel is subject to the conditions and provisions in § 1220.032.

(2) Charges to an NPSL account shall be made only for such materiel purchased or furnished as NPSL property as is reasonably practical and consistent with efficient and economical operations. The accumulation of surplus stocks shall be avoided.

(3) Credit for salvaged or returned materiel shall be made to the NPSL capital account. When the amount originally charged qualifies for the allowance for capital recovery in § 1220.020, the credit shall be calculated pursuant to § 1220.021(a)(3).

(d) Transportation. Transportation of employees and materiel necessary for NPSL operations to, from, and within the NPSL project area, are allowable, but subject to the following limitations:

(1) If materiel is moved to the NPSL project area, no charge shall be made to NPSL operations for a distance greater than the distance from the nearest reliable supply store, recognized barge terminal, or railway receiving point where like materiel is normally available, unless agreed to by the Office of Natural Resources Revenue (ONRR) Director.

(2) If surplus materiel is moved from the NPSL project area, no charge shall be made to NPSL operations for a distance greater than the distance to the nearest reliable supply store, recognized barge terminal, or railway receiving point unless agreed to by the ONRR Director. No charge shall be made to NPSL operations for moving materiel to other properties owned by or under the control of a lessee, unless agreed to by the ONRR Director.

(3) In the application of paragraphs (d)(1) and (d)(2) of this section, there shall be no equalization of actual gross trucking costs of $200 or less, excluding accessorial charges.

(e) Contract services. Except when excluded by paragraph (f) of this section and/or § 1220.013(c), the cost of services and utilities provided under contract by outside parties to the lessee and which constitute proper and necessary NPSL operations or support for NPSL operations, and rental charges paid to outside parties for the use of equipment used in the NPSL project area in support of NPSL operations, may be charged to NPSL operations subject to the following conditions and limitations:

(1) Contract services (including professional consulting services and contract services of technical personnel) that are entirely performed in the NPSL project area and benefit exclusively NPSL operations may be charged at the rates specified in the contract.

(2) Contract services (including professional consulting services and contract services of technical personnel) that are entirely performed in the NPSL project area and benefit the NPSL operations and operations on other tracts must be allocated among all tracts benefited and only that portion representing services benefiting the NPSL tract charged to NPSL operations.

(3) Contract services (including professional consulting services and contract services of technical personnel) that are performed at sites outside the NPSL project area may be charged to NPSL operations only if:

(i) The contracted services charged to the NPSL operations benefit only the NPSL tract or support NPSL operations;

(ii) The contract under which such services are provided deals exclusively with services benefiting the NPSL tract or NPSL operations, or the costs of the contract services which are applicable to the NPSL tract or NPSL operations are separately and specifically identified in the contract; and

(iii) Services specified in the contract relate to the resolution of specific technical problems confronting NPSL operations, or specific engineering design problems related to equipment or facilities required for NPSL operations.

(4) The cost of any contract service related to research and development is specifically excluded, as are contract services calling for feasibility studies not directly related to specific engineering design problems or alternatives for equipment and facilities required by NPSL operations.

(f) Legal expenses. Expense of handling, investigating and settling litigation or claims, discharging of liens, payments of judgments and amounts paid for settlement of claims incurred in or resulting from NPSL operations, or necessary to protect or recover the NPSL property are allowable, except those costs listed in § 1220.013(f) as unallowable. This includes the salaries and wages of lessee's legal staff and the expense of outside attorneys who are assigned to matters described in this paragraph if supported by adequate time records showing the nature of the matter, its direct relationship to NPSL operations, and the hours spent on the matter.

(g) Rental of equipment and facilities furnished by lessee. (1)(i) The NPSL capital account shall be charged for the use of equipment and facilities owned by a lessee that are proper and necessary for NPSL operations, including shore base and offshore facilities and pipelines from the tract to shore base production facilities, and that are not NPSL property. Rental charges shall be made at rates based upon actual costs of acquisition, construction, and operation. Such rates may include labor, the cost of setting up and dismantling equipment, maintenance, repairs, other operating expenses, insurance, taxes, depreciation (calculated using a method consistent with generally accepted accounting principles, consistently applied) and a return on the remaining undepreciated basis not to exceed 8 percent per year, except that the ONRR Director may from time to time establish a different maximum percentage. Any cost of acquiring real property in excess of that reasonably required to support the facilities furnished for NPSL operations shall not be included in the costs used to establish these rates. Rates charged shall not exceed average commercial rates for equipment and facilities of similar nature and capability currently prevailing in the vicinity of the NPSL project area.

(ii) The term “equipment and facilities” is used in the broad sense to include equipment that may be mobile or semimobile and also installations that may be semipermanent or permanent in nature. Such equipment and facilities listed below shall be charged on the basis indicated.

Equipment/facilities | Basis of charge

A. Mobile equipment:

Aircraft | Hour.

Automobiles | Mile or hour.

Trucks | Mile or hour.

Tractors | Hour.

Bulldozers | Hour.

Mobile cranes | Hour.

Trailer-mounted test separators | Hour.

Truck-mounted cement mixers | Hour.

Boats | Day or hour.

House trailers | Day.

B. Semimobile equipment:

Drill rigs | Foot or day.

Workover rigs | Hour.

Pulling units | Hour.

Derricks | Day.

Drilling tender | Day.

Barges | Day.

C. Semipermanent installations:

Skid-mounted separators | Day or volume.

Skid-mounted compressors | Day or volume.

D. Permanent installations:

Compressor stations | Volume.

Saltwater disposal wells | Volume or wells.

Source water wells and supply systems | Volume.

Roads | Wells.

Production/drilling platform | Volume or wells.

Canals | Wells.

Dock | Wells.

Oil storage and loading facilities. | Volume.

Gathering systems and pipeline | Volume.

ACT systems | Volume.

Laboratory services (excluding research work) | Hour or unit.

Shore base production facilities | Volume.

Shore base support facilities | Wells.

E. Miscellaneous:

Drill pipe | Foot or day.

Casing setting tools | Day.

Well testing equipment | Day.

Equipment and facilities that are not listed shall be charged on a basis consistent with the nature of the use.

(2) In lieu of charges in paragraph (g)(1) of this section, the lessee may elect to use average commercial rates prevailing in the vicinity of the NPSL project area less 20 percent. For automotive equipment, the lessee may elect to use rates established by the ONRR Director. For other equipment for which no commercial rate exists, the lessee shall submit the basis for determining such costs to the ONRR Director for approval.

(h) Damages and losses to NPSL property. All costs necessary for the repair or replacement of NPSL property made necessary because of damages or losses incurred by fire, flood, storm, theft, accident, or other causes not covered by insurance, except those resulting from lessee's negligence or willful misconduct may be charged to the NPSL capital account. Any settlement received from an insurance carrier should be credited to NPSL operations when received.

(i) Taxes. All taxes, except income taxes, profit share payments, and taxes based upon income, that are assessed or levied upon or in connection with NPSL operations and which have been paid by the lessee are allowable. Allowed taxes shall include, but not be limited to, production, severance, excise, ad valorem, and mineral taxes.

(j) Insurance. (1) Net premiums paid for insurance required to be carried for NPSL operations are allowable. For NPSL operations in which the lessee may act as self-insurer for Workmen's Compensation and Employer's Liability, the lessee may include the risk under its self-insurance program in providing coverage under State and Federal laws and charge NPSL operations at lessee's cost not to exceed manual rates.

(2) NPSL operations shall be credited for all reimbursements for costs of damage to NPSL property or personal injury. Reimbursements for damaged NPSL property shall be credited as follows:

(i) If the damaged NPSL property is replaced or repaired, to the NPSL capital account charged for the cost of replacement or repair; or

(ii) If the damaged NPSL property is not replaced or repaired, to the NPSL capital account except that if the cost of the property originally qualified for the allowance for capital recovery in § 1220.020, the credit shall be calculated pursuant to § 1220.021(a)(3).

(k) Communications. Costs of leasing, acquiring, installing, operating, repairing and maintaining communication systems, including radio, microwave facilities, and computer production controls for the NPSL operations are allowable. If communication facilities systems serving the NPSL tract serve operations and/or facilities outside the NPSL project area, charges to NPSL operations shall be made as provided in paragraph (g) of this section or shall be allocated to NPSL operations in accordance with § 1220.014.

(l) Ecological and environmental. Costs incurred in the NPSL project area as a result of statutory regulations for archeological and geophysical surveys relative to identification and protection of cultural resources and other environmental or ecological surveys required by the Bureau of Land Management or other regulatory authority, may be charged to the NPSL capital account. Also, the costs to provide or have available pollution containment and removal equipment, including payments to organizations and/or funds which provide equipment and/or assistance in the event of oil spills or other environmental damage are allowable. The costs of actual control and cleanup of oil spills and resulting responsibilities required by applicable laws and regulations are allowable, except that a charge shall not be allowed for any such costs attributable to the lessee's negligence or willful misconduct.

(m) Dry or bottom hole contributions. The costs of dry or bottom hole contributions made to obtain information about the structure or other characteristics of the geology underlying the NPSL tract are allowable.

(n) Abandonment costs. Actual costs incurred in the plugging of wells, dismantling of platforms and other facilities and in the restoration of the NPSL project area shall be charged to the NPSL capital account only when incurred (i.e., not on an accrual basis), except that costs incurred after the cessation of production shall not be charged to the NPSL capital account. Abandonment costs in excess of offsetting revenues shall not form the basis of any claim against the United States.

(o) Other costs. Any other costs not covered in paragraphs (a)-(n) of this section and not disallowed by § 1220.013 that are incurred by the lessee in the necessary and proper conduct of NPSL operation and are approved by the ONRR Director, are allowable. Approval of a plan of development and production for the NPSL tract by the BOEM Director shall be considered sufficient approval for these other costs provided they are separately identified in said plan of development and production. Such separate identification shall note the nature of these other costs and may include an estimate of their magnitude. Any cost approvals under this paragraph for which the specific amounts have not been itemized are presumed to be approved provided they fall within the limits for a prudent operator. Approval of costs under this paragraph shall be approval solely for the purposes of determining allowable costs and shall not preclude a subsequent adjustment at audit of the amount of such costs.

(p) Other credits. Credit shall be given to the NPSL capital account, depending on when it is incurred, for NPSL property leased or used in non-NPSL operations, for the sale of information derived from test wells and G & G, and for any and all amounts earned or otherwise due lessee as a result of NPSL operations.

[45 FR 36800, May 30, 1980. Redesignated at 48 FR 1182, Jan. 11, 1983, and at 48 FR 35642, Aug. 5, 1983, as amended at 67 FR 19112, Apr. 18, 2002; 75 FR 61087, Oct. 4, 2010]

§ 1220.012 Overhead allowance.

(a) During the capital recovery period the overhead allowance shall be calculated on a percentage basis at the rate of 4 percent of allowable direct and allocable joint costs charged to the NPSL capital account, exclusive of costs specified in paragraph (c) of this section. This overhead allowance shall be debited to the NPSL capital account in accordance with § 1220.021(b)(2).

(b) For each month after the end of the capital recovery period, an overhead allowance shall be calculated on a percentage basis at the rate of 10 percent of allowable direct and allocable joint costs charged to the NPSL capital account, exclusive of costs specified in paragraph (c) of this section. This overhead allowance shall be debited to the NPSL capital account in accordance with § 1220.021(c)(2).

(c) Overhead shall not be charged on the value of:

(1) Lease rental (§ 1220.011(a));

(2) Contract services (§ 1220.011(e));

(3) Taxes (§ 1220.011(i));

(4) Re-injected hydrocarbons, originally produced from the NPSL tract, that are charged under § 1220.011(c); and

(5) Credits for materiel charged under § 1220.011(c) that are salvaged, returned, or used for the benefit of non-NPSL operations.

[45 FR 36800, May 30, 1980, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1220.013 Unallowable costs.

The following costs shall not be charged as direct or joint costs to NPSL operations:

(a) Bonus payments to the United States;

(b) Interest (except as permitted under § 1220.011(g));

(c) Depreciation, depletion, amortization, or any other charge for capital recovery for materiel charged to the NPSL capital account under § 1220.011(c), except as explicitly provided by the allowance for capital recovery calculated according to § 1220.020;

(d) The cost of taking inventory;

(e) Research and development costs;

(f) The following legal expenses:

(1) The costs of litigation against the Federal government;

(2) Fines or penalties levied by any Federal agency;

(3) Settlement of claims or other litigation resulting from the lessee's violation of regulatory requirements or negligence; and

(4) The cost of the lessee's legal staff or expense of outside attorneys, except as explicitly allowed under § 1220.011(f);

(g) The following employee relocation costs (whether incurred by the employee or the lessee):

(1) Loss on the sale of a home;

(2) Purchase price of a home in the new location;

(3) Payments for employee income taxes incident to reimbursed relocation costs; and

(4) Any relocation cost in connection with an employee move that is for the primary benefit of the lessee's non-NPSL operations;

(h) The lessee's own cost of administering employee benefit plans;

(i) The cost of acquiring or constructing shore base facilities and real property improvements that are charged to NPSL operations on a rental basis under § 1220.011(g);

(j) Rentals on any facilities, the investment costs of which have been charged either directly or as allocable joint costs, to the NPSL capital account; and

(k) Pre-NPSL expenditures.

[45 FR 36800, May 30, 1980, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1220.014 Allocation of joint costs and credits.

(a) Joint costs shall be grouped in cost pools for allocation to NPSL and non-NPSL operations in reasonable proportion to the beneficial or causal relationships which exist between a specific cost pool and the operations. That portion of a joint cost pool that may be allocated to NPSL operations is called an allocable joint cost.

(b) The following allocation principles apply in allocating joint costs:

(1) G & G. G & G shall be allocated on a line mile per tract basis.

(2) Wages and salaries. Wages and salaries that are not charged as direct on the basis of time spent on a particular job shall be allocated on a reasonable and equitable basis.

(3) Compensated personal absence, payroll taxes and personal expenses. These items shall be allocated on the same basis as wages and salaries.

(4) Transportation costs. Transportation costs for employees that are not charged direct shall be allocated on the same basis as their wages and salaries.

(c) Joint credits shall be allocated in the same manner as joint costs.

(d) When the NPSL is made a part of a unit, the allowed costs shall be charged to the NPSL capital account on the basis specified in the unit operating agreement as approved by the BSEE Director. Revenues and other credits shall be made to the NPSL accounts on the same basis as specified in the approved operating agreement. Joint costs of an NPSL and a non-NPSL tract that are adjacent to one another and are on the same structure shall be allocated on a basis approved by the BSEE Director.

§ 1220.015 Pricing of materiel purchases, transfers, and dispositions.

(a)(1) Purchased materiel. Except as provided in paragraph (a)(2)(i) of this section, materiel purchased for use in NPSL operations shall be charged to NPSL operations at the price paid, after deduction of any discounts received. Should any purchased materiel be defective or returned to a vendor for other reasons, the credit shall be allocated to NPSL operations when received by the lessee in accordance with § 1220.011(c)(3).

(2) Transferred and disposal materiel. An item of materiel, which is acquired by the lessee for use in NPSL operations by means other than purchase or disposed of by any means, shall be priced according to this subparagraph:

(i) Condition A (new) materiel. (A) Tubular goods, except line pipe, shall be priced at the current market price in effect on date of movement on a minimum carload or barge load weight basis, regardless of quantity transferred, equalized to the lowest published price “free on board” (f.o.b.) railway receiving point or recognized barge terminal nearest the NPSL tract where such materiel is normally available.

(B) Line pipe. (1) Movement of less than 30,000 pounds shall be priced at the current price in effect at date of movement, as listed by a reliable supply store nearest the NPSL tract where such materiel is normally available.

(2) Movement of 30,000 pounds or more shall be priced under the provisions for tubular goods pricing in paragraph (a)(2)(i)(A) of this section.

(C) Other materiel shall be priced at the current price in effect at date of movement, as listed by a reliable supply store or f.o.b. railway receiving point nearest the NPSL tract where such materiel is normally available.

(ii) Condition B (good used) materiel. Materiel in sound and serviceable condition and suitable for reuse without reconditioning:

(A) Materiel transferred to the NPSL project area shall be priced at 75 percent of current Condition A price.

(B) Materiel transferred from the NPSL project area shall be priced:

(1) At 75 percent of current Condition A price, if the materiel was originally charged to NPSL operations as Condition A materiel, or

(2) At 65 percent of current Condition A price, if the materiel was originally charged to NPSL operations as Condition B materiel at 75 percent of current Condition A price.

(iii) Conditions C and D (other used) materiel—(A) Condition C. Materiel that is not in sound and serviceable condition and not suitable for its original function until after reconditioning shall be priced at 50 percent of current Condition A price.

(B) Condition D. Materiel no longer suitable for its original purposes but suitable for some other purpose shall be priced on a basis commensurate with its use and comparable with that of materiel normally used for such other purpose. If the materiel has no alternative use it should be priced at prevailing prices as scrap.

(iv) Obsolete materiel. Materiel that is serviceable and usable for its original function and has a value less than Condition A, B, or C materiel may be valued at a price agreed to by the Director. Such price should be the equivalent of the value of the service rendered by such materiel.

(b) Pricing conditions. (1) Loading and unloading costs shall be charged at a rate of 15 cents per hundred weight, or such other rate as may be set by the ONRR Director, on all tubular goods movements, in lieu of loading/unloading costs sustained, when the actual hauling costs of such tubular goods is equalized under provisions of § 1220.011(d).

(2) Materiel involving erection costs shall be charged at the applicable percentage of the current knocked-down price of new materiel.

(c) When materiel subject to paragraphs (a)(2) (ii) and (iii) of this section is transferred, the cost of reconditioning shall be borne by the receiving party.

[45 FR 36800, May 30, 1980, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1220.020 Calculation of the allowance for capital recovery.

(a) For purposes of this section, the cost base for the allowance for capital recovery in a particular month shall consist of the sum of:

(1) All allowable direct and allocable joint costs chargeable to the NPSL capital account during the month less any costs specified in § 1220.012(c); plus

(2) The value of contract services chargeable to the NPSL capital account during the month pursuant to § 1220.011(e); plus

(3) The capital recovery period overhead allowance, calculated in accordance with § 1220.012(a), that is chargeable to the NPSL capital account for the month; less

(4) Production revenues and other credits received during the month.

(b) If the cost base for a month is greater than zero (that is, if the sum of the charges specified in paragraphs (a) (1) through (3) of this section exceeds the value of production revenues and other credits), the allowance for capital recovery shall be calculated by multiplying the cost base by the capital recovery factor, and shall be debited to the NPSL capital account as specified in § 1220.021(b).

(c) If the cost base for a month is less than zero, the allowance for capital recovery for the NPSL capital account shall be calculated by multiplying the resulting negative cost base by the capital recovery factor. The negative product of this calculation shall be debited to the NPSL capital account as specified in § 1220.021(b).

(d) No allowance for capital recovery shall be calculated on the charges or credits related to any time period after the end of the capital recovery period.

[45 FR 36800, May 30, 1980, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1220.021 Determination of net profit share base.

(a) During each month of the lease term, the NPSL capital account shall be:

(1) Debited with allowable direct and allocable joint costs;

(2) Credited with an amount reflecting the production revenues for the month, calculated in accordance with § 1260.110(b) of this title.

(3) Credited with amounts properly credited back to the NPSL capital account as specified in § 1220.011(p). Credits associated with charges to the NPSL capital account during the capital recovery period, however, shall first be increased by the value of the credit multiplied by the recovery factor, before crediting that sum to the NPSL capital account.

(b) At the end of each month of the lease term during the capital recovery period:

(1) The transactions specified in paragraph (a) of this section shall be made to the NPSL capital account.

(2) The capital recovery period overhead allowance shall be calculated in accordance with § 1220.012(a) and debited to the NPSL capital account.

(3) The allowance for capital recovery shall be calculated in accordance with § 1220.020 and the allowance debited (or the negative allowance debited, as appropriate) to the NPSL capital account. (A debit entry of a negative allowance for capital recovery shall have the same effect as a credit entry of the absolute value of the allowance for capital recovery.)

(4) The balance in the NPSL capital account shall be calculated. If, as a result of the accounting transactions described in paragraphs (b) (1) through (3) of this section, there is a credit balance in the NPSL capital account, the capital recovery period will be considered terminated as of this month. The credit balance will be forwarded to the next month, which will be the first month for which a profit share payment is due.

(c) At the end of each month of the lease term following the end of the capital recovery period:

(1) The transaction specified in paragraph (a) of this section shall be made to the NPSL capital account.

(2) An overhead allowance shall be calculated in accordance with § 1220.012(b) and debited to the NPSL capital account.

(3) The balance in the NPSL capital account shall be calculated.

(d) If, as a result of the accounting transactions described in paragraph (c) of this section, there is a credit balance in the NPSL capital account, this credit balance is the net profit share base for that month. The opening debit and credit balances in the NPSL capital account for any month following a month in which there is a credit balance in the NPSL capital account (except as provided in paragraph (b)(4)) of this section shall be zero.

(e) If, as a result of the accounting transactions described in paragraph (b) or (c) of this section, there is a debit balance in the NPSL capital account, this debit balance shall be the opening debit balance in the NPSL capital account for the following month.

(f) Any credit balance in the NPSL capital account shall become the net profit share base as described in this section. Any debit balance in the NPSL capital account shall be maintained only insofar as necessary for the determination of profit share payments. Such debit balance shall not represent a claim against the United States.

[45 FR 36800, May 30, 1980. Redesignated at 48 FR 1182, Jan. 11, 1983, and at 48 FR 35642, Aug. 5, 1983, and amended at 55 FR 1210, Jan. 12, 1990; 75 FR 61087, Oct. 4, 2010]

§ 1220.022 Calculation of net profit share payment.

The net profit share payment shall be calculated by multiplying the net profit share base calculated in accordance with § 1220.021 by the net profit share rate. The net profit share payment shall be paid to the United States in accordance with § 1220.031.

[45 FR 36800, May 30, 1980, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1220.030 Maintenance of records.

(a) Each lessee subject to this part 1220 shall establish and maintain such records as are necessary to determine for each NPSL:

(1) The volume and disposition of all oil and gas production saved, removed or sold for each month;

(2) The value of all oil and gas production saved, removed or sold for each month;

(3) The amount and description of costs and credits to the NPSL capital account;

(4) The amount and description of all costs of acquisition, construction, and operation of equipment and facilities furnished by the lessee and charged to the NPSL capital account under § 1220.011(g). Such records shall include worksheets or other documents that indicate the method used to calculate the amount of each charge made under § 1220.011(g);

(5) The cumulative balance of costs and credits to the NPSL capital account; and

(6) The inventory of materiel.

(b) The ledger cards showing the charges and credits to the NPSL capital account shall be maintained until thirty-six months after the cessation of NPSL operations by the lessee. All other documents, journals and records shall be maintained for thirty-six months from the due date or date of mailing of the statement of account on an NPSL, whichever comes later, except that nothing in these regulations shall limit the time of investigation or the need to produce records when prima facie evidence of fraud or willful misconduct is obtained with respect to the government's interest in the NPSL.

[45 FR 36800, May 30, 1980, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1220.031 Reporting and payment requirements.

(a) Each lessee subject to this part shall file an annual report during the period from issuance of the NPSL until the first month in which production revenues are credited to the NPSL capital account. Such report shall list the costs incurred, including allowances applied, credits received, and the balance of the NPSL capital account. Not later than 60 days after the end of the first month in which production revenues are credited to the NPSL capital account, a final report relating to the period shall be filed.

(b) Beginning with the first month in which production revenues are credited to the NPSL capital account, each lessee subject to this part 1220 shall file a report for each NPSL, not later than 60 days following the end of each month, containing the following information for the month for which the report is filed:

(1) The volume and disposition of all oil and gas production saved, removed or sold;

(2) The production revenue;

(3) The amount and description of all costs and credits to the NPSL capital account;

(4) The balance of the NPSL capital account; and

(5) The net profit share base and net profit share payment due the United States and the monthly profit share of the lessee.

(c) Each lessee subject to this part 1220 shall submit, together with the report required by paragraph (b) of this section, any net profit share payment due the United States for the period covered by the report.

(d) Each lessee subject to this part 1220 shall file a report not later than 90 days after each inventory is taken, reporting the controllable materiel on hand, acquired, transferred or used.

(e) Each lessee subject to this part 1220 shall file a final report, not later than 60 days following the cessation of production, together with the appropriate net profit share payment, indicating the remaining balance and costs and credits to the NPSL capital account for the period.

(f) Reports required by this section shall be filed with the ONRR Director, either separately or as part of the reports that are currently filed.

(g) Interest shall be calculated at the prevailing rate or rates as published in the Bulletin to the Department of the Treasury Fiscal Requirement Manual, in effect for the period or periods over which the net profit share payment is owed, compounded monthly, on the amount of a net profit share payment, from the due date (60 days following the end of each month for which the payment was due) of a net profit share payment until such payment is received by the United States.

[45 FR 36800, May 30, 1980, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1220.032 Inventories.

(a) The lessee is responsible for NPSL materiel and shall make proper and timely cost and credit notations for all materiel movements affecting NPSL property. The lessee shall provide only such materiel as may be required for immediate use or is consistent with practical, efficient, and economical operations. The accumulation of surplus stocks shall be avoided by proper materiel control, inventory and purchasing. The lessee shall make timely disposition of idle and surplus materiel through sale.

(b) At reasonable intervals, but at least once every three years, inventories of controllable materiel shall be taken by the lessee. Written notice of intention to take inventory shall be given by the lessee at least 30 days before any inventory is to be taken so that the BOEM Director may be represented at the taking of inventory. Failure of the BOEM Director to be represented at an inventory shall bind the BOEM Director to accept the inventory taken by the lessee, except in the case of willful misrepresentation or fraud.

(c) Inventory shall be valued with any generally accepted accounting method used by the lessee to value the same materiel for financial or income tax reporting purposes, provided that the method is consistently applied throughout the life of the materiel.

(d) Reconciliation shall be made of a physical inventory with the NPSL capital account by the lessee, and a list of overages and shortages shall be available to the BOEM Director for audit as provided in § 1220.033. Inventory adjustments of controllable materiel shall be made by the lessee to the NPSL capital account for overages and shortages. Controllable materiel removed from physical inventory that has not been credited to NPSL operations under § 1220.015(a)(2) shall be credited to NPSL operations at its original value, except that when the cost of the materiel originally qualified for the allowance for capital recovery in § 1220.020, the credit shall be calculated pursuant to § 1220.021(a)(3).

[45 FR 36800, May 30, 1980, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1220.033 Audits.

(a) The accounts of an NPSL lessee or of a contractor of the lessee which are related to NPSL operations shall be subject to audit by DOI or its appointed agent. Where possible, the auditor for DOI shall coordinate audit efforts with other nonoperators, if any. DOI shall have the right to initiate an audit any time within thirty-six months of the due date of the monthly statement that is to be audited or the date that the statement was mailed, whichever is later, provided, however, that audits may not be conducted any more frequently than once every year except upon a showing of fraud or willful misrepresentation.

(b)(1) When nonoperators of an NPSL lease call an audit in accordance with the terms of their operating agreement, the ONRR Director shall be notified of the audit call in the same manner as the operator is notified. DOI may elect to send an auditor with the audit team specified by the nonoperators in lieu of calling for a separate audit by DOI.

(2) If DOI determines to call for an audit, DOI shall notify the lessee of its audit call and set a time and place for the audit. Such a notice shall be sent at least thirty days before the suggested time for the audit to allow the nonoperators to join in DOI's audit in lieu of calling for their own audit. The place for the audit will normally be the place where the lessee maintains its records pertaining to the NPSL lease. The lessee shall send copies of the notice to the nonoperators on the lease. The lessee shall use reasonable effort to notify all nonoperators, but failure to include one or more nonoperators in the notification shall not void the notice.

(3) When DOI calls for an audit, DOI may suggest the date and time when the audit may commence. The estimated duration of the audit may be mentioned to the lessee as well as to the other nonoperators who may elect to supply and auditor for their own audit purposes. The lessee's office where the audit will be held may be named or, if not known, inquired about. If a visit to a field plant or field office is contemplated by the government auditor, such a field trip may be mentioned. If DOI expresses a desire to review a period on which the thirty-six month time limitation has expired, it is the lessee's prerogative to allow the review or to request that DOI adhere to the time limitation specified in these regulations.

(c)(1) Exceptions to the accounting by the lessee, whether in favor of the government or the lessee, shall be noted in a report to the lessee. The lessee shall have 60 days from the mailing of a notice of exceptions to agree to the adjustments proposed by the DOI auditor or to object to the proposed adjustments. If the lessee accepts the proposed adjustments, the adjustment shall be booked in the month in which the lessee agrees to the adjustment, except where such adjustment would have resulted in a change in any net profit share payment due the United States. In such a case, there shall be a redetermination of the NPSL capital account pursuant to § 1220.034.

(2) If the lessee disagrees with the adjustment, the lessee shall have the right to appeal the adjustment to the ONRR Director.

(d) Upon receipt of an agreement by the government auditor that there are no required audit adjustments, upon final determination with respect to any audit adjustment proposed by the government auditor, or upon the lapse of thirty-six months from the due date or date of mailing of the statement of account on an NPSL lease, whichever comes later, the books shall be closed for audit adjustment purposes, except upon a showing of fraud or willful misrepresentation.

(e) ONRR or its authorized agent may require you to provide records for the audit by one or more of the methods specified in 30 CFR 1217.10.

[45 FR 36800, May 30, 1980, as amended at 75 FR 61087, Oct. 4, 2010; 88 FR 53793, Aug. 9, 2023]

§ 1220.034 Redetermination and appeals.

(a) If, as a result of an inspection of records or an audit under § 1220.033, the ONRR Director determines that there is an error in the NPSL capital account or an error in calculating the net profit share payment, whether in favor of the government or the lessee, the ONRR Director shall redetermine the net profit share base and recalculate the net profit share payment due the United States and notify the lessee of the recalculation.

(b) The lessee shall pay any additional amount of net profit share payment owed plus interest, compounded monthly, from the date that the payment was due until the date it is actually paid. Interest shall be calculated at the prevailing rate or rates as published in the Bulletin to the Department of the Treasury Fiscal Requirements Manual, in effect for the period or periods over which the payment is owed.

(c) If the recalculated profit share payment is less than the amount paid the United States, the lessee shall apply such overpayment to the next profit share payment.

(d) Within 30 days after receiving notice of the recalculation as provided in paragraph (a) of this section, the lessee may appeal the decision of the ONRR Director in accordance with the appeals provision of 30 CFR part 1290.

[45 FR 36800, May 30, 1980, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1227.1 What is the purpose of this part?

This part provides procedures to delegate Federal royalty management functions to States under section 205 of the Federal Oil and Gas Royalty Management Act of 1982 (the Act), 30 U.S.C. 1735, as amended by the Federal Oil and Gas Royalty Simplification and Fairness Act of 1996, Pub. L. 104-185, August 13, 1996, as corrected by Pub. L. 104-200. This part also provides procedures to delegate only audit and investigation functions to States under Pub. L. 102-154 for solid mineral leases, geothermal leases and leases subject to section 8(g) of the Outer Continental Shelf Lands Act, 43 U.S.C. 1337(g). This part does not apply to any inspection or enforcement responsibilities of the Bureau of Land Management for onshore leases or the ONRR Offshore Minerals Management program for leases on the Outer Continental Shelf.

[62 FR 43084, Aug. 12, 1997, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1227.10 What is the authority for information collection?

(a) The Office of Management and Budget (OMB) approved the information collection requirements contained in this part under 44 U.S.C. 3501 et seq. The approved OMB control number is identified in 30 CFR 1210.10. We will use the information collected to review and approve delegation proposals from States wishing to perform royalty management functions.

(b) The Federal Government will reimburse some costs, as provided by statute, for delegated functions that each state performs. However, states could incur additional start-up costs, such as purchasing equipment necessary to perform a delegated function that may not be reimbursable. The ONRR estimates that each payor or reporter will coordinate their interactions and communications among the several states and with ONRR. Send comments regarding the burden estimates or any other aspect of this information collection, including suggestions for reducing burden, to the Office of Natural Resources Revenue, Attention: Rules & Regs Team, OMB Control Number 1012-0003, P.O. Box 25165, Denver, CO 80225-0165.

[62 FR 43084, Aug. 12, 1997, as amended at 75 FR 61087, Oct. 4, 2010; 76 FR 76616, Dec. 8, 2011]

§ 1227.101 What royalty management functions may ONRR delegate to a State?

(a) If there are oil and gas leases subject to the Act on Federal lands within your State, ONRR may delegate the following royalty management functions for all such Federal oil and gas leases to you under this part:

(1) Receiving and processing production or royalty reports;

(2) Correcting erroneous report data; and

(3) Performing automated verification.

(b) If there are oil and gas leases subject to the Act on Federal lands within your State, ONRR may delegate the following royalty management functions for some or all of the Federal oil and gas leases to you under this part:

(1) Conducting audits and investigations; and

(2) Issuing demands, subpoenas, and orders to perform restructured accounting, including related notices to lessees or their designees, and entering into tolling agreements under section 115(d)(1) of the Act, 30 U.S.C. 1725(d)(1).

(c) If there are oil and gas leases offshore of your State subject to section 8(g) of the Outer Continental Shelf Lands Act, 43 U.S.C. 1337 (g), or solid mineral leases or geothermal leases on Federal lands within your State, ONRR may delegate authority to conduct audits and investigations for some or all such Federal leases.

[64 FR 36784, July 8, 1999, as amended at 75 FR 61087, Oct. 4, 2010]]

§ 1227.102 What royalty management functions will ONRR not delegate?

This section lists the principal royalty management functions that ONRR will not delegate to a State. ONRR will not delegate to a State the following functions:

(a) ONRR must collect all moneys received from sales, bonuses, rentals, royalties, civil penalties, assessments and interest. ONRR also must collect any moneys a lessee or its designee pays because of audits or other actions of a delegated State;

(b) ONRR must compare all cash and other payments it receives with payments shown on royalty reports or other documents, such as bills, to reconcile payor accounts. ONRR also must disburse all appropriate moneys to States and other revenue recipients, including refunds and interest owed to lessees and their designees;

(c) The Department of the Interior will receive, process, and decide all administrative appeals from demands or other orders issued to lessees, their designees, or any other person, including demands or orders a delegated State issues;

(d) Only ONRR may take enforcement actions other than issuing demands, subpoenas and orders to perform restructured accounting. ONRR or the appropriate Federal agency will issue notices of non-compliance and civil penalties, collect debts, write off delinquent debts, pursue litigation, enforce subpoenas, and manage any alternative dispute resolution. ONRR will conduct, coordinate and approve any settlement or other compromise of an obligation that a lessee or its designee owes;

(e) ONRR will decide all valuation policies, including issuing valuation regulations, determinations, and guidelines, and interpreting valuation regulations; and

(f) ONRR may reserve additional authorities and responsibilities not included in paragraphs (a) through (f) of this section.

[62 FR 43084, Aug. 12, 1997, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1227.103 What must a State's delegation proposal contain?

If you want ONRR to delegate royalty management functions to you, then you must submit a delegation proposal to the Director for Office of Natural Resources Revenue. ONRR will provide you with technical assistance and information to help you prepare your delegation proposal. Your proposal must contain the following minimum information:

(a) The name and title of the State official authorized to submit the delegation proposal and execute the delegation agreement;

(b) The name, address, and telephone number of the State contact for the proposal;

(c) A copy of the legislation, State Attorney General opinion or other document that:

(1) States which State entity or entities are responsible for performing delegated functions, and if more than one entity is delegated such responsibility, the position of the highest ranking State official having ultimate authority over the collection of royalties from leases on Federal lands within the State;

(2) Demonstrates the State's authority to:

(i) Accept a delegation from ONRR; and

(ii) Receive State or Federal appropriations to perform delegated functions;

(d) The date you propose to begin performing delegated functions;

(e) A detailed statement of the delegable functions that you propose to perform. For each function, describe the resources available in your State to perform each function, the procedures you will use to perform each function, and how you will assure that you will meet all Federal laws, lease terms, regulations and relevant performance standards. As evidence that you have or will have the resources to perform each delegable function, provide the following information:

(1) A description of the personnel you have available to perform delegated functions, including:

(i) How many persons you will assign full-time and part-time to each delegated function;

(ii) The technical qualifications of the key personnel you will assign to each function, including academic field and degree, professional credentials, and quality and amount of experience with similar functions; and

(iii) Whether these persons are currently State employees. If not, explain how you propose to hire these persons or obtain their services, and when you expect to have those persons available to perform delegated functions;

(2) A description of the facilities you will use to perform delegated functions, including:

(i) Whether you currently have the facilities in which you will physically locate the personnel and equipment you will need to perform the functions you propose to assume. If not, how you propose to acquire such facilities, and when you expect to have such facilities available; and

(ii) How much office space is available;

(3) Describe the equipment you will use to perform delegated functions, including:

(i) Hardware and software you will use to perform each delegated function, including equipment for:

(A) Document processing, including compatibility with ONRR automated systems, electronic commerce capabilities, and data storage capabilities;

(B) Accessing reference data;

(C) Contacting production or royalty reporters;

(D) Issuing demands;

(E) Maintaining accounting records;

(F) Performing automated verification;

(G) Maintaining security of confidential and proprietary information; and

(H) Providing data to other Federal agencies;

(ii) Whether you currently have the equipment you will need to perform the functions you propose to assume. If not, how you propose to acquire such equipment and when you expect to have such equipment available;

(f) Your estimates of the costs to fund the following resources necessary to perform the delegation:

(1) Personnel, including hiring, employee salaries and benefits, travel and training;

(2) Facilities, including acquisition, upgrades, operation, and maintenance; and

(3) Equipment, including acquisition, operation, and maintenance;

(g) Your plans to fund the resources under paragraph (f) of this section, including any items you will ask ONRR to fund under the delegation agreement;

(h) A statement identifying any areas where State law, including State appropriation law, may limit your ability to perform delegated functions, and an explanation of how you propose to remove any such limitation;

(i) A statement that in accordance with section 203 of the Act (30 U.S.C. 1733) persons who have access to information received under delegated functions are subject to the same provisions of law regarding confidentiality and disclosure of that information as Federal employees. Applicable laws include the Freedom of Information Act (FOIA), the Trade Secrets Act, and relevant Executive Orders. In addition, your statement must acknowledge that all documents produced, received, and maintained as part of any delegation functions are agency records for purposes of FOIA. Therefore, persons who have access to information received under delegated functions may not use such information or provide such information to any other person, including State personnel, for purposes other than performing delegated functions. However, this limitation does not apply if the person submitting the information consents in writing to its use for other State purposes.

[62 FR 43084, Aug. 12, 1997, as amended at 67 FR 19112, Apr. 18, 2002; 75 FR 61087, Oct. 4, 2010]

§ 1227.104 What will ONRR do when it receives a State's delegation proposal?

When ONRR receives your delegation proposal, it will record the receipt date. ONRR will notify you in writing within 15 business days whether your proposal is complete. If it is not complete, ONRR will identify any missing items § 1227.103 requires. Once you submit all required information, ONRR will notify you of the date your application is complete.

[62 FR 43084, Aug. 12, 1997, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1227.105 What are the hearing procedures?

After ONRR notifies you that your delegation proposal is complete, ONRR will schedule a hearing on your proposal, if ONRR determines a hearing is appropriate, as follows:

(a) The ONRR Director will appoint a hearing official to conduct one or more public hearings for fact finding regarding your ability to assume the delegated functions requested. The hearing official will not decide whether to approve your delegation request;

(b) The hearing official will contact you about scheduling a hearing date and location;

(c) The ONRR will publish notice of the hearing in the Federal Register and other appropriate media within your State;

(d) ONRR will publish notice of the proposal in the Federal Register. ONRR will also post the proposal on the ONRR Website, and upon request, ONRR will send a copy of the delegation proposal to the trade associations to distribute to their members, as necessary;

(e) At the hearing, you will have an opportunity to present testimony and written information in support of your proposal;

(f) Other persons may attend the hearing and may present testimony and written information for the record;

(g) ONRR will record the hearing;

(h) ONRR will maintain a record of all documents related to the proposal process;

(i) After the hearing, ONRR may require you to submit additional information in support of your delegation proposal.

[62 FR 43084, Aug. 12, 1997, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1227.106 What statutory requirements must a State meet to receive a delegation?

The ONRR Director will decide whether to approve your delegation request and will ask the Secretary of the Interior to concur in the decision. That decision is solely within the ONRR Director's and the Secretary's discretion. The ONRR Director's decision, which the Secretary concurs in, is the final decision for the Department of the Interior. The ONRR Director may approve a State's request for delegation only if, based upon the State's delegation proposal and the hearing record, the ONRR Director finds that:

(a) It is likely that the State will provide adequate resources to achieve the purposes of the Act;

(b) The State has demonstrated that it will effectively and faithfully administer the ONRR regulations under the Act in accordance with subsections (c) and (d) of section 205 of the Act;

(c) Such delegation will not create an unreasonable burden on any lessee;

(d) The State agrees to adopt standardized reporting procedures ONRR prescribes for royalty and production accounting purposes, unless the State and all affected parties (including ONRR) otherwise agree;

(e) The State agrees to follow and adhere to regulations and guidelines ONRR issues under the mineral leasing laws regarding valuation of production; and

(f) Where necessary for a State to carry out and enforce a delegated activity, the State agrees to enact such laws and promulgate such regulations as are consistent with relevant Federal laws and regulations.

[62 FR 43084, Aug. 12, 1997, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1227.107 When will the ONRR Director decide whether to approve a State's delegation proposal?

The ONRR Director will decide whether to approve your delegation proposal within 90 days after your delegation proposal is considered complete under § 1227.104. ONRR may extend the 90-day period with your written consent.

[62 FR 43084, Aug. 12, 1997, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1227.108 How will ONRR notify a State of its decision?

ONRR will notify you in writing of its decision on your delegation proposal. If ONRR approves your delegation proposal, then ONRR will hold discussions with you to develop a delegation agreement detailing the functions that you will perform, the standards and requirements you must comply with to perform those functions, and any required transition period.

[62 FR 43084, Aug. 12, 1997, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1227.109 What if the ONRR Director denies a State's delegation proposal?

If the ONRR Director denies your delegation proposal, ONRR will state the reasons for denial. ONRR also will inform you in writing of the conditions you must meet to receive approval. You may submit a new delegation proposal at any time following a denial.

[62 FR 43084, Aug. 12, 1997, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1227.110 When and for how long are delegation agreements effective?

(a) Delegation agreements are effective for 3 years from the date the ONRR Director signs the delegation agreement. However, during the development of the State's delegation proposal under § 1227.108 of this part, ONRR, the delegated State, and any other affected person will determine an appropriate transition period for lessees and their designees to modify their systems to comply with any new requirements under a delegation agreement. ONRR will publish notice of the effective date of a State's delegation agreement in the Federal Register and that notice will inform lessees and their designees of any transition period. ONRR also will post the proposals on the ONRR Website at www.boemre.gov, and upon request, will send a copy of the delegation proposals to trade associations to distribute to their members.

(b) You may ask ONRR to renew the delegation for an additional 3 years no less than 6 months before your 3-year delegation agreement expires. You must submit your renewal request to the Director for Office of Natural Resources Revenue as follows:

(1) If you do not want to change the terms of your delegation agreement for the renewal period, you need only ask to extend your existing agreement for the 3-year renewal period. ONRR will not schedule a hearing unless you request one;

(2) If you want to change the terms of your delegation agreement for the renewal period, you must submit a new delegation proposal under this part.

(c) The ONRR Director may approve your renewal request only if ONRR determines that you are meeting the requirements of the applicable standards and regulations. If the ONRR Director denies your renewal request, ONRR will state the reasons for denial. ONRR also will inform you in writing of the conditions you must meet to receive approval. You may submit a new renewal request any time after denial.

(d) After the 3-year renewal period for your delegation agreement ends, if you wish to continue performing one or more delegated functions, you must request a new delegation agreement from ONRR under this part. ONRR will schedule a hearing on your request, if ONRR determines a hearing is appropriate. As part of the decision whether to approve your request for a new delegation, the ONRR Director will consider whether you are meeting the requirements of the applicable standards and regulations under your existing delegation agreement.

(e) If you do not request a hearing under paragraphs (b)(1) or (d) of this section, any other affected person may submit a written request for a hearing under those paragraphs to the ONRR Associate Director for Minerals Revenue Management.

[62 FR 43084, Aug. 12, 1997, as amended at 67 FR 19112, Apr. 18, 2002; 75 FR 61087, Oct. 4, 2010]

§ 1227.111 Do existing delegation agreements remain in effect?

This section explains your options if you have a delegation agreement in effect on the effective date of this regulation.

(a) If you do not want to perform any royalty management functions in addition to those authorized under your existing agreement, you may continue your existing agreement until its expiration date. Before the agreement expires, if you wish to continue to perform one or more of the delegated functions you performed under the expired agreement, you must request a new delegation agreement meeting the requirements of this part and the applicable standards.

(b) If you want to perform royalty management functions in addition to those authorized under your existing agreement, you must request a new delegation agreement under this part.

(c) ONRR may extend any delegation agreement in effect on the effective date of this regulation for up to 3 years beyond the date it is due to expire.

[62 FR 43084, Aug. 12, 1997, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1227.112 What compensation will a State receive to perform delegated functions?

You will receive compensation for your costs to perform each delegated function subject to the following conditions:

(a) Compensation for costs is subject to Congressional appropriations;

(b) Compensation may not exceed the reasonably anticipated expenditures that ONRR would incur to perform the same function;

(c) The cost for which you request compensation must be directly related to your performance of a delegated function and necessary for your performance of that delegated function;

(d) At a minimum, you must provide vouchers detailing your expenditures quarterly during the fiscal year. However, you may agree to provide vouchers on a monthly basis in your delegation agreement;

(e) You must maintain adequate books and records to support your vouchers;

(f) ONRR will pay you quarterly or monthly during the fiscal year as stated in your delegation agreement; and

(g) ONRR may withhold compensation to you for your failure to properly perform any delegated function as provided in section 227.801 of this part.

§ 1227.200 What are a State's general responsibilities if it accepts a delegation?

For each delegated function you perform, you must:

(a) Operate in compliance with all Federal laws, regulations, and Secretarial and ONRR determinations and orders relating to calculating, reporting, and paying mineral royalties and other revenues. You must seek information or guidance from ONRR regarding new, complex, or unique issues. If ONRR determines that written guidance or interpretation is appropriate, ONRR will provide the guidance or interpretation in writing to you and you must follow the interpretation or guidance given;

(b) Comply with Generally Accepted Accounting Principles (GAAP). You must:

(1) Provide complete disclosure of financial results of activities;

(2) Maintain correct and accurate records of all mineral-related transactions and accounts;

(3) Maintain effective controls and accountability;

(4) Maintain a system of accounts that includes a comprehensive audit trail so that all entries may be traced to one or more source documents; and

(5) Maintain adequate royalty and production information for royalty management purposes;

(c) Assist ONRR in meeting the requirements of the Government Performance and Results Act (GPRA) as well as assisting in developing and endeavoring to comply with the ONRR Strategic Plan and Performance Measurements;

(d) Maintain all records you obtain or create under your delegated function, such as royalty reports, production reports, and other related information. You must maintain such records in a safe, secure manner, including taking appropriate measures for protecting confidential and proprietary information and assisting ONRR in responding to Freedom of Information Act requests when necessary. You must maintain such records for at least 7 years;

(e) Provide reports to ONRR about your activities under your delegated functions. ONRR will specify in your delegation agreement what reports you must submit and how often you must submit them. At a minimum, you must provide periodic statistical reports to ONRR summarizing the activities you carried out, such as:

(1) Production and royalty reports processed;

(2) Erroneous reports corrected;

(3) Results of automated verification findings;

(4) Number of audits performed; and

(5) Enforcement documents issued.

(f) Assist ONRR in maintaining adequate reference, royalty, and production databases as provided in the Standards issued under § 1227.201 of this part and the delegation agreement;

(g) Develop annual work plans that:

(1) Specify the work you will perform for each delegated function; and

(2) Identify the resources you will commit to perform each delegated function;

(h) Help ONRR respond to requests for information from other Federal agencies, Congress, and the public;

(i) Cooperate with ONRR's monitoring of your delegated functions; and

(j) Comply with the Standards as required under § 1227.201 of this part.

§ 1227.201 What standards must a State comply with for performing delegated functions?

(a) If ONRR delegates royalty management functions to you, you must comply with the Standards. The Standards explain how you must carry out the activities under each of the delegable functions.

(b) Your delegation agreement may include additional standards specifically applicable to the functions delegated to you.

(c) Failure to comply with your delegation agreement, the Standards, or any of the specific standards and requirements in the delegation agreement, is grounds for termination of all or part of your delegation agreement, or other actions as provided under §§ 1227.801 and 227.802.

(d) ONRR may revise the Standards and will provide notice of those changes in the Federal Register. You must comply with any changes to the Standards.

[62 FR 43084, Aug. 12, 1997, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1227.300 What audit functions may a State perform?

An audit consists of an examination of records to verify that royalty reports and payments accurately reflect actual production, sales, revenues and costs, and compliance with Federal statutes, regulations, lease terms, and ONRR policy determinations.

(a) If you request delegation of audit functions, you must perform at least the following:

(1) Submitting requests for records;

(2) Examining royalty and production reports;

(3) Examining lessee production and sales records, including contracts, payments, invoices, and transportation and processing costs to substantiate production and royalty reporting;

(4) Providing assistance to ONRR for appealed demands or orders, including preparing field reports, performing remanded actions, modifying orders, and providing oral and written briefing and testimony as expert witnesses.

(b) If necessary for a particular audit, you may also perform any of the following:

(1) Issuing engagement letters;

(2) Arranging for entrance conferences;

(3) Scheduling site visits; and

(4) Issuing record releases and audit closure letters; and

(5) Holding closeout conferences.

[62 FR 43084, Aug. 12, 1997, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1227.301 What are a State's responsibilities if it performs audits?

If you perform audits you must:

(a) Comply with the ONRR Audit Procedures Manual and the Government Auditing Standards issued by the Comptroller General of the United States;

(b) Follow the ONRR Annual Audit Work Plan and 5-year Audit Strategy, which ONRR will develop in consultation with States having delegated audit authority;

(c) Agree to undertake special audit initiatives ONRR identifies targeting specific royalty issues, such as valuation or volume determinations;

(d) Prepare, construct, or compile audit work papers under the appropriate procedures, manuals, and guidelines;

(e) Prepare and submit ONRR Audit Work Plans. You may modify your Audit Work Plans with ONRR approval; and

(f) Comply with procedures for appealed demands or orders, including meeting timeframes, supplying information, and using the appropriate format.

[62 FR 43084, Aug. 12, 1997, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1227.400 What functions may a State perform in processing production reports or royalty reports?

Production reporters or royalty reporters provide production, sales, and royalty information on mineral production from leases that must be collected, analyzed, and corrected.

(a) If you request delegation of either production report or royalty report processing functions, you must perform at least the following:

(1) Receiving, identifying, and date stamping production reports or royalty reports;

(2) Processing production or royalty data to allow entry into a data base;

(3) Creating copies of reports by means such as electronic imaging;

(4) Timely transmitting production report or royalty report data to ONRR and other affected Federal agencies as provided in your delegation agreement and the Standards;

(5) Providing training and assistance to production reporters or royalty reporters;

(6) Providing production data or royalty data to ONRR and other affected Federal agencies; and

(7) Providing assistance to ONRR for appealed demands or orders, including meeting timeframes, supplying information, using the appropriate format, performing remanded actions, modifying orders, and providing oral and written briefing and testimony as expert witnesses.

(b) If you request delegation of either production report or royalty report processing functions, or both, you may perform the following functions:

(1) Granting exceptions from reporting and payment requirements for marginal properties; and

(2) Approving alternative royalty and payment requirements for unit agreements and communitization agreements.

(c) You must provide ONRR with a copy of any exceptions from reporting and payment requirements for marginal properties and any alternative royalty and payment requirements for unit agreements and communitization agreements you approve.

[62 FR 43084, Aug. 12, 1997, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1227.401 What are a State's responsibilities if it processes production reports or royalty reports?

In processing production reports or royalty reports you must:

(a) Process reports accurately and timely as provided in the Standards and your delegation agreement;

(b) Identify and resolve fatal errors to use in subsequent error correction that the State or ONRR performs;

(c) Accept multiple forms of electronic media from reporters, as ONRR specifies;

(d) Timely transmit required production or royalty data to ONRR and other affected Federal agencies;

(e) Access well, lease, agreement, and reporter reference data from ONRR and provide updated information to ONRR;

(f) For production reports, maintain adequate system software edits to ensure compliance with the provisions of 30 CFR part 1210—Forms and Reports, the ONRR Minerals Production Reporter Handbook, any interagency memorandum of understanding to which ONRR is a party, and the Standards;

(g) For royalty reports, maintain adequate system software edits to ensure compliance with the provisions of 30 CFR part 1218, the Oil and Gas Payor Handbook, Volume II, “Dear Payor” letters, and the Standards; and

(h) Comply with the procedures for appealed demands or orders, including meeting timeframes, supplying information, and using the appropriate format.

[62 FR 43084, Aug. 12, 1997, as amended at 67 FR 19112, Apr. 18, 2002; 73 FR 15898, Mar. 26, 2008; 75 FR 61087, Oct. 4, 2010]

§ 1227.500 What functions may a State perform to ensure that reporters correct erroneous report data?

Production data and royalty data must be edited to ensure that what is reported is correct, that disbursement is made to the proper recipient, and that correct data are used for other functions, such as automated verification and audits. If you request delegation of error correction functions for production reports or royalty reports, or both, you must perform at least the following:

(a) Correcting all fatal errors and assigning appropriate confirmation indicators;

(b) Verifying whether production reports are missing;

(c) Contacting production reporters or royalty reporters about missing reports and resolving exceptions;

(d) Documenting all corrections made, including providing production reporters or royalty reporters with confirmation reports of any changes;

(e) Providing training and assistance to production reporters or royalty reporters;

(f) Issuing notices, orders to report, and bills as needed, including, but not limited to, imposing assessments on a person who chronically submits erroneous reports; and

(g) Providing assistance to ONRR for appealed demands or orders, including preparing field reports, performing remanded actions, modifying orders, and providing oral and written briefing and testimony as expert witnesses.

[62 FR 43084, Aug. 12, 1997, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1227.501 What are a State's responsibilities to ensure that reporters correct erroneous data?

To ensure the correction of erroneous data, you must:

(a) Ensure compliance with the provisions of 30 CFR parts 1216 and 1218, any applicable handbook specified under 30 CFR 1227.401 (f) and (g), interagency memorandums of understanding to which ONRR is a party, and the Standards;

(b) Ensure that reporters accurately and timely correct all fatal errors as designated in the Standards. These errors include, for example, invalid or incorrect reporter/payor codes, incorrect lease/agreement numbers, and missing data fields;

(c) Submit accepted and corrected lines to ONRR to allow processing in a timely manner as provided in the Standards and 30 CFR part 1219; and

(d) Comply with the procedures for appealed demands or orders, including meeting timeframes, supplying information, and using the appropriate format.

[62 FR 43064, Aug. 12, 1997, as amended at 67 FR 19112, Apr. 18, 2002; 75 FR 61087, Oct. 4, 2010]

§ 1227.600 What automated verification functions may a State perform?

Automated verification involves systematic monitoring of production and royalty reports to identify and resolve reporting or payment discrepancies. States may perform the following:

(a) Automated comparison of sales volumes reported by royalty reporters to sales and transfer volumes reported by production reporters. If you request delegation of automated comparison of sales and production volumes, you must perform at least the following functions:

(1) Performing an initial sales volume comparison between royalty and production reports;

(2) Performing subsequent comparisons when reporters adjust royalty or production reports;

(3) Checking unit prices for reasonable product valuation based on reference price ranges ONRR provides;

(4) Resolving volume variances using written correspondence, telephone inquiries, or other media;

(5) Maintaining appropriate file documentation to support case resolution; and

(6) Issuing orders to correct reports or payments;

(b) Any one or more of the following additional automated verification functions:

(1) Verifying compliance with lease financial terms, such as payment of rent, minimum royalty, and advance royalty;

(2) Identifying and resolving improper adjustments;

(3) Identifying late payments and insufficient estimates, including calculating interest owed to ONRR and verifying payor-calculated interest owed to ONRR;

(4) Calculating interest due to a lessee or its designee for an adjustment or refund, including identifying overpayments and excessive estimates;

(5) Verifying royalty rates; and

(6) Verifying compliance with transportation and processing allowance limitations;

(c) Issuing notices and bills associated with any of the functions under paragraphs (a) and (b) of this section; and

(d) Providing assistance to ONRR for any of these delegated functions on appealed demands or orders, including meeting timeframes, supplying information, using the appropriate format, taking remanded actions, modifying orders, and providing oral and written briefing and testimony as expert witnesses.

§ 1227.601 What are a State's responsibilities if it performs automated verification?

To perform automated verification of production reports or royalty reports, you must:

(a) Verify through research and analysis all identified exceptions and prepare the appropriate billings, assessment letters, warning letters, notification letters, Lease Problem Reports, other internal forms required, and correspondence required to perform any required follow-up action for each function, as specified in the Standards or your delegation agreement;

(b) Resolve and respond to all production reporter or royalty reporter inquiries;

(c) Maintain all documentation and logging procedures as specified in the Standards or your delegation agreement;

(d) Access well, lease, agreement, and production reporter or royalty reporter reference data from ONRR and provide updated information to ONRR; and

(e) Comply with procedures for appealed demands and orders, including meeting time frames, supplying information, and using the appropriate format.

§ 1227.700 What enforcement documents may a State issue in support of its delegated function?

This section explains what enforcement actions you may take as part of your delegated functions.

(a) You may issue demands, subpoenas, and orders to perform restructured accounting, including related notices to lessees and their designees. You also may enter into tolling agreements under section 15(d)(1) of the Act, 30 U.S.C. 1725(d)(1).

(b) When you issue any enforcement document you must comply with the requirements of section 115 of the Act, 30 U.S.C. 1725.

(c) When you issue a demand or enter into a tolling agreement under section 15(d)(1) of the Act, 30 U.S.C. 1725(d)(1), the highest State official having ultimate authority over the collection of royalties or the State official to whom that authority has been delegated must sign the demand or tolling agreement.

(d) When you issue a subpoena or order to perform a restructured accounting you must:

(1) Coordinate with ONRR to ensure identification of issues that may concern more than one State before you issue subpoenas and orders to perform restructured accounting; and

(2) Ensure that the highest State official having ultimate authority over the collection of royalties signs any subpoenas and orders to perform restructured accounting, as required under section 115 of the Act, 30 U.S.C. 1725. This official may not delegate signature authority to any other person.

§ 1227.800 How will ONRR monitor a State's performance of delegated functions?

This section explains ONRR's procedures for monitoring your performance of any of your delegated functions.

(a) A monitoring team of ONRR officials will annually review your performance of the delegated functions and compliance with your delegation agreement, the Standards, and 30 U.S.C. 1735, including conducting fiscal examination to verify your costs for reimbursement.

(b) The monitoring team also will:

(1) Periodically review your statistical reports required under § 1227.200(e) to verify your accuracy, timeliness, and efficiency;

(2) Check for timely transmittal of production report or royalty report information to ONRR and other affected agencies, as applicable, to allow for proper disbursement of funds and processing of information;

(3) Coordinate on-site visits and Office of the Inspector General, General Accounting Office, and ONRR audits of your performance of your delegated functions; and

(4) Maintain reports of its monitoring activities.

[62 FR 43084, Aug. 12, 1997, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1227.801 What if a State does not adequately perform a delegated function?

If your performance of the delegated function does not comply with your delegation agreement, or the Standards, or if ONRR finds that you can no longer meet the statutory requirements under § 1227.106, then ONRR may:

(a) Notify you in writing of your noncompliance or inability to comply. The notice will prescribe corrective actions you must take, and how long you have to comply. You may ask ONRR for an extension of time to comply with the notice. In your extension request you must explain why you need more time; and

(b) If you do not take the prescribed corrective actions within the time that ONRR allows in a notice issued under paragraph (a) of this section, then ONRR may:

(1) Initiate proceedings under § 1227.802 to terminate all or a part of your delegation agreement;

(2) Withhold compensation provided to you under § 1227.112; and

(3) Perform the delegated function, before terminating or without terminating your delegation agreement, including, but not limited to, issuing a demand or order to a Federal lessee, or its designee, or any other person when:

(i) Your failure to issue the demand or order would result in an underpayment of an obligation due ONRR; and

(ii) The underpayment would go uncollected without ONRR intervention.

§ 1227.802 How will ONRR terminate a State's delegation agreement?

This section explains the procedures ONRR will use to terminate all or a part of your delegation agreement:

(a) ONRR will notify you in writing that it is initiating procedures to terminate your delegation agreement;

(b) ONRR will provide you notice and opportunity for a hearing under § 1227.803 of this part;

(c) The ONRR Director, with concurrence from the Secretary, will decide whether to terminate your delegation agreement.

(d) After the hearing, ONRR may:

(1) Terminate your delegation agreement; or

(2) Allow you 30 days to correct any remaining deficiencies. If you do not correct the deficiency within 30 days, ONRR will terminate all or a part of your delegation agreement.

(e) ONRR will determine the date your agreement is terminated and will notify you of that date in writing. ONRR will determine the termination date based on the number of delegated functions and the impact of the termination on all affected parties.

§ 1227.803 What are the hearing procedures for terminating a State's delegation agreement?

(a) The ONRR Director will appoint a hearing official to conduct one or more public hearings for fact finding and to determine any actions you must take to correct the noncompliance. The hearing official will not decide whether to terminate your delegation agreement;

(b) The hearing official will contact you about scheduling a hearing date and location;

(c) The hearing official will publish notice of the hearing in the Federal Register and other appropriate media within your State;

(d) At the hearing, you will have an opportunity to present testimony and written information on your ability to perform your delegated functions as required under this part, your delegation agreement, and the Standards;

(e) Other persons may attend the hearing and may present testimony and written information for the record;

(f) ONRR will record the hearing;

(g) After the hearing, ONRR may require you to submit additional information; and

(h) Information presented at each public hearing will help ONRR to determine whether:

(1) You have complied with the terms and conditions of your delegation agreement; or

(2) You have the capability to comply with the requirements under § 1227.106 of this part.

[62 FR 43084, Aug. 12, 1997, as amended at 75 FR 61087, Oct. 4, 2010]

§ 1227.804 How else may a State's delegation agreement terminate?

You may request ONRR to terminate your delegation at any time by submitting your written notice of intent 6 months prior to the date on which you want to terminate. ONRR will determine the date your agreement is terminated and will notify you of that date in writing. ONRR will determine the termination date based on the number of delegated functions and the impact of the termination on all affected parties.

§ 1227.805 How may a State obtain a new delegation agreement after termination?

After your delegation agreement is terminated, you may apply again for delegation by beginning with the proposal process under this part.

§ 1228.1 Purpose.

It is the purpose of cooperative agreements to effectively utilize the capabilities of the States and Indian tribes in developing and maintaining an efficient and effective Federal royalty management system as indicated at 30 U.S.C. 1701.

§ 1228.2 Policy.

It shall be the policy of DOI to enter into cooperative agreements with States and Indian tribes to carry out audits and related investigations and enforcement actions whenever a State or tribe initiates a request to enter into an agreement and a finding is made that a State or tribe has the ability to carry out cooperative activities in a timely and efficient manner.

§ 1228.3 Limitation on applicability.

As of the effective date of this rule, September 11, 1997, this part does not apply to Federal lands.

[62 FR 43091, Aug. 12, 1997]

§ 1228.4 Authority.

The Secretary of the Interior is authorized to enter into cooperative agreements with States and Indian tribes (30 U.S.C. 1732) to share oil or gas royalty management information, and to carry out auditing and related investigation or enforcement activities in cooperation with the Secretary.

§ 1228.5 Delegation of authority.

(a) Authority to enter into cooperative agreements to carry out audit and related investigation and enforcement activities with State and tribal governments has been delegated to the Director of the Office of Natural Resources Revenue (ONRR).

(b) Authority to enter into cooperative agreements with State and tribal governments to carry out inspection and related investigation and enforcement activities has been delegated to the Director of the Bureau of Land Management (BLM) and is not covered by this part.

(c) The entry into a cooperative agreement with either ONRR or BLM will not affect the ability of a State or Indian tribe to choose to enter into such an agreement with the other agency. A State may enter into a delegation agreement (30 U.S.C. 1735) with ONRR to perform certain functions without affecting its ability to enter into a cooperative agreement with either ONRR or BLM, or both, to cooperate in the performance of those functions which are not delegated in this part.

§ 1228.6 Definitions.

For the purposes of this part, terms shall have the same meaning as in 30 U.S.C. 1702. In addition, the following definition shall apply:

Audit means an examination of the financial accounting and lease related records of the lessee and other interest holders, who by lease or contract pay royalties or are obligated to pay royalties, rents, bonuses or other payments on Federal or Indian leases. An examination is to be conducted in accordance with generally accepted audit standards as adopted by the American Institute of Certified Public Accountants. Activities to be examined which are considered to be an audit function include reconciliation of lease accounts under the Royalty Accounting System; records of lease activities related to Federal leases located within the boundaries of the State entering into a cooperative agreement; records of lease activities related to leases located on Indian lands, and the review and resolution of exceptions processed by the official accounting systems for royalty reporters and payors maintained by the ONRR.

[49 FR 37348, Sept. 21, 1984, as amended at 67 FR 19112, Apr. 18, 2002]

§ 1228.10 Information collection.

(a) The Office of Management and Budget (OMB) approved the information collection requirements contained in this part under 44 U.S.C. 3501 et seq. The approved OMB control number is identified in 30 CFR 1210.10. The information collected will be used to prepare a cooperative agreement with a State or Indian tribe wishing to perform royalty audits. The information should be submitted voluntarily in order to enter into a cooperative agreement authorized by 30 U.S.C. 1732.

(b) Send comments regarding the burden estimates or any other aspect of this information collection, including suggestions for reducing burden, to the Office of Natural Resources Revenue, Attention: Rules & Regs Team, OMB Control Number 1012-0003, P.O. Box 25165, Denver, CO 80225-0165.

[57 FR 41868, Sept. 14, 1992, as amended at 58 FR 64903, Dec. 10, 1993; 76 FR 76617, Dec. 8, 2011]

§ 1228.100 Entering into an agreement.

(a) A State or Indian tribe may request the Department to enter into a cooperative agreement by sending a letter from the governor, tribal chairman, or other appropriate official with delegation authority, to the Director of ONRR.

(b) The request for an agreement shall be in a format prescribed by ONRR and should include at a minimum the following information:

(1) Type of eligible activities to be undertaken.

(2) Proposed term of the agreement.

(3) Evidence that the State or Indian tribe meets, or can meet by the time the agreement is in effect, the standards established by the Secretary for the types of activities to be conducted under the terms of the agreement.

(4) If the State is proposing to undertake activities on Indian lands located within the State, a resolution from the appropriate tribal council indicating their agreement to delegate to the State responsibilities under the terms of the cooperative agreement for activities to be conducted on tribal or allotted land.

(c) The eligible activities to be conducted under the terms of a cooperative agreement may be funded or unfunded by the Department. See § 1228.105 of this subpart for funding of cooperative agreements.

[49 FR 37348, Sept. 21, 1984, as amended at 56 FR 10512, Mar. 13, 1991]

§ 1228.101 Terms of agreement.

(a) Agreements entered into under this part shall be valid for a period of 3 years and shall be renewable or additional consecutive 3-year periods upon request of the State or Indian tribe which is a party to the agreement.

(b) An agreement may be terminated at any time by mutual agreement and upon any terms and conditions as agreed upon by the parties.

(c) A State or Indian tribe may unilaterally terminate an agreement by giving a 120-day written notice of intent to terminate.

(d) The ONRR may commence termination of an agreement by giving a 120-day written notice of intent to terminate. ONRR shall provide the State or Indian tribe with the reasons for the proposed termination in writing if the termination is proposed because of alleged deficiencies by the State or Indian tribe in carrying out the provisions of the agreement. The State or Indian tribe will be given 60 days to respond to the notice of deficiencies and to provide a plan for correction of those deficiencies. No final action on termination shall be taken until any submission of the State or Indian tribe provided within the above prescribed 60 days has been reviewed by ONRR for content or merit.

(e) Termination of a cooperative agreement shall not bar a later request by a State or Indian tribe to enter into a subsequent cooperative agreement.

§ 1228.102 Establishment of standards.

The ONRR, after consultation with States and Indian tribes, shall establish standards for carrying out the activities under the provisions of this part. The standards will be incorporated into the agreement and shall be no more stringent than those applicable to similar activities of the ONRR. The States and Indian tribes shall coordinate their planned auditing activities with ONRR. Where an ONRR audit team is permanently assigned to a lessee/payor, contact by State and Indian tribal auditors with the lessee/payor shall be through the ONRR auditor in residence.

§ 1228.103 Maintenance of records.

(a) The State or Indian tribe entering into a cooperative agreement under this part must retain all records, reports, working papers, and any backup materials for a period specified by ONRR. All records and support materials must be available for inspection and review by appropriate personnel of the Department including the Office of the Inspector General.

(b) The State or Indian tribe shall maintain all books and records as may be necessary to assure compliance with the provisions of chapter 1, 48 CFR 31.107 and 48 CFR subpart 31.6 (Contracts with State, local, and federally recognized Indian tribal Governments).

[56 FR 10512, Mar. 13, 1991]

§ 1228.104 Availability of information.

(a) Under the provisions of this part, information necessary to carry out the activities authorized under the terms of a cooperative agreement will be provided by DOI to the States and Indian tribes entering into such agreements. The information will consist of data provided from all relevant sources on a lease level basis for leases located within the boundaries of the State or Indian tribe which has entered into the agreement. This information will include any records or data held by the lessee or other person that have not been submitted to ONRR, but that affect Federal lease interests and could be required to be submitted under the lease terms or Federal regulations.

(b) None of the provisions of this subpart should be construed as limiting information already being provided to Indian tribes and allottees regarding their lease interests.

(c) Information will be provided by ONRR on a monthly basis and will include data on royalties, rents, and bonuses collected on the lease, volumes produced, sales made, value of products disposed of as a sale and used as a basis for royalty calculation, and other information necessary to allow the State or tribe to carry out its responsibilities under the cooperative agreement.

(d) Proprietary data that is made available to a State or tribe under provisions of 30 U.S.C. 1733 shall be subject to the constraints of 18 U.S.C. 1905. To receive proprietary data, the State or tribe must—

(1) Demonstrate what audit, investigation, or litigation under provisions of 30 U.S.C. 1734 is planned for or underway for which this data is essential;

(2) Demonstrate why this particular data is necessary; and

(3) Agree to safeguard proprietary data as provided.

§ 1228.105 Funding of cooperative agreements.

(a)(1) The Department may, under the terms of the cooperative agreement, reimburse the State or Indian tribe up to 100 percent of the costs of eligible activities. Eligible activities will be agreed upon annually upon the submission and approval of a workplan and funding requirement.

(2) A cooperative agreement may be entered into with a State or Indian tribe, upon request, without a requirement for reimbursement of costs by the Department.

(b) All cooperative agreements under this part are subject to annual funding and the availability of appropriations specifically designated for the purpose of this part.

(c) The State or Indian tribe shall submit a voucher for reimbursement of eligible costs incurred within 30 days of the end of each calendar quarter. The State or Indian tribe must provide the Department a summary of costs incurred, for which the State or Indian tribe is seeking reimbursement, with the voucher.

[49 FR 37348, Sept. 21, 1984, as amended at 56 FR 10512, Mar. 13, 1991]

§ 1228.107 Eligible cost of activities.

(a) If a cooperative agreement provides for Federal funding, only costs directly associated with eligible activities undertaken by the State or Indian tribe under the terms of a cooperative agreement will be eligible for reimbursement. Costs of services or activities which cannot be directly related to the support of activities specified in the agreement will not be eligible for Federal funding or for inclusion in the State's share or in the Indian tribe's share of funding that may be established in the agreement.

(b) Eligible costs are the cost of salaries and benefits associated with technical, support, and clerical personnel engaged in eligible activities; direct cost of travel, rentals, and other normal administrative activities in direct support of the project or projects; basic and specialized training for State and tribal participants; and cost of any contractual services which can be shown to be in direct support of the activities covered by the agreement. Each cooperative agreement shall contain detailed schedules identifying those activities and costs which qualify for funding and the procedures, timing, and mechanics for implementing Federal funding.

[49 FR 37348, Sept. 21, 1984, as amended at 56 FR 10512, Mar. 13, 1991]

§ 1228.108 Deduction of civil penalties accruing to the State or tribe from the Federal share of a cooperative agreement.

As provided at 30 U.S.C. 1736, 50 percent of any civil penalty collected as a result of activities under a cooperative agreement will be shared with the State or Indian tribe performing the cooperative agreement; however, the amount of the civil penalty shared will be deducted from any Federal funding owed under that cooperative agreement. ONRR shall maintain records of civil penalties collected and distributed to the States and tribes involved in cooperative agreements. Each quarterly payment of the Federal share of a cooperative agreement will be reduced by the amount of the civil penalties paid to the State or tribe during the prior quarter.

§ 1229.1 Purpose.

The purpose of this part is to promote the effective utilization of the capabilities of the States in developing and maintaining an efficient and effective Federal royalty management system.

§ 1229.2 Policy.

It shall be the policy of the Department of the Interior (DOI) to honor any properly made petition from the Chief Executive or other appropriate official of a State seeking delegation of authority under the provisions of 30 U.S.C. 1735 and to make a delegation to conduct audits and related investigations when the Secretary finds that the provisions of 30 U.S.C. 1735 have been complied with or can be complied with by a State seeking the delegation.

§ 1229.3 Limitation on applicability.

As of the effective date of this rule, September 11, 1997, this part does not apply to Federal lands.

[62 FR 43091, Aug. 12, 1997]

§ 1229.4 Authority.

The Secretary of the DOI is authorized under provisions of 30 U.S.C. 1735 to delegate authority to States to conduct audits and related investigations with respect to all Federal lands within a State, and to those Indian lands to which a State has received permission from the respective Indian tribe(s) or allottee(s) to carry out audit activities under a delegation from the Secretary.

§ 1229.6 Definitions.

The definitions contained in 30 U.S.C. 1702 and in part 228 of this title apply to the activities carried out under the provisions of this part.

§ 1229.10 Information collection requirements.

The information collection requirements contained in this part do not require approval by the Office of Management and Budget under 44 U.S.C. 3501 et seq., because there are fewer than 10 respondents annually.

§ 1229.100 Authorities and responsibilities subject to delegation.

(a) All or part of the following authorities and responsibilities of the Secretary under the Act may be delegated to a State authority:

(1) Conduct of audits related to oil and gas royalty payments made to the Office of Natural Resources Revenue (ONRR) which are attributable to leased Federal or Indian lands within the State. Delegations with respect to any Indian lands require the written permission, subject to the review of the ONRR, of the affected Indian tribe or allottee.

(2) Conduct of investigations related to oil and gas royalty payments made to the ONRR which are attributable to leased Federal lands or Indian lands within the State. Delegation with respect to any Indian lands require the written permission, subject to the review of the ONRR, of the affected Indian tribe or allottee. No investigation will be initiated without the specific approval of the ONRR or the Secretary's designee and in accordance with the Departmental Manual.

(b) The following authorities and responsibilities are specifically reserved to the ONRR and are not delegable under these regulations:

(1) Enforcement actions to assess and collect additional royalties identified as a consequence of audits, inspections, and investigations. These include all actions related to resolution of royalty obligations so identified, and the establishment and maintenance of payment performance bonds which may be required during the resolution process.

(2) Enforcement actions to collect civil penalties and interest charges related to findings of audits, inspections, and investigations.

(3) Administration of all appeals and all actions of the Department related to administrative and judicial litigation.

(4) Issuance of subpoenas.

(c) The provisions of this section do not limit the authority provided to the States by section 204 of the Act.

[49 FR 40026, Oct. 12, 1984]

§ 1229.101 Petition for delegation.

(a) The governor or other authorized official of any State which contains Federal oil and gas leases, or Indian oil and gas leases where the Indian tribe and allottees have given the State an affirmative indication of their desire for the State to undertake certain royalty management-related activities on their lands, may petition the Secretary to assume responsibilities to conduct audits and related investigations of royalty related matters affecting Federal or Indian oil and gas leases within the State.

(b) A State may enter into a delegation of authority under this part without affecting a State's ability to enter into a cooperative agreement under part 228 of this title.

(c) The Secretary shall carry out all factfinding and hearings he may decide are necessary in order to approve or disapprove the petition.

(d) In the event that the Secretary denies the petition, the Secretary must provide the State with the specific reasons for denial of the petition. The State will then have 60 days to either contest or correct specific deficiencies and to reapply for a delegation of authority.

[49 FR 37350, Sept. 21, 1984. Redesignated and amended at 49 FR 40025, Oct. 12, 1984]

§ 1229.102 Fact-finding and hearings.

(a) Upon receipt of a petition for delegation from a State, the Secretary shall appoint a representative to conduct a hearing or hearings to carry out factfinding and determine the ability of the petitioning State to carry out the delegated responsibilities requested in accordance with the provisions of this part.

(b) The Secretary's representative, after proper notice in the Federal Register and other appropriate media within the State, shall hold one or more public hearings to determine whether:

(1) The State has an acceptable plan for carrying out delegated responsibilities and if it is likely that the State will provide adequate resources to achieve the purposes of this part (30 U.S.C. 1735);

(2) The State has the ability to put in place a process within 60 days of the grant of delegation which will assure the Secretary that the functions to be delegated to the State can be effectively carried out;

(3) The State has demonstrated that it will effectively and faithfully administer the rules and regulations of the Secretary in accordance with the requirements at 30 U.S.C. 1735;

(4) The State's plan to carry out the delegated authority will be in accordance with the ONRR standards; and

(5) The State's plan to carry out the delegated authority will be coordinated with ONRR and the Office of Inspector General audit efforts to eliminate added burden on any lessee or group of lessees operating Federal or Indian oil and gas leases within the State.

(c) A State petitioning for a delegation of authority shall be given the opportunity to present testimony at a public hearing.

[49 FR 37350, Sept. 21, 1984. Redesignated and amended at 49 FR 40025, Oct. 12, 1984]

§ 1229.103 Duration of delegations; termination of delegations.

(a) Delegations of authority shall be valid for a period of 3 years and may be renewable for an additional consecutive 3-year period upon request of the State and after the appropriate factfinding required in § 1229.101. Delegations are subject to annual funding and the availability of appropriations specifically designated for the purpose of this part.

(b) A delegation of authority may be terminated at any time and upon any terms and conditions as mutually agreed upon by the parties.

(c) A State may terminate a delegation of authority by giving a 120-day written notice of intent to terminate.

(d) The Department may terminate a delegation of authority when it is determined, after opportunity for a hearing, that the State has failed to substantially comply with the provisions of the delegation of authority.

(e) No action to initiate formal hearing proceedings for termination shall be taken until the Department has notified the State in writing of alleged deficiencies and allowed the State 120 days to correct the deficiencies.

(f) Termination of a delegation shall not bar a subsequent request by a State to regain a delegation of authority.

[49 FR 37351, Sept. 21, 1984, as amended at 49 FR 40025, Oct. 12, 1984]

§ 1229.104 Terms of delegation of authority.

Each delegation of authority under this part shall be in writing, shall incorporate all the requirements of this part, and shall specifically include:

(a) Terms obligating the State to conduct audit and investigative activities for a specific period of time;

(b) Terms describing the authorities and responsibilities reserved by the ONRR, including, but not limited to, those specified under § 1229.100;

(c) Terms requiring the State to provide annual audit workplans to include the lease universe by company, or by individual lease accounts, a description of the audit work product(s) to be delivered, and the State resources (staff and otherwise) to be committed to the delegation;

(d) Terms requiring the State to notify the ONRR of any changed circumstances which would affect the State's ability to carry out the terms of the delegation;

(e) Terms requiring coordination of delegated activities among the State, the ONRR, and the land management agencies responsible for management of the leases included in the audit universe;

(f) Terms requiring the State to maintain and make available to the ONRR all audit workpapers, documents, and information gained or developed as a consequence of activities conducted under the delegation;

(g) Terms obligating the State to adhere to all Federal laws, rules and regulations, and Secretarial determinations and orders relating to the calculation, reporting, and payment of oil and gas royalties, in all activities performed under the delegation.

[49 FR 40026, Oct. 12, 1984]

§ 1229.105 Evidence of Indian agreement to delegation.

In the case of a State seeking a delegation of authority for Indian lands as well as Federal lands, the State petition to the Secretary must be supported by an appropriate resolution or resolutions of tribal councils joining the State in petitioning for delegation and evidence of the agreement of individual Indian allottees whose lands would be involved in a delegation. Such evidence shall specifically speak to having the State assume delegated responsibility for specific functions related to royalty management activities.

[49 FR 37351, Sept. 21, 1984. Redesignated at 49 FR 40025, Oct. 12, 1984]

§ 1229.106 Withdrawal of Indian lands from delegated authority.

If at any time an Indian tribe or an individual Indian allottee determines that it wishes to withdraw from the State delegation of authority in relation to its lands, it may do so by sending a petition of withdrawal to the State. Once the petition has been received, the State shall within 30 days cease all activities being carried out under the delegation of authority on the lands covered by the petition for the tribe or allottee.

[49 FR 37351, Sept. 21, 1984. Redesignated at 49 FR 40025, Oct. 12, 1984]

§ 1229.107 Disbursement of revenues.

(a) The additional royalties and late payment charges resulting from State audit work done under a delegation of authority shall be collected by ONRR. The State's share of any amounts so collected shall be paid to the State in accordance with the provisions of 30 U.S.C. 191 and part 1219 of this title.

(b) Amounts collected for Indian leases shall be transferred to the appropriate Indian accounts (designated Treasury accounts) managed by the Bureau of Indian Affairs at the earliest practicable date after such funds are received, but in no case later than the last business day of the month in which such funds are received.

(c) ONRR shall provide to the State on a monthly basis, an accounting of collections resulting from audit work and enforcement actions resulting from a delegation of authority. Such accounting will identify collections broken down by royalties, penalties and interest paid.

[49 FR 40026, Oct. 12, 1984]

§ 1229.108 Deduction of civil penalties accruing to the State or tribe under the delegation of authority.

Fifty percent of any civil penalty resulting from activities under a delegation of authority shall be shared with the delegated State. However, the amount of the civil penalty shared will be deducted from any Federal funding owed under a delegation of authority under the provisions of 30 U.S.C. 1735. ONRR shall maintain records of civil penalties collected and distributed to the States involved in 30 U.S.C. 1735 delegations. Each quarterly payment will be reduced by the amount of the civil penalties paid to the delegated State or tribe during the prior quarter.

[49 FR 37351, Sept. 21, 1984. Redesignated at 49 FR 40025, Oct. 12, 1984]

§ 1229.109 Reimbursement for costs incurred by a State under the delegation of authority.

(a) The Department of the Interior (DOI) shall reimburse the State for 100 percent of the direct cost associated with the activities undertaken under the delegation of authority. The State shall maintain books and records in accordance with the standards established by the DOI and will provide the DOI, on a quarterly basis, a summary of costs incurred for which the State is seeking reimbursement. Only costs as defined under the provisions of 30 U.S.C. 1735 are eligible for reimbursement.

(b) The State shall submit a voucher for reimbursement of costs incurred within 30 days of the end of each calendar quarter.

[49 FR 37351, Sept. 21, 1984]

§ 1229.110 Examination of the State activities under delegation.

(a) The Department will carry out an annual examination of the State's delegated activities undertaken under the delegation of authority.

(b) The examination required by this section will consist of a management review and a fiscal examination and evaluation to determine—

(1) That activities being carried out by the State under the delegation of authority meet the standards established by the Department and in particular the provisions of 30 U.S.C. 1735; and

(2) That costs incurred by the State under the delegation of authority are eligible for reimbursement by the Department.

[49 FR 37351, Sept. 21, 1984. Redesignated at 49 FR 40025, Oct. 12, 1984]

§ 1229.111 Materials furnished to States necessary to perform delegation.

The ONRR shall provide to the State all reports, files, and supporting materials within its possession necessary to allow the State to effectively carry out the terms of the delegation specified in § 1229.104.

[49 FR 40026, Oct. 12, 1984]

§ 1229.120 Obtaining regulatory and policy guidance.

All activities performed by a State under a delegation must be in full accord with all Federal laws, rules and regulations, and Secretarial and agency determinations and orders relating to the calculation, reporting, and payment of oil and gas royalties. In those cases when guidance or interpretations are necessary, the State will direct written requests for such guidance or interpretation to the appropriate ONRR officials. All policy and procedural guidance or interpretation provided by the ONRR shall be in writing and shall be binding on the State.

§ 1229.121 Recordkeeping requirements.

(a) The State shall maintain in a safe and secure manner all records, workpapers, reports, and correspondence gained or developed as a consequence of audit or investigative activities conducted under the delegation. All such records shall be made available for review and inspection upon request by representatives of the Secretary and the Department's Office of Inspector General (OIG).

(b) The State must maintain in a confidential manner all data obtained from DOI sources or from payor or company sources under the delegation which have been deemed “confidential or proprietary” by DOI or a company or payor. In this regard, the State regulatory authority shall be bound by provisions of 30 U.S.C. 1733. ONRR shall provide to the State guidelines for determining confidential and proprietary material.

(c) All records subject to the requirements of paragraph (a) must be maintained for a 6-year period measured from the end of the calendar year in which the records were created. All dispositions or records must be with the written approval of the ONRR. Upon termination of a delegation, the State shall, within 90 days from the date of termination, assemble all records specified in subsection (a), complete all working paper files in accordance with § 1229.124, and transfer such records to the ONRR.

(d) The State shall maintain complete cost records for the delegation in accordance with generally accepted accounting principles. Such records shall be in sufficient detail to demonstrate the total actual costs associated with the project and to permit a determination by ONRR whether delegation funds were used for their intended purpose. All such records shall be made available for review and inspection upon request by representatives of the Secretary and the Department's Office of Inspector General (OGIG).

§ 1229.122 Coordination of audit activities.

(a) Each State with a delegation of authority shall submit annually to the ONRR an audit workplan specifically identifying leases, resources, companies, and payors scheduled for audit. This workplan must be submitted 120 days prior to the beginning of each fiscal year. A State may request changes to its workplan (including the companies and leases to be audited) at the end of each quarter of each fiscal year. All requested changes are subject to approval by the ONRR and must be submitted in writing.

(b) When a State plans to audit leases of a lessee or royalty payor for which there is an ONRR or OIG resident audit team, all audit activities must be coordinated through the ONRR or OIG resident supervisor. Such activities include, but are not limited to, issuance of engagement letters, arranging for entrance conferences, submission of data requests, scheduling of audit activities including site visits, submission of issue letters, and closeout conferences.

(c) The State shall consult with the ONRR and/or OIG regarding resolution of any coordination problems encountered during the conduct of delegation activities.

§ 1229.123 Standards for audit activities.

(a) All audit activities performed under a delegation of authority must be in accordance with the “Standards for Audit of Governmental Organizations, Programs, Activities, and Functions” as issued by the Comptroller General of the United States.

(b) The following audit standards also shall apply to all audit work performed under a delegation of authority.

(1) General standards—(i) Qualifications. The auditors assigned to perform the audit must collectively possess adequate professional proficiency for the tasks required, including a knowledge of accounting, auditing, agency regulations, and industry operations.

(ii) Independence. In all matters relating to the audit work, the audit organization and the individual auditors must be free from personal or external impairments to independence and shall maintain an independent attitude and appearance.

(iii) Due professional care. Due professional care is to be used in conducting the audit and in preparing related reports.

(iv) Quality control. The State governments must institute quality control review procedures to ensure that all audits are performed in conformity with the standards established herein.

(2) Examination and evaluation standards—Standards and requirements for examination and evaluation. Auditors should be alert to situations or transactions that could be indicative of fraud, abuse, or illegal acts with respect to the program. If such evidence exists, auditors should forward this evidence to ONRR. The ONRR will contact the appropriate Federal law enforcement agencies. The scope of examinations are to be governed by the principle of a justifiable relationship between cost and benefit as determined by the auditor or audit supervisor. Audit procedures should reflect the most efficient method of obtaining the requisite degree of satisfaction. The auditor should determine, to the extent possible, the effect on royalty reporting of the non-arms'-length nature of related party transactions, such as transfers of oil to refinery units affiliated with the producer. A review should be made of compliance with the appropriate laws and regulations applicable to program operations. ONRR shall issue guidelines as to the definition and nature of arms'-length and non-arms'-length transactions for use in carrying out delegated audit activities.

(3) Standards of reporting. (i) Written audit reports are to be submitted to the appropriate ONRR officials at the end of each field examination.

(ii) A statement in the auditors' report that the examination was made in accordance with the generally accepted program audit standards (including the applicable General Accounting Office (GAO) standards) for royalty compliance audits should be in the appropriate language to indicate that the audit was made in accordance with this statement of standards.

(iii) The auditor's report should contain a statement of positive assurance on those items tested and negative assurance on those items not tested. It should also include all instances of noncompliance and instances or indications of fraud, abuse, or illegal acts found during or in connection with the audit.

(iv) The auditor's report should contain any other material deficiency identified during the audit not covered in paragraph (b)(3)(iii) of this section.

(v) When factors external to the program and to the auditor restrict the audit or interfere with the auditor's ability to form objective opinions and conclusions (such as denial of access to information by a company), the auditor is to notify the ONRR. If the limitation is not removed, a description of the matter must be included in the auditor's report. ONRR will take all legally enforceable steps necessary to seek information necessary to complete the audit.

(vi) If certain information is prohibited from general disclosure, the auditor's report should state the nature of the information omitted and the requirement that makes the omission necessary.

(vii) Written audit reports are to be prepared in the format prescribed by the ONRR.

(viii) In instances where the extent of the audit findings or the amounts involved do not warrant it, a formal audit report need not be issued. In lieu of an audit report, a memorandum of audit findings will be prepared and placed on the case file.

[49 FR 40026, Oct. 12, 1984, as amended at 58 FR 64903, Dec. 10, 1993]

§ 1229.124 Documentation standards.

Every audit performed by a State under a delegation of authority must meet certain documentation standards. In particular, detailed workpapers must be developed and maintained.

(a) Workpapers are defined to include all records obtained or created in performing an audit.

(b) Each audit performed varies in scope and detail. As a result, the audit team must determine the best presentation of the workpapers for a particular audit. The following general standards of workpaper preparation are consistent with the goal of achieving proper documentation while maintaining sufficient flexibility.

(1) All relevant information obtained orally must be promptly recorded in writing and incorporated in the workpapers.

(2) Workpapers must be complete and accurate in order to provide support for findings and conclusions.

(3) Workpapers should be clear and understandable without the need for supplementary oral explanations. The information they contain must be clear, complete, and concise, so that anyone using the workpapers will be able to readily determine their purpose, the nature and scope of the work done, and the conclusions drawn.

(4) Workpapers must be legible and as neat as practicable. They must meet standards which allow their use as evidence in judicial and administrative proceedings.

(5) The information contained in workpapers should be restricted to matters which are materially important and relevant to the objectives established for the assignment.

(6) Workpapers must be in sufficient detail to permit a subsequent independent execution of each audit procedure, assuming the target company retains its accounting documentation.

§ 1229.125 Preparation and issuance of enforcement documents.

(a) Determinations of additional royalties due resulting from audit activities conducted under a delegation of authority must be formally communicated by the State, to the companies or other payors by an issue letter prior to any enforcement action. The issue letter will serve to ensure that all audit findings are accurate and complete by obtaining advance comments from officials of the companies or payors audited. Issue letters must be prepared in a format specified by the ONRR, and transmitted to the company or payor. The company or payor shall be given 30 days from receipt of the letter to respond to the State on the findings contained in the letter.

(b) After evaluating the company or payor's response to the issue letter, the State shall draft a demand letter which will be submitted with supporting workpaper files to the ONRR for appropriate enforcement action. Any substantive revisions to the demand letter will be discussed with the State prior to issuance of the letter. Copies of all enforcement action documents shall be provided to the State by ONRR upon their issuance to the company or payor.

§ 1229.126 Appeals.

(a) Appeals made pursuant to the rules and procedures at 30 CFR parts 1243 and 1290 related to demand letters issued by officers of the ONRR for additional royalties identified under a delegation of authority shall be filed with the ONRR for processing. The State regulatory authority shall, upon the request of the ONRR, provide competent and knowledgeable staff for testimony, as well as any required documentation and analyses, in support of the lessor's position during the appeal process.

(b) An affected State, upon the request of the ONRR, shall provide expert witnesses from their audit staff for testimony as well as required documentation and analyses to support the Department's position during the litigation of court cases arising from denied appeals. The cost of providing expert witnesses including travel and per diem is reimbursable under the provisions of a delegation of authority, at the Federal Government's existing per diem rates.

§ 1229.127 Reports from States.

The State, acting under the authority of the Secretarial delegation, shall submit quarterly reports which will summarize activities carried out by the State during the preceding quarter of the year under the provisions of the delegation. The report shall include:

(a) A statistical summary of the activities carried out, e.g., number of audits performed, accounts reconciled, and other actions taken;

(b) A summary of costs incurred during the previous quarter for which the State is seeking reimbursement; and

(c) A schedule of changes which the State proposes to make from its approved plan.

[49 FR 37351, Sept. 21, 1984. Redesignated at 49 FR 40025, Oct. 12, 1984]

§ 1241.1 What is the purpose of this part?

This part explains:

(a) When you may receive a NONC, FCCP, or ILCP.

(b) How ONRR assesses a civil penalty.

(c) How to appeal a NONC, FCCP, or ILCP.

§ 1241.2 What leases are subject to this part?

This part applies to:

(a) All Federal mineral leases onshore and on the OCS.

(b) All Federally-administered mineral leases on Indian Tribal and individual Indian mineral owners' lands, regardless of the statutory authority under which the lease was issued or maintained.

(c) All easements, rights of way, and other agreements subject to 43 U.S.C. 1337(p).

§ 1241.3 What definitions apply to this part?

(a) Unless specifically defined in paragraph (b) of this section, the terms in this part have the same meaning as in 30 U.S.C. 1702.

(b) The following definitions apply to this part:

Agent means any individual or other person with the actual authority of, with the apparent authority of, or designated by a person subject to FOGRMA who acts or who, with apparent authority, appears to act on behalf of the person subject to FOGRMA.

ALJ means an Administrative Law Judge in the DCHD.

Assessment means a civil penalty set out in a FCCP or ILCP; it includes a dollar amount per violation for each day the violation continues. In this part “assessment” is used consistent with 30 U.S.C. 1719(k), but is distinguishable from “assessment” as defined in 30 U.S.C. 1702(19) and used in 30 U.S.C. 1702(25). Correspondence that we send to you to update you on the amount of penalties accrued or outstanding under a FCCP or ILCP we previously served on you is not an assessment.

DCHD means the Departmental Cases Hearings Division, Office of Hearings and Appeals.

FCCP means a Failure to Correct Civil Penalty Notice; it assesses a civil penalty if you fail to correct a violation identified in a NONC.

FOGRMA means the Federal Oil and Gas Royalty Management Act.

IBLA means the Interior Board of Land Appeals, Office of Hearings and Appeals.

ILCP means an Immediate Liability Civil Penalty Notice; it identifies a violation and assesses a civil penalty for the violation even if you have not been provided prior notice and an opportunity to correct the violation.

Information means any data that you provide to an ONRR data system, or otherwise provide to us for our official records, including, but not limited to, any report, notice, affidavit, record, data, or document that you provide to us, any document that you provide to us in response to our request, and any other written information that you provide to us.

Knowingly or willfully includes an act or failure to act committed with:

(i) Actual knowledge;

(ii) Deliberate ignorance; or

(iii) Reckless disregard of the facts surrounding the event or violation; it requires no proof of specific intent to defraud.

Maintains false, inaccurate, or misleading information includes providing information to an ONRR data system, or otherwise to us for our official records, and later learning that the information that you provided was false, inaccurate, or misleading, and you do not correct that information or other information that you provided to us that you know or should know contains the same false, inaccurate, or misleading information.

NONC means a Notice of Noncompliance; it identifies a violation, specifies the corrective action that must be taken, and establishes the deadline for such action to avoid a civil penalty.

Notice means a NONC, FCCP, or ILCP, as defined in this section.

OCS means the Outer Continental Shelf.

ONRR means the Office of Natural Resources Revenue (also referred to in the regulations as “we,” “our,” and “us,” as appropriate).

RSFA means the Federal Oil and Gas Royalty Simplification and Fairness Act of 1996.

Submits false, inaccurate, or misleading information means that you provide false, inaccurate, or misleading information to an ONRR data system, or otherwise to us for our official records.

Violation means any action or failure to take action that is inconsistent with the provisions of FOGRMA, RSFA, a regulation promulgated under either of those Acts, or a Federal or Indian lease as defined by FOGRMA, as amended.

You (I) means the recipient of a NONC, FCCP, or ILCP.

§ 1241.4 How will ONRR serve a Notice?

(a) We will serve a NONC, FCCP, or ILCP as set out in FOGRMA section 109(h) (30 U.S.C. 1719) by registered mail or personal service to the addressee of record or alternate, as identified in 30 CFR 1218.540.

(b) We will consider the Notice served on the date when it was delivered to the addressee of record or alternate, as identified in 30 CFR 1218.540.

§ 1241.5 Which ONRR enforcement actions are subject to a hearing?

Except as provided by § 1241.6, you may request a hearing on:

(a) A NONC to contest your liability.

(b) A FCCP to contest only the civil penalty amount, unless a request for hearing was filed under paragraph (a) of this section; in which case, the requests for hearing filed under paragraph (a) and this paragraph (b) will be combined into a single proceeding.

(c) An ILCP to contest your liability, civil penalty amount, or both. If your hearing request does not state whether you are contesting your liability for the ILCP or the penalty amount, or both, you will be deemed to have requested a hearing only on the penalty amount.

(d) You may request a hearing even if you correct the violation identified in a Notice.

§ 1241.6 Which ONRR enforcement actions are not subject to a hearing?

You may not request a hearing on:

(a) Your liability under an order identified in a NONC, FCCP, or ILCP if you did not appeal in a timely manner the order under 30 CFR part 1290 or you appealed in a timely manner the order under 30 CFR part 1290 but have exhausted your appeal rights.

(b) Any correspondence that we send to you to update you on the amount of penalties accrued or outstanding under a FCCP or ILCP ONRR previously served on you.

§ 1241.7 How do I request a hearing on the record on a Notice?

You may request a hearing on the record before an ALJ on a Notice by filing a request within 30 days of the date of service of the Notice with the DCHD, at the address indicated in your Notice. The 30 day-period to request a hearing on the record will not be extended for any reason.

§ 1241.8 How will DCHD conduct the hearing on the record?

If you request a hearing on the record under § 1241.7, an ALJ will conduct the hearing under the provisions of 43 CFR 4.420 through 4.438, except when the provisions are inconsistent with the provisions of this part. We have the burden of proving, by a preponderance of the evidence, the fact of the violation and the basis for the amount of the civil penalty. Upon completion of the hearing, the ALJ will issue a decision according to the evidence presented and the applicable law.

§ 1241.9 May I appeal the ALJ's decision?

If you are adversely affected by the ALJ's decision, you may appeal that decision to the IBLA under 43 CFR part 4, subpart E.

§ 1241.10 May I seek judicial review of the IBLA decision?

You may seek judicial review of the IBLA decision under 30 U.S.C. 1719(j) in Federal District Court. You must file a suit for judicial review in Federal District Court within 90 days after the final IBLA decision.

§ 1241.11 Does my hearing request affect a penalty?

(a) If you do not correct the violation identified in a Notice, any penalty will continue to accrue, even if you request a hearing, except as provided in paragraph (b) of this section.

(b) Standards and procedures for obtaining a stay. If you request in a timely manner a hearing on a Notice, you may petition the DCHD to stay the assessment or accrual of penalties pending the hearing on the record and a decision by the ALJ under § 1241.8.

(1) You must file your petition for stay within 45 calendar days after you receive a Notice.

(2) You must file your petition for stay under 43 CFR 4.21(b), in which event:

(i) We may file a response to your petition within 30 days after service.

(ii) The 45-day requirement set out in 43 CFR 4.21(b)(4) for the ALJ to grant or deny the petition does not apply.

(3) If the ALJ determines that a stay is warranted, the ALJ will issue an order granting your petition, subject to your satisfaction of the following condition: within 10 days of your receipt of the order, you must post a bond or other surety instrument using the same standards and requirements as prescribed in 30 CFR part 1243, subpart B; or demonstrate financial solvency using the same standards and requirements as prescribed in 30 CFR part 1243, subpart C, for any specified, unpaid principal amount that is the subject of the Notice, any interest accrued on the principal, and the amount of any penalty set out in a Notice accrued up to the date of the ALJ order conditionally granting your petition.

(4)(i) If you satisfy the condition to post a bond or surety instrument or demonstrate financial solvency under paragraph (b)(3) of this section, the accrual of penalties will be stayed effective on the date of the ALJ's order conditionally granting your petition.

(ii) If you fail to satisfy the condition to post a bond or surety instrument or demonstrate financial solvency under paragraph (b)(3) of this section, penalties will continue to accrue.

(5) Notwithstanding paragraphs (b)(1), (2), (3), and (4) of this section, if the ALJ determines that your defense to a Notice is frivolous, and a civil penalty is owed, you will forfeit the benefit of the stay, and penalties will be calculated as if no stay had been granted.

§ 1241.50 What may ONRR do if I violate a statute, regulation, order, or lease term relating to a lease subject to this part?

If we determine that you have not followed any requirement of a statute, regulation, order, or a term of a lease subject to this part, we may serve you with a NONC explaining:

(a) What the violation is.

(b) How to correct the violation to avoid a civil penalty.

(c) That you have 20 days after the date on which you are served the NONC to correct the violation, unless the NONC specifies a longer period.

§ 1241.51 What if I correct the violation identified in a NONC?

If you correct all of the violations that we identified in the NONC within 20 days after the date on which you are served the NONC, or any longer period for correction that the NONC specifies, we will close the matter and will not assess a civil penalty. However, we will consider these violations as part of your history of noncompliance for future penalty assessments under § 1241.70(a)(2).

§ 1241.52 What if I do not correct the violation identified in a NONC?

(a) If you do not correct all of the violations that we identified in the NONC within 20 days after the date on which you are served the NONC, or any longer period that the NONC specifies for correction, then we may send you an FCCP.

(1) The FCCP will state the amount of the penalty that you must pay. The penalty will:

(i) Begin to run on the day on which you were served with the NONC.

(ii) Continue to accrue for each violation identified in the NONC until it is corrected.

(2) The penalty may be up to $1,562 per day for each violation identified in the NONC that you have not corrected.

(b) If you do not correct all of the violations identified in the NONC within 40 days after you are served the NONC, or within 20 days following the expiration of any period longer than 20 days that the NONC specifies for correction, then we may increase the penalty to a maximum of $15,628 per day for each violation identified in the NONC that you have not corrected. The increased penalty will:

(1) Begin to run on the 40th day after the date on which you were served the NONC, or on the 20th day after the expiration of any period longer than 20 days that the NONC specifies for correction.

(2) Continue to accrue for each violation identified in the NONC until it is corrected.

[81 FR 50316, Aug. 1, 2016, as amended at 82 FR 18860, Apr. 24, 2017; 83 FR 2909, Jan. 22, 2018; 84 FR 8418, Mar. 8, 2019; 85 FR 7223, Feb. 7, 2020; 86 FR 7810, Feb. 2, 2021; 87 FR 1673, Jan. 12, 2022; 88 FR 2522, Jan. 17, 2023; 89 FR 3886, Jan. 22, 2024; 90 FR 1879, Jan. 10, 2025]

§ 1241.60 Am I subject to a penalty without prior notice and an opportunity to correct?

(a) We may assess a penalty for a violation identified in paragraph (b) of this section without prior notice or first giving you an opportunity to correct the violation. We will inform you of a violation without a period to correct by issuing an ILCP explaining:

(1) What the violation is.

(2) The amount of the civil penalty. The civil penalty for such a violation begins running on the day it was committed.

(b) ONRR may assess a civil penalty of up to:

(1) $31,252 per day, per violation for each day that the violation continues if you:

(i) Knowingly or willfully fail to make any royalty payment by the date specified by statute, regulation, order, or a term of the lease.

(ii) Fail or refuse to permit lawful entry, inspection, or audit, including refusal to keep, maintain, or produce documents.

(2) $78,134 per day, per violation for each day that the violation continues if you knowingly or willfully prepare, maintain, or submit a false, inaccurate, or misleading report, notice, affidavit, record, data, or any other written information.

(c) We may use any information as evidence that you knowingly or willfully committed a violation, including:

(1) The act and failure to act of your employee or agent.

(2) An email indicating your concurrence with an issue.

(3) An order that you did not appeal or an order, NONC, or ILCP for which no further appeal is available.

(4) Any written or oral communication, identifying a violation which:

(i) You acknowledge as true and fail to correct.

(ii) You fail to or cannot further appeal and fail to correct.

(iii) You correct, but you subsequently commit the same violation.

[81 FR 50316, Aug. 1, 2016, as amended at 82 FR 18860, Apr. 24, 2017; 83 FR 2909, Jan. 22, 2018; 84 FR 8418, Mar. 8, 2019; 85 FR 7223, Feb. 7, 2020; 86 FR 7810, Feb. 2, 2021; 87 FR 1673, Jan. 12, 2022; 88 FR 2522, Jan. 17, 2023; 89 FR 3886, Jan. 22, 2024; 90 FR 1880, Jan. 10, 2025]

§ 1241.70 How does ONRR decide the amount of the penalty to assess?

(a) ONRR will determine the amount of the penalty to assess by considering:

(1) The severity of the violation.

(2) Your history of noncompliance.

(3) The size of your business. To determine the size of your business, we may consider the number of employees in your company, parent company or companies, and any subsidiaries and contractors.

(b) We will not consider the royalty consequence of the underlying violation when determining the amount of the civil penalty for a violation under § 1241.50 or § 1241.60(b)(1)(ii) or (b)(2).

(c) We will post the FCCP and ILCP assessment matrices and any adjustments to the matrices on our Web site.

§ 1241.71 Do I owe interest on both the penalty amount and any underlying underpayment or unpaid debt?

(a) A penalty under this part is in addition to interest that you may owe on any underlying underpayment or unpaid debt.

(b) If you do not pay the penalty amount by the due date in the bill accompanying the FCCP or ILCP, you will owe late payment interest on the penalty amount under 30 CFR 1218.54 from the date when the civil penalty payment became due under § 1241.72 until the date when you pay the civil penalty amount.

§ 1241.72 When must I pay the penalty?

(a) If you do not request a hearing on a FCCP or ILCP under this part, you must pay the penalty amount by the due date specified in the bill accompanying the FCCP or ILCP.

(b) If you request a hearing on a FCCP or ILCP under this part, the ALJ affirms the civil penalty; and

(1) You do not appeal the ALJ's decision to the IBLA under § 1241.9, you must pay the civil penalty amount determined by the ALJ within 30 days of the ALJ's decision; or

(2) You appeal the ALJ's decision to the IBLA under § 1241.9, and IBLA affirms a civil penalty; and

(i) You do not seek judicial review of the IBLA's decision under 30 U.S.C. 1719(j), you must pay the civil penalty amount that IBLA determines within 120 days of the IBLA decision; or

(ii) You seek judicial review of the IBLA decision, and a court of competent jurisdiction affirms the penalty, you must pay the penalty assessed within 30 days after the court enters a final non-appealable judgment.

§ 1241.73 May ONRR reduce my penalty once it is assessed?

ONRR's Director or his or her delegate may compromise or reduce a civil penalty assessed under this part.

§ 1241.74 How may ONRR collect my penalty?

(a) If you do not pay a civil penalty amount by the date when payment is due under § 1241.72, we may use all available means to collect the penalty, including but not limited to:

(1) Requiring the lease surety, for an amount owed by a lessee, to pay the penalty.

(2) Deducting the amount of the penalty from any sum that the United States owes you.

(3) Referring the debt to the Department of the Treasury for collection under 30 CFR part 1218, subpart J.

(4) Using the judicial process to compel your payment under 30 U.S.C. 1719(k).

(b) If ONRR uses the judicial process to compel your payment, or if you seek judicial review under 30 U.S.C. 1719(j), and the court upholds the assessment of a penalty, the court will have jurisdiction to award the penalty amount assessed plus interest from the date of the expiration of the 90-day period referred to in 30 U.S.C. 1719(j).

§ 1243.1 What is the purpose of this part?

This part applies to you if you are a lessee or recipient of an order. This part explains:

(a) How you may suspend compliance with an order that you (or your designee if you are a lessee) have appealed under 30 CFR part 290 in effect prior to May 13, 1999 and contained in the 30 CFR, parts 200 to 699, edition revised as of July 1, 1998, or under 30 CFR part 290, subpart b; and

(b) When you or another person acting on your behalf must submit a bond or other surety or demonstrate financial solvency.

§ 1243.2 What leases are subject to this part?

This part applies to all Federal mineral leases onshore and on the Outer Continental Shelf (OCS), and to all federally-administered mineral leases on Indian tribal and individual Indian mineral owners' lands.

§ 1243.3 What definitions apply to this part?

Assessment means any fee or charge levied or imposed by the Secretary or a delegated State other than:

(1) The principal amount of any royalty, minimum royalty, rental, bonus, net profit share or proceed of sale;

(2) Any interest; or

(3) Any civil or criminal penalty.

Designee means the person designated by a lessee under § 1218.52 of this title to make all or part of the royalty or other payments due on a lease on the lessee's behalf.

Lessee means any person to whom the United States, or the United States on behalf of an Indian tribe or individual Indian mineral owner, issues a lease, or any person to whom all or part of the lessee's interest or operating rights in a lease has been assigned.

ONRR bond-approving officer means the Deputy Director for Office of Natural Resources Revenue or an official to whom the Deputy Director delegates that responsibility.

ONRR-specified surety instrument means an ONRR-specified administrative appeal bond, an ONRR-specified irrevocable letter of credit, a Treasury book-entry bond or note, or a financial institution book-entry certificate of deposit.

Notice of order means the notice that ONRR or a delegated State issues to a lessee that informs the lessee that ONRR or the delegated State has issued an order to the lessee's designee.

Order means an order appealable under 30 CFR part 290 in effect prior to May 13, 1999 and contained in the 30 CFR, parts 200 to 699, edition revised as of July 1, 1998, under 30 CFR part 290 subpart B, or under 30 CFR part 1208.

Person means any individual, firm, corporation, association, partnership, consortium, or joint venture.

[64 FR 26254, May 13, 1999, as amended at 67 FR 19113, Apr. 18, 2002]

§ 1243.4 How do I suspend compliance with an order?

(a) If you timely appeal an order, and if that order or portion of that order:

(1) Requires you to make a payment, and you want to suspend compliance with that order, you must post a bond or other surety instrument or demonstrate financial solvency under this part, except as provided in paragraph (b) of this section; or

(2) Does not require you to make a payment, compliance with that order is suspended when you meet all requirements to file that appeal.

(b) You need not meet the requirements of paragraph (a) of this section if:

(1) The order is an assessment; or

(2) Another person agrees to fulfill these requirements on your behalf under § 1243.5.

§ 1243.5 May another person post a bond or other surety instrument or demonstrate financial solvency on my behalf?

Any other person, including a designee, payor, or affiliate, may post a bond or other surety instrument or demonstrate financial solvency under this part on behalf of an appellant required to post a bond or other surety instrument under § 1243.4(a)(1).

§ 1243.6 When must I or another person meet the bonding or financial solvency requirements under this part?

If you must meet the bonding or financial solvency requirements under § 1243.4(a)(1), or if another person is meeting your bonding or financial solvency requirements, then either you or the other person must post a bond or other surety instrument or demonstrate financial solvency within 60 days after you receive the order or the Notice of Order.

§ 1243.7 What must a person do when posting a bond or other surety instrument or demonstrating financial solvency on behalf of an appellant?

If you assume an appellant's responsibility to post a bond or other surety instrument or demonstrate financial solvency under § 1243.5, you:

(a) Must notify ONRR in writing at the address specified in § 1243.200(a) that you are assuming the appellant's responsibility under this part;

(b) May not assert that you are not otherwise liable for royalties or other payments under 30 U.S.C. 1712(a), or any other theory, as a defense if ONRR calls your bond or requires you to pay based on your demonstration of financial solvency; and

(c) May end your voluntarily-assumed responsibility for posting a bond or other surety instrument only after the appellant under this part either:

(1) Pays or posts a bond or other surety instrument; or

(2) Demonstrates financial solvency.

§ 1243.8 When will ONRR suspend my obligation to comply with an order?

(a) Federal leases. Subject to paragraph (d) of this section, if you appeal an order regarding the payment and reporting of royalties and other payments due from Federal mineral leases onshore or on the Outer Continental Shelf (OCS), and:

(1) If the amount under appeal is less than $10,000 or does not require payment of a specified amount, ONRR will suspend your obligation to comply with the order. ONRR will use the lease surety posted with the Bureau of Land Management for onshore leases, and Bureau of Ocean Energy Management for OCS leases, as collateral for the obligation; or

(2) If the amount under appeal is $10,000 or more, ONRR will suspend your obligation to comply with that order if you:

(i) Submit an ONRR-specified surety instrument under subpart B of this part within a time period ONRR prescribes; or

(ii) Demonstrate financial solvency under subpart C.

(b) Indian leases. Subject to paragraph (d) of this section, if you appeal an order regarding the payment and reporting of royalties and other payments due from Indian mineral leases subject to this part, and:

(1) If the amount under appeal is less than $1,000 or does not require payment, ONRR will suspend your obligation to comply with the order. ONRR will use the lease surety posted with the Bureau of Indian Affairs as collateral for the obligation; or

(2) If the amount under appeal is $1,000 or more, ONRR will suspend your obligation to comply with that order if you submit an ONRR-specified surety instrument under subpart B of this part within a time period ONRR prescribes.

(c) Nothing in this part prohibits you from paying any demanded amount or complying with any other requirement pending appeal. However, voluntarily paying any demanded amount or otherwise complying with any other requirement when suspension of an order is otherwise available under these rules does not create judicially reviewable final agency action under 5 U.S.C. 704.

(d) Regardless of the amount under appeal, ONRR may inform you that it will not suspend your obligation to comply with the order under paragraph (a) or (b) of this section because suspension would harm the interests of the United States or the Indian lessor.

§ 1243.9 Will ONRR continue to suspend my obligation to comply with an order if I seek judicial review in a Federal court?

(a) If you seek judicial review of an IBLA decision or other final action of the Department of the Interior regarding an order, ONRR will suspend your obligation to comply with that order pending judicial review if you continue to meet the requirements of this part.

(b) Notwithstanding the provisions of paragraph (a) of this section, ONRR may decide that it will not suspend your obligation to comply with an order. ONRR will notify you in writing of that decision and the reasons for it.

§ 1243.10 When will ONRR collect against a bond or other surety instrument or a person demonstrating financial solvency?

(a) This section applies to you if, for an appeal of an order under this part, you:

(1) Maintain a bond or an ONRR-specified surety instrument on your own behalf or for another person; or

(2) Have demonstrated financial solvency on your own behalf or for another person.

(b) ONRR may initiate collection against the bond or other surety instrument or the person demonstrating financial solvency:

(1) If the ONRR Director or the Deputy Commissioner of Indian Affairs decides your appeal adversely to you and you do not pay the amount due or appeal that decision to the IBLA under 43 CFR part 4, subpart E;

(2) If the IBLA, the Director of the Office of Hearings and Appeals, an Assistant Secretary, or the Secretary decides your appeal adversely to you, and you do not pay the amount due or pursue judicial review within 90 days of the decision;

(3) If a court of competent jurisdiction issues a final non-appealable decision adverse to you, and you do not pay the amount due within 30 days of the decision;

(4) If you do not increase the amount of your bond or other surety instrument as required under § 1243.101(b), or otherwise fail to maintain an adequate surety instrument in effect, and you do not pay the amount due under the order within 30 days of notice from ONRR under § 1243.101(b);

(5) If the obligation to comply with an order or decision is not suspended under § 1243.8 or § 1243.9 and you do not pay the amount required under the order or decision; or

(6) If the ONRR bond-approving officer determines that you are no longer financially solvent under § 1243.202(c), and you do not pay the order amount or post a bond or other ONRR-specified surety instrument under subpart B within 30 days of that determination.

§ 1243.11 May I appeal the ONRR bond-approving officer's determination of my surety amount or financial solvency?

Any decision on your surety amount under subpart B or your financial solvency under subpart C is final and is not subject to appeal.

§ 1243.12 May I substitute a demonstration of financial solvency for a bond posted before the effective date of this rule?

If you appealed an order before June 14, 1999 and you submitted an ONRR-specified surety instrument to suspend compliance with that order, you may replace the surety with a demonstration of financial solvency under this part at an administratively convenient time, such as when the surety instrument is due for renewal.

§ 1243.100 What standards must my ONRR-specified surety instrument meet?

(a) An ONRR-specified surety instrument must be in a form specified in ONRR instructions. ONRR will give you written information and standard forms for ONRR-specified surety instrument requirements.

(b) ONRR will use a bank-rating service to determine whether a financial institution has an acceptable rating to provide a surety instrument adequate to indemnify the lessor from loss or damage.

(1) Administrative appeal bonds must be issued by a qualified surety company which the Department of the Treasury has approved.

(2) Irrevocable letters of credit or certificates of deposit must be from a financial institution acceptable to ONRR with a minimum 1-year period of coverage subject to automatic renewal up to 5 years.

§ 1243.101 How will ONRR determine the amount of my bond or other surety instrument?

(a) The ONRR bond-approving officer may approve your surety if he or she determines that the amount is adequate to guarantee payment. The amount of your surety may vary depending on the form of the surety and how long the surety is effective.

(1) The amount of the ONRR-specified surety instrument must include the principal amount owed under the order plus any accrued interest we determine is owed plus projected interest for a 1-year period.

(2) Treasury book-entry bond or note amounts must be equal to at least 120 percent of the required surety amount.

(b) If your appeal is not decided within 1 year from the filing date, you must increase the surety amount to cover additional estimated interest for another 1-year period. You must continue to do this annually on the date your appeal was filed. We will determine the additional estimated interest and notify you of the amount so you can amend your surety instrument.

(c) You may submit a single surety instrument that covers multiple appeals. You may change the instrument to add new amounts under appeal or remove amounts that have been adjudicated in your favor or that you have paid if you:

(1) Amend the single surety instrument annually on the date you filed your first appeal; and

(2) Submit a separate surety instrument for new amounts under appeal until you amend the instrument to cover the new appeals.

§ 1243.200 How do I demonstrate financial solvency?

(a) To demonstrate financial solvency under this part, you must submit an audited consolidated balance sheet, and, if requested by the ONRR bond-approving officer, up to 3 years of tax returns to the ONRR, Debt Collection Section using:

(1) The U.S. Postal Service or private delivery at Office of Natural Resources Revenue, Office of Enforcement, P.O. Box 25165, MS 642000B, Denver, Colorado 80225-0165; or

(2) Courier or overnight delivery at Office of Natural Resources Revenue, MS 642000B, Room A322, Bldg 85, DFC, Denver, Colorado 80225-0165.

(b) You must submit an audited consolidated balance sheet annually, and, if requested, additional annual tax returns on the date ONRR first determined that you demonstrated financial solvency as long as you have active appeals, or whenever ONRR requests.

(c) If you demonstrate financial solvency in the current calendar year, you are not required to redemonstrate financial solvency for new appeals of orders during that calendar year unless you file for protection under any provision of the U.S. Bankruptcy Code (Title 11 of the United States Code), or ONRR notifies you that you must redemonstrate financial solvency.

[64 FR 26254, May 13, 1999, as amended at 76 FR 76617, Dec. 8, 2011; 87 FR 21746, Apr. 13, 2022]

§ 1243.201 How will ONRR determine if I am financially solvent?

(a) The ONRR bond-approving officer will determine your financial solvency by examining your total net worth, including, as appropriate, the net worth of your affiliated entities.

(b) If your net worth, minus the amount we would require as surety under subpart B for all orders you have appealed is greater than $300 million, you are presumptively deemed financially solvent, and we will not require you to post a bond or other surety instrument.

(c) If your net worth, minus the amount we would require as surety under subpart B for all orders you have appealed is less than $300 million, you must submit the following to the ONRR Debt Collection Section by one of the methods in § 1243.200(a):

(1) A written request asking us to consult a business-information, or credit-reporting service or program to determine your financial solvency; and

(2) A nonrefundable $50 processing fee:

(i) You must pay the processing fee to us following the requirements for making payments found in 30 CFR 1218.51. You are not required to use Electronic Funds Transfer (EFT) for these payments;

(ii) You must submit the fee with your request under paragraph (c)(1) of this section, and then annually on the date we first determined that you demonstrated financial solvency, as long as you are not able to demonstrate financial solvency under paragraph (a) of this section and you have active appeals.

(d) If you request that we consult a business-information or credit-reporting service or program under paragraph (c) of this section:

(1) We will use criteria similar to that which a potential creditor would use to lend an amount equal to the bond or other surety instrument we would require under subpart B;

(2) For us to consider you financially solvent, the business-information or credit-reporting service or program must demonstrate your degree of risk as low to moderate:

(i) If our bond-approving officer determines that the business-information or credit-reporting service or program information demonstrates your financial solvency to our satisfaction, our bond-approving officer will not require you to post a bond or other surety instrument under subpart B;

(ii) If our bond-approving officer determines that the business-information or credit-reporting service or program information does not demonstrate your financial solvency to our satisfaction, our bond-approving officer will require you to post a bond or other surety instrument under subpart B or pay the obligation.

§ 1243.202 When will ONRR monitor my financial solvency?

(a) If you are presumptively financially solvent under § 1243.201(b), ONRR will determine your net worth as described under §§ 1243.201(b) and (c) to evaluate your financial solvency at least annually on the date we first determined that you demonstrated financial solvency as long as you have active appeals and each time you appeal a new order.

(b) If you ask us to consult a business-information or credit-reporting service or program under § 1243.201(c), we will consult a service or program annually as long as you have active appeals and each time you appeal a new order.

(c) If our bond-approving officer determines that you are no longer financially solvent, you must post a bond or other ONRR-specified surety instrument under subpart B.

§ 1290.100 What is the purpose of this part?

This part tells you how to appeal Office of Natural Resources Revenue (ONRR) or delegated State orders concerning reporting to the Minerals Revenue Management (MRM) and the payment of royalties and other payments due under leases subject to this part.

[71 FR 51752, Aug. 31, 2006, as amended at 78 FR 30206, May 22, 2013]

§ 1290.101 What leases are subject to this part?

This part applies to:

(a) All Federal mineral leases onshore and on the Outer Continental Shelf (OCS); and

(b) All federally-administered mineral leases on Indian tribal and individual Indian mineral owners' lands, regardless of the statutory authority under which the lease was issued or maintained.

[64 FR 26257, May 13, 1999, as amended at 78 FR 30206, May 22, 2013]

§ 1290.102 What definitions apply to this part?

Assessment means any fee or charge levied or imposed by the Secretary or a delegated State other than:

(1) The principal amount of any royalty, minimum royalty, rental, bonus, net profit share or proceed of sale;

(2) Any interest; or

(3) Any civil or criminal penalty.

Delegated State means a State to which ONRR has delegated authority to perform royalty management functions under an agreement or agreements under regulations at 30 CFR part 1227.

Designee means the person designated by a lessee under 30 CFR 1218.52 to make all or part of the royalty or other payments due on a lease on the lessee's behalf.

IBLA means the Interior Board of Land Appeals.

Indian lessor means an Indian tribe or individual Indian mineral owner with a beneficial or restricted interest in a property that is subject to a lease issued or administered by the Secretary on behalf of the tribe or individual Indian mineral owner.

Lease means any agreement authorizing exploration for or extraction of any mineral, regardless of whether the instrument is expressly denominated as a “lease,” including any:

(1) Contract;

(2) Net profit share arrangement;

(3) Joint venture; or

(4) Agreement the Secretary approves under the Indian Mineral Development Act, 25 U.S.C. 2101 et seq.

Lessee means any person to whom the United States, or the United States on behalf of an Indian tribe or individual Indian mineral owner, issues a lease subject to this part, or any person to whom all or part of the lessee's interest or operating rights in a lease subject to this part has been assigned.

Notice of Order means the notice that ONRR or a delegated State issues to a lessee that informs the lessee that ONRR or the delegated State has issued an order to the lessee's designee.

Obligation means:

(1) A lessee's, designee's or payor's duty to:

(i) Deliver oil or gas royalty in kind; or

(ii) Make a lease-related payment, including royalty, minimum royalty, rental, bonus, net profit share, proceeds of sale, interest, penalty, civil penalty, or assessment; and

(2) The Secretary's duty to:

(i) Take oil or gas royalty-in-kind; or

(ii) Make a lease-related payment, refund, offset, or credit, including royalty, minimum royalty, rental, bonus, net profit share, proceeds of sale, or interest.

(3) The obligations identified in paragraphs (1)(i) and (2)(i) of this definition are nonmonetary obligations. The obligations identified in paragraphs (1)(ii) and (2)(ii), including the requirement to compute the amount of such obligations, are monetary obligations.

Order, for purposes of this part only, means any document issued by ONRR or a delegated State that contains mandatory or ordering language that requires the recipient to do any of the following for any lease subject to this part: Report, compute, or pay royalties or other obligations, report production, or provide other information.

(1) Order includes:

(i) An order to pay (Order to Pay) or to compute and pay (Order to Perform a Restructured Accounting); and

(ii) An ONRR or delegated State decision to deny a lessee's, designee's, or payor's written request that asserts an obligation due the lessee, designee, or payor (Denial).

(2) Order does not include:

(i) A non-binding request, information, or guidance, such as:

(A) Advice or guidance on how to report or pay, including a valuation determination, unless it contains mandatory or ordering language; and

(B) A policy determination;

(ii) A subpoena;

(iii) An order to pay that ONRR issues to a refiner or other person involved in disposition of royalty taken in kind;

(iv) A Notice of Noncompliance or a Notice of Civil Penalty issued under 30 U.S.C. 1719 and 30 CFR part 1241, or a decision of an administrative law judge or of the IBLA following a hearing on the record on a Notice of Noncompliance or Notice of Civil Penalty;

(v) A “Dear Payor,” “Dear Operator,” or “Dear Reporter” letter unless it explicitly includes the right to appeal in writing; or

(vi) Any correspondence that does not include the right to appeal in writing.

Party means ONRR, any person who files a Notice of Appeal, and any person who files a Notice of Joinder in an appeal under this part.

[64 FR 26257, May 13, 1999, as amended at 71 FR 51752, Aug. 31, 2006; 78 FR 30206, May 22, 2013; 79 FR 62050, Oct. 16, 2014]

§ 1290.103 Who may file an appeal?

(a) If you receive an order that adversely affects you or your lessee, you may appeal that order except as provided under § 1290.104.

(b) If you are a lessee and you receive a Notice of Order, and if you contest the order, you may either appeal the order or join in your designee's appeal under § 1290.106.

§ 1290.104 What may I not appeal under this part?

You may not appeal:

(a) An action that is not an order, as defined in this part; or

(b) A determination of the surety amount or financial solvency under 30 CFR part 243, parts B or C.

[64 FR 26257, May 13, 1999, as amended at 78 FR 30206, May 22, 2013]

§ 1290.105 How do I appeal an order?

(a)(1) You may appeal to the Director, Office of Natural Resources Revenue (ONRR Director), by filing a Notice of Appeal in the office of the official issuing the Order:

(i) Within 30 days from service of an Order to Pay or a Denial involving Federal or Indian mineral leases, or an Order to Perform a Restructured Accounting involving Indian mineral leases or Federal solid mineral or geothermal leases; or

(ii) Within 60 days from service of an Order to Perform a Restructured Accounting involving Federal oil and gas leases if a delegated State issued the Order to Perform a Restructured Accounting.

(2) If the ONRR Director, or other most senior career professional responsible for the ONRR royalty management program, issued the Order to Perform a Restructured Accounting for a Federal oil and gas lease, then you may appeal that order to the IBLA within 60 days under § 1290.108.

(3) For appeals to the ONRR Director under paragraph (a)(1) of this section, within the same 30-day or 60-day period, whichever is applicable, you must file in the office of the official issuing the Order to Pay, Order to Perform a Restructured Accounting, or Denial, a statement of reasons, or written arguments, or brief that includes the arguments on the facts or law that you believe justify reversal or modification of the Order to Pay, Order to Perform a Restructured Accounting, or Denial.

(4) If you are a designee, when you file your Notice of Appeal, you must concurrently serve your Notice of Appeal on the lessees for the leases in the Order to Pay, Order to Perform a Restructured Accounting, or Denial you appealed.

(b) You may not request and will not receive an extension of time for filing the Notice of Appeal.

(c) If the office of the official issuing the order does not receive the Notice of Appeal within the time provided in paragraph (a) of this section, the Notice of Appeal will be considered timely if the office of the official issuing the order receives:

(1) The Notice of Appeal not later than 10 days after the required filing date; and

(2) The officer with whom the Notice of Appeal must be filed determines that the Notice of Appeal was transmitted to the proper office before the filing deadline in paragraph (a) of this section.

(d) If the Notice of Appeal is filed after the grace period provided in paragraph (c) of this section and was not transmitted to the proper office before the filing deadline in paragraph (a) of this section, the ONRR Director will not consider the Notice of Appeal and the case will be closed.

(e) The officer with whom the Notice of Appeal is filed will send the appeal and accompanying papers to the ONRR Director.

(f) The ONRR Director will review the record and render a decision in the case.

(g) If an order involves Indian leases, the Director, Bureau of Indian Affairs will exercise the functions vested in the ONRR Director.

[64 FR 26257, May 13, 1999, as amended at 76 FR 38561, July 1, 2011; 79 FR 62051, Oct. 16, 2014]

§ 1290.106 How do lessees join a designee's appeal and how does joinder affect the appeal?

(a) If you are a lessee, and your designee files an appeal under § 1290.103, you may join in that appeal within 30 days after you receive your designee's Notice of Appeal under § 1290.105(a)(2) by filing a Notice of Joinder with the office or official that issued the order.

(b) If you join in an appeal under paragraph (a) of this section, you are deemed to appeal the order jointly with the designee, but the designee must fulfill all requirements imposed on appellants under this part and 43 CFR part 4, subparts E and J. You may not file submissions or pleadings separately from the designee.

(c) If you are a lessee and you neither appeal nor join in your designee's appeal under this section, your designee's actions with respect to the appeal and any decisions in the appeal bind you.

(d) If you are a designee and you decide to discontinue participation in the appeal, you must serve written notice within 30 days before the next submission or pleading is due on:

(1) All lessees who have joined in the appeal under paragraph (a) of this section;

(2) The office or officer with whom any subsequent submissions or pleadings must be filed, including the IBLA; and

(3) All other parties to the appeal.

(e) If you have joined in the appeal under paragraph (a) of this section, and if the designee notifies you under paragraph (d) of this section that it declines to further pursue the appeal, you become an appellant and must then meet all requirements of this part and 43 CFR part 4, subparts E and J, as the appellant.

[64 FR 26257, May 13, 1999, as amended at 78 FR 30206, May 22, 2013]

§ 1290.107 Where are the rules concerning the effect of the Department not issuing a decision in my appeal within the statutory time frame?

If your appeal involves monetary or nonmonetary obligations under Federal oil and gas leases, the rules concerning the effect of the Department not issuing a final decision in your appeal within the 33-month period prescribed under 30 U.S.C. 1724(h) are located in 43 CFR part 4, subpart J.

§ 1290.108 How do I appeal to the IBLA?

(a) Any party to a case adversely affected by an order the ONRR Director issues or a decision the ONRR Director or Director, Bureau of Indian Affairs issues under this part shall have a right of appeal to the IBLA under the procedures provided in 43 CFR part 4, subpart E.

(b) Notwithstanding 43 CFR 4.414(a), a party shall file an answer or appropriate motion within 60 days after service of the statement of reasons for appeal unless an extension of time is requested and granted.

[79 FR 62051, Oct. 16, 2014]

§ 1290.109 How do I request an extension of time?

(a) If you are a party to an appeal under this part, and you need additional time after the appeal commences under 43 CFR 4.904 for any purpose:

(1) You may obtain an extension of time under this section; and

(2) You must submit a written request for an extension of time to:

(i) The office or official with whom you must file a document before the required filing date; or

(ii) If you are not seeking an extension of time to file a document, to the office or official before whom the appeal is pending.

(b) If you are an appellant, and if your appeal involves monetary or nonmonetary obligations under Federal oil and gas leases, you must agree in writing in your request to extend the period in which the Department must issue a final decision in your appeal under 30 U.S.C. 1724(h) and 43 CFR 4.906, by the amount of time for which you are requesting an extension.

(c) If you are any other party to an appeal involving monetary or nonmonetary obligations under Federal oil and gas leases, the office or official with whom you must file the request may require you to submit a written agreement signed by the appellant to extend the period in which the Department must issue a final decision in the appeal under 43 CFR 4.906, by the amount of time for which you are requesting an extension.

(d) The office or official with whom you must file your request may decline any request for an extension of time.

(e) You must serve your request on all parties to the appeal.

[64 FR 26257, May 13, 1999, as amended at 78 FR 30206, May 22, 2013]

§ 1290.110 How do I exhaust administrative remedies?

(a) To exhaust administrative remedies, you must appeal an Office of Natural Resources Revenue (ONRR) or delegated State order:

(1) To the ONRR Director (or the Director, Bureau of Indian Affairs when Indian lands are involved); and

(2) Subsequently to the Interior Board of Land Appeals under 30 CFR part 1290, and 43 CFR part 4.

(b) This section does not apply if an order was made effective by:

(1) The Assistant Secretary for Policy, Management and Budget;

(2) The Assistant Secretary for Indian Affairs; or

(3) The Interior Board of Land Appeals under 43 CFR part 4.

(4) The Interior Board of Land Appeals under 43 CFR part 4.

[64 FR 50753, Sept. 20, 1999, as amended at 76 FR 38561, July 1, 2011; 79 FR 62051, Oct. 16, 2014]

§ 1290.111 What happens if I do not pay or appeal an order?

If you neither pay nor appeal an order under this part, that order is the final decision of the Department, you have failed to exhaust administrative remedies as required under § 1290.110(a), and you may not contest the validity or merits of that order in any subsequent proceeding to enforce that order under 30 U.S.C. 1719 and part 1241 of this chapter.

[79 FR 62051, Oct. 16, 2014]