(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]

(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]

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.

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]

(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.

(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:

(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.

(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]

(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.

(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.

(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 Cspan 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.

(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]

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.