Consolidated Federal Oil and Gas and Federal and Indian Coal Valuation Reform
Federal RegisterOct 1, 2020
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DEPARTMENT OF THE INTERIOR
Office of Natural Resources Revenue
30 CFR Parts 1202 and 1206
[Docket No. ONRR-2012-0004; DS63644000 DRT000000.CH7000 201D1113RT]
RIN 1012-AA26
Consolidated Federal Oil and Gas and Federal and Indian Coal Valuation Reform
AGENCY:
Office of Natural Resources Revenue (ONRR), Interior.
ACTION:
Final rule.
SUMMARY:
ONRR is re-issuing certain regulations associated with the valuation of Federal oil and gas and Federal and Indian coal to implement a March 29, 2019 Court order that vacated ONRR's 2017 repeal of those regulations. These republished regulations implement the court's order by recodifying the regulations that were in effect prior to the vacated rulemaking.
DATES:
This rule is effective on September 7, 2017 because a Court vacated the rule that became effective on that date (82 FR 36934). The vacated rule repealed the original publication of this rule (81 FR 43338). The attempted postponement of the effectiveness of the original publication (82 FR 11823) was also vacated by Court order. The combined effect of the original publication, vacated postponement, and vacated repeal rule is that industry must comply with these regulations for production occurring from and after January 1, 2017.
FOR FURTHER INFORMATION CONTACT:
For questions on technical issues, contact Ms. Amy Lunt at (303) 231-3746, or Mr. Dane Templin at (303) 231-3125.
SUPPLEMENTARY INFORMATION:
I. Executive Summary
ONRR published the Consolidated Federal Oil & Gas and Federal & Indian Coal Valuation Reform Rule (“2016 Valuation Rule”) on July 1, 2016 (81 FR 43338), with an effective date of January 1, 2017. However, Federal and Indian Lessees were not required to report and pay royalties under the 2016 Valuation Rule until February 28, 2017. On February 27, 2017, after the 2016 Valuation Rule had been codified in the CFR, ONRR attempted to postpone the effectiveness of the 2016 Valuation Rule pursuant to 5 U.S.C. 705 of the Administrative Procedure Act with the publication of the Postponement of Effectiveness of the Consolidated Federal Oil & Gas and Federal & Indian Coal Valuation Reform Rule (“2017 Postponement Rule;” published at 82 FR 11823). Litigation challenging the 2017 Postponement Rule was filed and, on August 30, 2017, a Federal judge ruled ONRR's attempted postponement violated the Administrative Procedures Act.
Becerra, et al.
v.
U.S. Dep't of the Interior, et al.,
276 F.Supp3d 953 (N.D. Cali. 2017).
On August 7, 2017, ONRR repealed the 2016 Valuation Rule by publishing the Repeal of the Consolidated Federal Oil & Gas and Federal & Indian Coal Valuation Reform Rule (“2017 Repeal Rule”) (81 FR 36934). The States of California and New Mexico filed litigation to challenge the 2017 Repeal Rule. On March 29, 2019, the United States District Court for the Northern District of California issued a decision vacating the 2017 Repeal Rule.
See California, et al.,
v.
U.S. Dep't. of the Int., et al.,
381 F.Supp.3d 1153 (N.D. Ca. 2019). The Court's vacatur of the 2017 Postponement Rule and the 2017 Repeal Rule “reinstat[ed] the [2016] Valuation Rule.”
State of California, et al.
v.
U.S. Dep't of the Interior, et al.,
Case No.: C 17-5948 SBA, Order dated July 30, 2020, pp. 1, 6. Thus, compliance is required with the requirements of the 2016 Valuation Rule from and after its original effective date, January 1, 2017. ONRR is reissuing the 2016 Valuation Rule to recodify the 2016 Valuation Rule in the Code of Federal Regulations (CFR).
Following the reinstatement of the 2016 Valuation Rule, industry filed litigation to challenge the 2016 Valuation Rule. That litigation is currently pending in the United States District Court for the District of Wyoming. On October 8, 2019, the Court entered an order granting in part and denying in part industry's request for a preliminary injunction. The Court refused to enjoin the portions of the 2016 Valuation Rule applicable to Federal oil and gas but enjoined the portions of the 2016 Valuation Rule applicable to Federal and Indian coal.
Cloud Peak Energy Inc., et al.,
v.
U.S. Dep't. of the Int., et al.,
415 F.Supp.3d 1034 (D. Wyo. 2019). Thus, as of the date of this
Federal Register
notice, the portions of 2016 Valuation Rule applicable to coal produced from Federal and Indian leases are enjoined.
Id.
at 1053. For Federal and Indian coal valuation only, you should continue to refer to the 2015 annual edition of 30 CFR 1206 subparts F (Federal coal) and J (Indian coal).
II. Procedural Matters
Because it is undisputed that the 2016 Valuation Rule was reinstated by operation of law, ONRR finds good cause to issue this final rule without notice and opportunity for public comment under 5 U.S.C. 553(b)(3)(B). Additionally, a 30-day period is not required between publication of a final rule and its effective date under 5 U.S.C. 553(d). As mentioned above, the Court's Order reinstated the 2016 Valuation Rule, effective January 1, 2017.
1. Derivation Table
The following derivation table lists the sections of the respective subparts to be changed:
Derivation Table for Part 1206
The requirements of section:
Are derived from section:
Subpart C—Federal Oil
1206.20
1206.101; 1206.151; 1206.251; 1206.451.
1206.101
1206.102.
1206.102
1206.103.
1206.103
1206.104.
1206.106
1206.105.
1206.107
1206.106.
1206.108
1206.107.
1206.109
1206.108.
1206.110
1206.109.
1206.111
1206.110.
1206.112
1206.111.
1206.113
1206.112.
1206.114
1206.113.
1206.115
1206.114.
1206.116
1206.115.
1206.117
1206.116.
1206.118
1206.117.
Subpart D—Federal Gas
1206.140
1206.150.
1206.141(a)(1)-(3)
1206.152(a)(1).
1206.141(b)(1)-(3)
1206.152(a)(2).
1206.141(b)(4)
1206.152(b)(1)(iv).
1206.142(a)(4)
1206.153(a)(1).
1206.142(b)
1206.153(a)(2).
1206.142(c)
1206.153(b)(1)(i).
1206.143(a)(1) and (b)
1206.152(b)(1)(ii); 1206.153(b)(1)(ii).
1206.143(a)(2)
1206.152(f); 1206.153(f).
1206.143(c)
1206.152(b)(1)(iii);1206.153(b)(1)(iii).
1206.144
1206.152(c)(1)-(3); 1206.153(c)(1)-(3).
1206.145
1206.152(e)(1) and (2); 1206.153(e)(1) and (2); 1206.157(c)(1)(ii) and (c)(2)(iii); 1206.159(c)(1)(ii) and (c)(2)(iii).
1206.146
1206.152(i); 1206.153(i).
1206.147
1206.152(k); 1206.153(k).
1206.148
1206.152(g); 1206.153(g).
1206.149
1206.152(l); 1206.153(l).
1206.150
1206.154.
1206.151
1206.155.
1206.152(a)
1206.156(a).
1206.152(b)
1206.156(b); 1206.157(a)(2) and (b)(3).
1206.152(c)(1)
1206.157(a)(2) and (b)(4).
1206.152(f)
1206.157(a)(4).
1206.153(b)
1206.157(f).
1206.153(c)
1206.157(g).
1206.154(a)
1206.157(b).
1206.154(e)-(h)
1206.157(b)(2)(i)-(iii).
1206.154(i)
1206.157(b)(2)(iv).
1206.154(i)(3)
1206.157(b)(2)(v).
1206.155
1206.157(c)(1)(i)-(ii).
1206.156
1206.157(c)(2)(i)-(iv).
1206.157(a)(1) and (c)
1206.156(d).
1206.157(a)(2) and 1206.158
1206.157(e).
1206.159(a)(1)
1206.158(a).
1206.159(b)
1206.158(b).
1206.159(c)(1) and (2)
1206.158(c)(1) and (2).
1206.159(d)
1206.158(d)(1).
1206.160
1206.159(a).
1206.161
1206.159(b).
1206.162
1206.159(c)(1).
1206.163
1206.159(c)(2).
1206.164
1206.159(d).
1206.165
1206.159(e).
Subpart F—Federal Coal
1206.250
1206.250.
1206.251
1206.254; 1206.255; 1206.260.
1206.252(d)
1206.258(a); 1206.261(b).
1206.260(a)(1) and (b)
1206.261(a).
1206.260(c)(2)
1206.261(a)(2).
1206.260(d)
1206.261(c)(3).
1206.260(e)
1206.261(c)(1), (c)(2), and (e).
1206.260(f)
1206.262(a)(4).
1206.260(g)
1206.262(a)(2) and (a)(3).
1206.261
1206.262(a)(1).
1206.262
1206.262(b).
1206.263
1206.262(c)(1).
1206.264
1206.262(c)(2).
1206.265
1206.262(d).
1206.266
1206.262(e).
1206.267(a)
1206.258(a).
1206.267(b)(2)
1206.258(c); 1206.260.
1206.267(c)
1206.259(a)(4).
1206.267(d)
1206.259(a)(2) and (a)(3).
1206.267(e)
1206.258(e).
1206.268
1206.259(a)(1).
1206.269
1206.259(b).
1206.270
1206.259(c)(1).
1206.271
1206.259(c)(2).
1206.272
1206.259(d).
1206.273
1206.259(e).
Subpart J—Indian Coal
1206.450
1206.450.
1206.451
1206.453; 1206.454; 1206.459.
1206.460
1206.461(a)(1).
1206.463
1206.461(c).
2. Regulatory Planning and Review (Executive Orders 12866 and 13563)
Executive Order (E.O.) 12866 provides that the Office of Information and Regulatory Affairs (OIRA) of the Office of Management and Budget (OMB) will review all significant rulemakings. While the 2016 Valuation Rule was considered significant when originally published, its republication here is not significant. The republication restates existing law, and does not change the law in any way.
Executive Order 13563 reaffirms the principles of E.O. 12866, while calling for improvements in the nation's regulatory system to promote predictability, to reduce uncertainty, and to use the best, most innovative, and least burdensome tools for achieving regulatory ends. This rule is consistent with the requirements of E.O. 13563 because it restates the law without change, as required by court order.
3. Regulatory Flexibility Act
The Department certified that the 2016 Valuation Rule did not have a significant economic effect on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
et seq.
). Thus, a Regulatory Flexibility Analysis was not required, and, accordingly, a Small Entity Compliance Guide was not required. Similarly, the Regulatory Flexibility Analysis and Small Entity Compliance Guide are not required to republish the 2016 Valuation Rule.
Your comments are important. The Small Business and Agriculture Regulatory Enforcement Ombudsman and ten Regional Fairness Boards receive comments from small businesses about Federal agency enforcement actions. The Ombudsman annually evaluates the enforcement activities and rates each agency's responsiveness to small business. If you wish to comment on ONRR's actions, call 1 (888) 734-3247. You may comment to the Small Business Administration without fear of retaliation. Allegations of discrimination/retaliation filed with the Small Business Administration will be investigated for appropriate action.
4. Small Business Regulatory Enforcement Fairness Act
The 2016 Valuation Rule was not a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act. The rule:
a. Did not have an annual effect on the economy of $100 million or more.
b. Did not cause a major increase in costs or prices for consumers; individual industries; Federal, State, or local government agencies; or geographic regions.
c. Did not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of U.S.-based enterprises to compete with foreign-based enterprises. ONRR is the only agency that promulgates rules for royalty valuation on Federal oil and gas leases and Federal and Indian coal leases.
This republication of the 2016 Valuation Rule is not a major rule because it simply republishes the law, as determined by court order.
5. Unfunded Mandates Reform Act
The 2016 Valuation Rule did not impose an unfunded mandate on State, local, or Tribal governments or the private sector of more than $100 million per year. The 2016 Valuation Rule did not have a significant or unique effect on State, local, or Tribal governments or the private sector. ONRR was not required to provide a statement containing the information that the Unfunded Mandates Reform Act (2 U.S.C. 1501
et seq.
) requires because the 2016 Valuation Rule was not an unfunded mandate. Similarly, this republication of the 2016 Valuation Rule is not an unfunded mandate.
6. Takings (E.O. 12630)
Under the criteria in section 2 of E.O. 12630, the 2016 Valuation Rule did not have any significant takings implications. The rule did not impose conditions or limitations on the use of any private property. The rule applied to Federal oil, Federal gas, Federal coal, and Indian coal leases only. Therefore, the rule did not require a Takings Implication Assessment, and this republication of the 2016 Valuation Rule does not either.
7. Federalism (E.O. 13132)
Under the criteria in section 1 of E.O. 13132, the 2016 Valuation Rule did not have sufficient Federalism implications to warrant the preparation of a Federalism summary impact statement. The management of Federal oil leases, Federal gas leases, and Federal and Indian coal leases is the responsibility of the Secretary of the Interior, and ONRR distributes all of the royalties that it collects from the leases to States, Tribes, and individual Indian mineral owners. The rule did not impose administrative costs on States or local governments. The rule also did not substantially and directly affect the relationship between the Federal and State governments. Similarly, the republication of the 2016 Valuation Rule does not require a Federalism summary impact statement either.
8. Civil Justice Reform (E.O. 12988)
The 2016 Valuation Rule, as well as the republication, comply with the
requirements of E.O. 12988. Specifically, the republished rule:
a. Meets the criteria of section 3(a), which requires that ONRR review all regulations to eliminate errors and ambiguity and write them to minimize litigation.
b. Meets the criteria of section 3(b)(2), which requires that ONRR write all regulations in clear language using clear legal standards.
9. Consultation With Indian Tribal Governments (E.O. 13175)
Under the criteria in E.O. 13175, ONRR evaluated the 2016 Valuation Rule, and determined that it potentially affected Federally-recognized Indian Tribes. Specifically, the rule changed the valuation method for coal produced from Indian leases. Accordingly:
a. ONRR held a public workshop on October 20, 2011, in Albuquerque, New Mexico, to consider Tribal comments on the Indian coal valuation regulations.
b. ONRR solicited comments from all Tribes and received comments from a Tribe through an Advance Notice of Proposed Rulemaking published on May 27, 2011 (76 FR 30881).
c. ONRR requested further comments from its Tribal partners through our bi-annual State and Tribal Royalty Audit Committee meetings held in May and November 2015.
d. ONRR considered Tribal views in the 2016 Valuation Rule.
See
82 FR 36952.
Because this rule republishes the 2016 Valuation Rule without change, ONRR did not solicit Tribal comments on the republication.
10. Paperwork Reduction Act
The 2016 Valuation Rule:
a. Did not contain any new information collection requirements.
b. Did not require a submission to OMB under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
et seq.
).
The rule also referred to, but did not change, the information collection requirements that OMB already approved under OMB Control Numbers 1012-0004, 1012-0005, and 1012-0010. Similarly, this republication of the 2016 Valuation Rule does not contain any new information collection requirements or submissions to OMB. Since the rule reorganized ONRR's regulations, please refer to the Derivations Table in Section II for specifics. The corresponding information collection burden tables will be updated during the normal renewal cycle.
See
5 CFR 1320.4(a)(2).
11. National Environmental Policy Act
The 2016 Valuation Rule did not constitute a major Federal action significantly affecting the quality of the human environment. ONRR was not required to provide a detailed statement under the National Environmental Policy Act of 1969 (NEPA) because the rule qualified for a categorical exclusion under 43 CFR 46.210(c) and (i) and the DOI Departmental Manual, part 516, section 15.4.D: “
(c) Routine financial transactions including such things as . . . audits, fees, bonds, and royalties . . . (i) Policies, directives, regulations, and guidelines: That are of an administrative, financial, legal, technical, or procedural nature.”
ONRR also determined that the rule was not involved in any of the extraordinary circumstances listed in 43 CFR 46.215 that require further analysis under NEPA. The procedural changes resulting from the amendments had no consequence on the physical environment. The rule did not alter, in any material way, natural resources exploration, production, or transportation. Likewise, this republication of the 2016 Valuation Rule does not alter, in any material way, natural resources exploration, production, or transportation because it republishes the law, as determined by court order.
12. Effects on the Nation's Energy Supply (E.O. 13211)
The 2016 Valuation Rule was not a significant energy action under the definition in E.O. 13211. Nor is this republication of the 2016 Valuation Rule a significant energy action under the definition in E.O. 13211. Thus, a Statement of Energy Effects is not required.
List of Subjects in 30 CFR Parts 1202 and 1206
Coal, Continental shelf, Government contracts, Indian lands, Mineral royalties, Natural gas, Oil, Oil and gas exploration, Public lands—mineral resources, Reporting and recordkeeping requirements.
Kimbra G. Davis,
Director for Office of Natural Resources Revenue.
Authority and Issuance
For the reasons discussed in the preamble, ONRR amends 30 CFR parts 1202 and 1206 as set forth below:
PART 1202—ROYALTIES
1. The authority citation for part 1202 continues to read as follows:
Authority:
5 U.S.C. 301
et seq.,
25 U.S.C. 396
et seq.,
396a
et seq.,
2101
et seq.;
30 U.S.C. 181
et seq.,
351
et seq.,
1001
et seq.,
1701
et seq.;
31 U.S.C. 9701; 43 U.S.C. 1301
et seq.,
1331
et seq.,
and 1801
et seq.
Subpart B—Oil, Gas, and OCS Sulfur, General
2. In § 1202.51, revise paragraph (b) to read as follows:
§ 1202.51
Scope and definitions.
(b) The definitions in § 1206.20 of this chapter are applicable to subparts B, C, D, and J of this part.
Subpart F—Coal
3. Add § 1202.251 to subpart F to read as follows:
§ 1202.251
What coal is subject to royalties?
(a) All coal (except coal unavoidably lost as BLM determines under 43 CFR part 3400) from a Federal or Indian lease is subject to royalty. This includes coal used, sold, or otherwise disposed of by you on or off of the lease.
(b) If you receive compensation for unavoidably lost coal through insurance coverage or other arrangements, you must pay royalties at the rate specified in the lease on the amount of compensation that you receive for the coal. No royalty is due on insurance compensation that you received for other losses.
(c) If you rework waste piles or slurry ponds to recover coal, you must pay royalty at the rate specified in the lease at the time when you use, sell, or otherwise finally dispose of the recovered coal.
(1) The applicable royalty rate depends on the production method that you used to initially mine the coal contained in the waste pile or slurry pond (such as an underground mining method or a surface mining method).
(2) You must allocate coal in waste pits or slurry ponds that you initially mined from Federal or Indian leases to those Federal or Indian leases regardless of whether it is stored on Federal or Indian lands.
(3) You must maintain accurate records demonstrating how to allocate the coal in the waste pit or slurry pond to each individual Federal or Indian coal lease.
PART 1206—PRODUCT VALUATION
4. The authority citation for part 1206 continues to read as follows:
Authority:
5 U.S.C. 301
et seq.,
25 U.S.C. 396
et seq.,
396a
et seq.,
2101
et seq.;
30 U.S.C. 181
et seq.,
351
et seq.,
1001
et seq.,
1701
et seq.;
31 U.S.C. 9701; 43 U.S.C. 1301
et seq.,
1331
et seq.,
and 1801
et seq.
5. Revise subpart A to read as follows:
Subpart A—General Provisions and Definitions
Sec.
1206.10
Has the Office of Management and Budget (OMB) approved the information collection requirements in this part?
1206.20
What definitions apply to this part?
Subpart A—General Provisions and Definitions
§ 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?
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.
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.
Coal
means coal of all ranks from lignite through anthracite.
Coal cooperative
means an entity organized to provide coal or coal-related services to the entity's members (who may or may not also be owners of the entity), partners, and others. The entity may operate as a coal lessee, operator, payor, logistics provider, or electricity generator, or any of their affiliates, and may be organized to be non-profit or for-profit.
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).
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
mean
s
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
(3)
Coal.
Gross proceeds also include, but are not limited to, the following examples:
(i) Payments for services such as crushing, sizing, screening, storing, mixing, loading, treatment with substances including chemicals or oil, and other preparation of the coal that the lessee must perform at no cost to the Federal Government or Indian lessor
(ii) Reimbursements for royalties, fees, and any other reimbursements
(iii) Tax reimbursements even though the Federal or Indian 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:
(1) Any person who has an interest in a lease.
(2) In the case of leases for Indian coal or Federal coal, an operator, payor, or other person with no lease interest who makes royalty payments on the lessee's behalf.
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, and region for Federal and Indian coal.
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:
(1) For gas, residue gas and each gas plant product that a processing plant produces.
(2) For coal, the quantity of washed coal that a coal wash 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.
Region
for coal means the eight Federal coal production regions, which the Bureau of Land Management designates as follows: Denver-Raton Mesa Region, Fort Union Region, Green River-Hams Fork Region, Powder River Region, San Juan River Region, Southern Appalachian Region, Uinta-Southwestern Utah Region, and Western Interior Region. See 44 FR 65197 (1979).
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 × (P
0
−P
1
) + .3333 × (P
0
−P
2
), where: P
0
= 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; P
1
= 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 P
2
= 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. P
0,
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. P
1
is the average of the daily NYMEX settlement prices for deliveries during January published for each business day between October 21 and November 18. P
2
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 P
0
= $95.08 per bbl, P
1
= $95.03 per bbl, and P
2
= $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. P
0,
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. P
1
is the average of the daily NYMEX settlement prices for deliveries during December published for each business day between September 21 and October 22. P
2
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
P
0
= $91.28 per bbl, P
1
= $91.65 per bbl, and P
2
= $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, gas plant product, or coal to the buyer and does not retain any related rights, such as the right to buy back similar quantities of oil, gas, gas plant product, or coal from the buyer elsewhere; and
(2) The buyer pays money or other consideration for the oil, gas, gas plant product, or coal; and
(3) The parties' intent is for a sale of the oil, gas, gas plant product, or coal 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.
Short ton
means 2,000 pounds.
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.
Tonnage
means tons of coal measured in short tons.
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.
(3) Coal to a point of sale remote from both the lease and mine or wash plant.
Washing allowance
means a deduction in determining royalty value for the reasonable, actual costs the lessee incurs for coal washing.
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.
6. Revise subpart C to read as follows:
Subpart C—Federal Oil
1206.100
What is the purpose of this subpart?
1206.101
How do I calculate royalty value for oil I or my affiliate sell(s) under an arm's-length contract?
1206.102
How do I value oil not sold under an arm's-length contract?
1206.103
What publications does ONRR approve?
1206.104
How will ONRR determine if my royalty payments are correct?
1206.105
How will ONRR determine the value of my oil for royalty purposes?
1206.106
What records must I keep to support my calculations of value under this subpart?
1206.107
What are my responsibilities to place production into marketable condition and to market production?
1206.108
How do I request a valuation determination?
1206.109
Does ONRR protect information I provide?
1206.110
What general transportation allowance requirements apply to me?
1206.111
How do I determine a transportation allowance if I have an arm's-length transportation contract?
1206.112
How do I determine a transportation allowance if I do not have an arm's-length transportation contract?
1206.113
What adjustments and transportation allowances apply when I value oil production from my lease using NYMEX prices or ANS spot prices?
1206.114
How will ONRR identify market centers?
1206.115
What are my reporting requirements under an arm's-length transportation contract?
1206.116
What are my reporting requirements under a non-arm's-length transportation contract?
1206.117
What interest and penalties apply if I improperly report a transportation allowance?
1206.118
What reporting adjustments must I make for transportation allowances?
1206.119
How do I determine royalty quantity and quality?
Subpart C—Federal Oil
§ 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.
7. Revise subpart D to read as follows:
Subpart D—Federal Gas
1206.140
What is the purpose and scope of this subpart?
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?
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?
1206.143
How will ONRR determine if my royalty payments are correct?
1206.144
How will ONRR determine the value of my gas for royalty purposes?
1206.145
What records must I keep in order to support my calculations of royalty under this subpart?
1206.146
What are my responsibilities to place production into marketable condition and to market production?
1206.147
When is an ONRR audit, review, reconciliation, monitoring, or other like process considered final?
1206.148
How do I request a valuation determination?
1206.149
Does ONRR protect information that I provide?
1206.150
How do I determine royalty quantity and quality?
1206.151
[Reserved]
1206.152
What general transportation allowance requirements apply to me?
1206.153
How do I determine a transportation allowance if I have an arm's-length transportation contract?
1206.154
How do I determine a transportation allowance if I have a non-arm's-length transportation contract?
1206.155
What are my reporting requirements under an arm's-length transportation contract?
1206.156
What are my reporting requirements under a non-arm's-length transportation contract?
1206.157
What interest and penalties apply if I improperly report a transportation allowance?
1206.158
What reporting adjustments must I make for transportation allowances?
1206.159
What general processing allowances requirements apply to me?
1206.160
How do I determine a processing allowance if I have an arm's-length processing contract?
1206.161
How do I determine a processing allowance if I have a non-arm's-length processing contract?
1206.162
What are my reporting requirements under an arm's-length processing contract?
1206.163
What are my reporting requirements under a non-arm's-length processing contract?
1206.164
What interest and penalties apply if I improperly report a processing allowance?
1206.165
What reporting adjustments must I make for processing allowances?
Subpart D—Federal Gas
§ 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 in
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