2021-00217. ONRR 2020 Valuation Reform and Civil Penalty Rule

AGENCY:

Department of the Interior, Office of the Secretary, Office of Natural Resources Revenue.

ACTION:

Final rule.

SUMMARY:

The Office of Natural Resources Revenue (“ONRR”) is amending certain regulations on how it values oil and gas produced from Federal leases for royalty purposes, values coal produced from Federal and Indian leases for royalty purposes, and assesses civil penalties for violations of certain statutes, regulations, leases, and orders associated with mineral leases. In addition, it is making some minor, non-substantive corrections to its regulations.

DATES:

Effective date: This rule is effective February 16, 2021.

Compliance date: With respect to the amendments to 30 CFR part 1206 only, compliance is required for production that occurs on or after May 1, 2021. Compliance with the amendments to 30 CFR part 1241 is required on the effective date.

FOR FURTHER INFORMATION CONTACT:

For questions on procedural issues, contact Dane Templin, Regulations Supervisor, at [phone] or [e-mail]. For questions on technical issues related to royalty valuation, contact Amy Lunt, Supervisor Royalty Valuation Team A, at [phone] or [e-mail], or Peter Christnacht, Supervisor Royalty Valuation Team B, at [phone] or [e-mail]. For questions on technical issues related to civil penalties, contact Michael Marchetti, Program Manager Office of Enforcement, at [phone] or [e-mail].

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Introduction

A. ONRR's Rulemaking Authority

B. Rulemaking Objectives

C. Executive Discretion is a Permissible Initiative for Rulemaking

D. ONRR's Relevant Prior Rulemakings and Associated Litigation

E. Public Comment Overview

II. Amendment Discussion—Part 1206 Product Valuation

A. Index-Based Valuation Method To Value Federal Gas

B. Transportation Allowance for Certain Offshore Federal Oil and Gas Gathering Costs

C. Allowance Limits for Federal Oil and Gas

D. The Default Provision for Federal Oil, Gas, and Coal and Indian Coal

E. “Misconduct” Definition for Federal Oil, Gas, and Coal and Indian Coal

F. Contract Signature Requirement for Federal Oil, Gas, and Coal and Indian Coal

G. Citation to Legal Precedent as Part of a Valuation Determination Request

H. Coal Valued for Royalty Purposes Based on an Electricity Sale

I. “Coal Cooperative” Definition

III. Amendment Discussion—Part 1241 Penalties

A. Civil Penalties for Payment Violations

B. Consideration of Aggravating and Mitigating Circumstances When ONRR Assesses a Civil Penalty

C. Forfeiture of a Stay of the Civil Penalty Accrual Under Limited Circumstances

IV. Non-Substantive Corrections

V. Economic Analysis

VI. Severability Statement

VII. Procedural Matters

A. Regulatory Planning and Review (Executive Orders 12866 and 13563)

B. Regulatory Flexibility Act

C. Small Business Regulatory Enforcement Fairness Act

D. Unfunded Mandates Reform Act

E. Takings (Executive Order 12630)

F. Federalism (Executive Order 13132)

G. Civil Justice Reform (Executive Order 12988)

H. Consultation With Indian Tribal Governments (Executive Order 13175)

I. Paperwork Reduction Act (44 U.S.C. 3501 et seq.)

J. National Environmental Policy Act

K. Effects on the Energy Supply (Executive Order 13211)

L. Clarity of this Regulation

M. Congressional Review Act

Table of Abbreviations and Commonly Used Acronyms in This Rule

Abbreviation	What it means
2016 Valuation Rule	ONRR's Consolidated Federal Oil and Gas and Federal and Indian Coal Valuation Reform Rule, 81 FR 43338 (July 1, 2016).
2016 Civil Penalty Rule	ONRR's Amendments to Civil Penalty Regulations, 81 FR 50306 (August 1, 2016).
2017 Postponement Notice	ONRR's Notice of Postponement, 82 FR 11823 (February 27, 2017) (sought to stay implementation of the 2016 Valuation Rule).
2017 Repeal Rule	ONRR's Repeal of the 2016 Valuation Rule, 82 FR 36934 (August 7, 2017).
2020 Proposed Rule	ONRR's 2020 proposed rule titled: ONRR 2020 Valuation Reform and Civil Penalty Rule, 85 FR 62054 (October 1, 2020).
ALJ	Administrative Law Judge.
APA	Administrative Procedure Act of 1946, as amended.
API	American Petroleum Institute.
APD	Application for a Permit to Drill.
BLM	Bureau of Land Management.
BLS	Bureau of Labor Statistics.
BOEM	Bureau of Ocean Energy Management.
BSEE	Bureau of Safety and Environmental Enforcement.
Department	U.S. Department of the Interior.
Deepwater Policy	MMS's May 20, 1999, memorandum titled “Guidance for Determining Transportation Allowances for Production from Leases in Water Depths Greater Than 200 Meters”.
E.O.	Executive Order.
FCCP	Failure to Correct Civil Penalty.
FERC	Federal Energy Regulatory Commission.
FLPMA	Federal Land Policy and Management Act of 1976.
FOGRMA	Federal Oil and Gas Royalty Management Act of 1982.
FY	Fiscal Year.
GOM	Gulf of Mexico.
IBLA	Interior Board of Land Appeals.
ILCP	Immediate Liability Civil Penalty.
MLA	Mineral Leasing Act of 1920.
MMS	Minerals Management Service.
NEPA	National Environmental Policy Act of 1970.
NGL	Natural Gas Liquids.
OCS	Outer Continental Shelf.
OCSLA	Outer Continental Shelf Lands Act of 1953.
ONRR	Office of Natural Resources Revenue.
Secretary	Secretary of the U.S. Department of the Interior.
S.O.	Secretarial Order.

I. Introduction

This final rule amends ONRR's regulations under 30 CFR Chapter XII, Parts 1206 (product valuation) and 1241 (penalties). In 30 CFR part 1206, this final rule amends certain definitions (Subpart A) and provisions used to value Federal oil (Subpart C), Federal gas (Subpart D), Federal coal (Subpart F), and Indian coal (Subpart J). In 30 CFR part 1241, this final rule amends ONRR's regulations on the practices it uses to assess civil penalties (Subparts A and C).

This rule is effective 30 days after its publication in the Federal Register. However, ONRR recognizes that lessees typically report and pay royalties based on monthly production, sales, and costs. In addition, compliance with the requirements of the Rule will require system modifications by ONRR to accept reports and for industry reporters in order to submit reports. These system modifications will take some time to program. For those reasons, a separate compliance date is provided under the DATES caption to establish that—for the amendments to 30 CFR part 1206 only—lessees must conform to the amended requirements under this final rule beginning with production that occurs on and after May 1, 2021.

As stated under the DATES caption, the amendments to 30 CFR part 1241 shall become effective on and compliance is required by February 16, 2021.

ONRR explained in the 2020 Proposed Rule that, with regard to 30 CFR part 1206, several of ONRR's proposed amendments would extend, revise, or remove regulations that ONRR had adopted through the 2016 Valuation Rule. See 85 FR 62054-62062. ONRR also explained the factors it was considering in its decision making, including: (1) Executive Orders (E.O.s) and Secretarial Orders (S.O.s) issued after the 2016 Valuation Rule's effective date; (2) specific to coal cooperatives and coal valuation based on electricity sales, ONRR's consideration of the parties' briefs filed in litigation challenging the 2016 Valuation Rule and the court's decision in that litigation to stay implementation of the rule's Federal and Indian coal provisions; and (3) ONRR's continued work to consider and implement regulatory changes that simplify or better explain ONRR's processes, and to provide early clarity regarding royalties owed. See 85 FR 62054-62057.

For 30 CFR part 1241, ONRR explained in the 2020 Proposed Rule that, in addition to some of the reasons listed above, ONRR was considering changes to its civil penalty practices to conform with a (subsequently-vacated) Federal District Court's decision on an industry challenge to ONRR's 2016 Civil Penalty Rule and to conform the civil penalty regulations to certain IBLA decisions. See 85 FR 62055 and 62056.

ONRR finds that those reasons, additional reasons raised in public comments, and additional information (identified by ONRR or provided to ONRR by its sister agencies) warrant the amendments adopted in this final rule on the following topics:

1. Allowing a lessee producing Federal oil and gas from the OCS under leases in water depths of 200 meters or greater to take a deduction for certain gathering costs as part of its transportation allowance.

2. Allowing a lessee to apply to ONRR for approval to claim an extraordinary processing allowance for Federal gas in situations where the gas stream, plant design, and/or unit costs were extraordinary, unusual, or unconventional relative to standard industry conditions and practice.

3. Removing the definition of “misconduct” from 30 CFR part 1206 as it applies to Federal oil and gas, and Federal and Indian coal.

4. Removing the default provision and references thereto from the regulations applying to Federal oil and gas, and Federal and Indian coal.

5. Removing the requirement that a lessee have contracts signed by all parties in order for those contracts to be recognized valid and binding with respect to the valuation of Federal oil and gas, and Federal and Indian coal.

6. Removing the requirement for a lessee to cite legal precedent when seeking a valuation determination for Federal oil and gas or a valuation decision for Federal or Indian coal.

7. Expanding the option to use index-based valuation to arm's-length Federal gas sales, which, under the 2016 Valuation Rule, was only available for non-arm's-length Federal gas sales.

8. For unprocessed and residue gas valued using the index-based valuation method, changing from the high index price to the average index price.

9. Changing the transportation deductions allowed under an index-based valuation method to reflect more recent transportation cost data reported to ONRR.

10. Amending other regulation language to make non-substantive corrections so as to make the regulations more clear and workable.

11. Amending ONRR's Federal and Indian coal valuation regulations to remove the requirement to value certain coal based on the sale of electricity.

12. Amending ONRR's Federal and Indian coal valuation regulations to remove the definition of “coal cooperative” and the method to value sales between members of a “coal cooperative.”

13. Amending ONRR's civil penalty regulations to clarify that ONRR will consider the unpaid, underpaid, or late payment amounts in the severity analysis for payment violations only.

14. Amending ONRR's civil penalty regulations to clarify that ONRR may consider aggravating and mitigating circumstances when calculating the amount of a civil penalty.

15. Amending ONRR's civil penalty regulations to remove an ALJ's ability to vacate the benefit of a stay of an accrual of penalties if the ALJ later determines that a violator's defense to a notice of noncompliance was frivolous.

This rule does not adopt three amendments that ONRR proposed in the 2020 Proposed Rule. This rule does not:

1. Remove or otherwise amend the regulatory cap on transportation allowances for Federal oil and gas.

2. Remove or otherwise amend the regulatory cap on processing allowances for Federal gas.

3. Allow a lessee producing oil or gas on the OCS in waters shallower than 200 meters to file an application seeking ONRR's permission to include certain gathering costs in its transportation allowance.

A. ONRR's Rulemaking Authority

ONRR's royalty program is “a complex and highly technical regulatory program, in which the identification and classification of relevant criteria necessarily require significant expertise and entail the exercise of judgment grounded in policy concerns.” Amoco Prod. Co. v. Watson, 410 F.3d 722, 729 (D.C. Cir. 2005) (internal quotations and citation omitted). FOGRMA grants the Secretary authority to “prescribe such rules and regulations as he deems reasonably necessary to carry out this chapter.” See 30 U.S.C. 1751(a); see also, e.g., 30 U.S.C. 1719. Re-evaluating the best means of balancing these statutory priorities within the bounds of the specific commands of the statute, as called for in the Executive and Secretarial Orders, is well within the scope of authority that Congress granted to the Secretary under FOGRMA and which was delegated by the Secretary to ONRR.

B. Rulemaking Objectives

The E.O.s explained below do not prescribe an outcome, rather, they note policy positions that are well within the specific authorities outlined in the relevant statutes, namely the MLA and the OCSLA. Specifically, 43 U.S.C. 1332(3) states that: “It is hereby declared to be the policy of the United States that . . . the [OCS] is a vital national resource reserve held by the Federal Government for the public, which should be made available for expeditious and orderly development, subject to environmental safeguards, in a manner which is consistent with the maintenance of competition and other national needs. . . .” Moreover, the MLA, at 30 U.S.C. 201, states that “[t]he Secretary of the Interior is authorized to divide any lands subject to this chapter which have been classified for coal leasing into leasing tracts of such size as he finds appropriate and in the public interest and which will permit the mining of all coal which can be economically extracted in such tract and thereafter he shall, in his discretion, upon the request of any qualified applicant or on his own motion, from time to time, offer such lands for leasing and shall award leases thereon by competitive bidding.” With respect to oil and gas, the MLA, at 30 U.S.C. 226, states that “[a]ll lands subject to disposition under this chapter which are known or believed to contain oil or gas deposits may be leased by the Secretary” and provides that “[l]ease sales shall be held for each State where eligible lands are available at least quarterly and more frequently if the Secretary of the Interior determines such sales are necessary.”

While neither of these statutes define or employ the term “fair return,” both the OCSLA and the MLA make use of the term “fair market value.” OCSLA, at 43 U.S.C. 1331(o), defines “fair market value” as “the value of any mineral (1) computed at a unit price equivalent to the average unit price at which such mineral was sold pursuant to a lease during the period for which any royalty or net profit share is accrued or reserved to the United States pursuant to such lease, or (2) if there were no such sales, or if the Secretary finds that there were an insufficient number of such sales to equitably determine such value, computed at the average unit price at which such mineral was sold pursuant to other leases in the same region of the [OCS] during such period, or (3) if there were no sales of such mineral from such region during such period, or if the Secretary finds that there are an insufficient number of such sales to equitably determine such value, at an appropriate price determined by the Secretary[.]” FOGRMA built upon the royalty provisions of the MLA and the OCSLA by stating that the Secretary shall: “establish a comprehensive inspection, collection and fiscal and production accounting and, auditing system to provide the capability to accurately determine oil and gas royalties, interest, fines, penalties, fees, deposits, and other payments owed and to collect and account for such amounts in a timely manner.” 30 U.S.C. 1711(a).

Both of the statutes provide for minimum royalty rates when leasing areas for energy and mineral development and offer some direction on royalty collection. The mineral leasing authorities granted to the Secretary by Congress provide broad authorities to “prescribe necessary and proper rules and regulations and to do any and all things necessary to carry out and accomplish the purposes of [the leasing statutes]” including the collection of all revenues associated with such activities (bonus bids, royalties, rentals and other fees). See 25 U.S.C. 396, 396d (tribal lands); 30 U.S.C. 189 (public lands); 30 U.S.C. 1751 (FOGRMA); 43 U.S.C. 1334(a) (OCS lands).

In addition to these policy goals, ONRR's objectives include implementing court decisions and analyses, making changes that reduce regulatory burdens while maintaining royalty value and ONRR's ability to provide oversight, and making regulations more simple, clear, and workable. Further, ONRR explains additional reasons to adopt or not adopt the specific proposed amendments in the amendment discussion sections that follow.

The 2020 Proposed Rule, at 85 FR 62054 and 62056-62057, explained that ONRR's objective for this rulemaking included furtherance of the policy goals described in:

1. E.O. 13783, “Promoting Energy Independence and Economic Growth.”

In E.O. 13783, the President emphasized that “[i]t is in the national interest to promote clean and safe development of our Nation's vast energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production, constrain economic growth, and prevent job creation.” The President further directed executive departments and agencies to immediately review existing regulations that potentially burden the development or use of domestically produced energy resources and appropriately suspend, revise, or rescind those that unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest or otherwise comply with the law. Pursuant to E.O. 13783, agency heads are required to review all existing regulations that potentially burden the development or use of domestically produced energy resources, “with particular attention to oil, natural gas, coal, and nuclear energy resources.” E.O. 13783 further explained that “burden” means to unnecessarily obstruct, delay, curtail, or otherwise impose significant costs on the siting, permitting, production, utilization, transmission, or delivery of energy resources.

2. E.O. 13795, “Implementing an America-First Offshore Energy Strategy.”

Through E.O. 13795, the President stated his policy goal of emphasizing “the energy needs of American families and businesses first” and to “continue implementing a plan that ensures energy security and economic vitality for decades to come.” E.O. 13795 stated that “[i]ncreased domestic energy production on Federal lands and waters strengthens the Nation's security and reduces reliance on imported energy” and “help[s] reinvigorate American manufacturing and job growth.” Accordingly, E.O. 13795 stated that “[i]t shall be the policy of the United States to encourage energy exploration and production, including on the [OCS], in order to maintain the Nation's position as a global energy leader and foster energy security and resilience for the benefit of the American people. . . .”

3. E.O. 13892, “Promoting the Rule of Law Through Transparency and Fairness in Civil Administrative Enforcement and Adjudication.”

Through E.O. 13892, the President stated his policy goal of emphasizing that “[a]gencies shall act transparently and fairly with respect to all affected parties, as outlined in this order, when engaged in civil administrative enforcement or adjudication.” E.O. 13892 stated that “the Federal Government should, where feasible, foster greater private-sector cooperation in enforcement, promote information sharing with the private sector, and establish predictable outcomes for private conduct. . . .” With emphasis on fairness and transparency, E.O. 13892 also reinforced that “regulated parties must know in advance the rules by which the Federal Government will judge their actions,” and required that agencies provide “prior public notice” of any legal standards the agency will be applying.

4. S.O.s 3306, 3350, and 3360.

Three Secretarial Orders are also relevant to this rulemaking. S.O. 3306, Organizational Changes Under the Assistant Secretary—Policy, Management and Budget, signed on September 30, 2010, created ONRR and reorganized this office under the Assistant Secretary for Policy, Management and Budget to: “discharge the duties of the Secretary for management of revenues from Federal and Indian onshore and offshore mineral and energy resource leases . . . to assure full and timely collection, distribution, and disbursement of bonuses, rentals, royalties, and other revenues and coordination of related Departmental policy.”

Through S.O. 3350, America-First Offshore Energy Strategy, the Secretary of the Interior (“Secretary”) took specific steps to implement E.O. 13795. Significant to the proposed rule, the Secretary specifically stated that S.O. 3350 is designed to implement the President's directives as set forth in E.O. 13795 to “ensure that responsible OCS exploration and development is promoted and not unnecessarily delayed or inhibited.” The Order directed BOEM and BSEE to take specific actions, but also more generally expressed a desire for active coordination of energy policy in order to enhance opportunities for energy exploration, leasing, and development on the OCS. S.O. 3360 is likewise directed at continuing to implement E.O. 13783 and the directive to the Department to review existing regulations that “potentially burden the development or utilization of domestically produced energy resources.”

These statutes, Executive Orders and Secretarial Orders make clear that it is in the national interest to promote domestic energy development for a variety of reasons, including stimulating the economy, job creation, and national security. They also emphasize the importance of reducing regulatory burdens so that energy producers, and particularly oil, natural gas, and coal producers, are incentivized to produce more energy. Through this rulemaking, ONRR furthers these policy objectives by several means, including providing mechanisms that simplify reporting and compliance, and promoting domestic energy production.

C. Executive Discretion is a Permissible Initiative for Rulemaking

As described in greater detail in the discussion of each amendment that follows, this rule is, in part, founded upon new factual findings that, in some instances, contradict those upon which the 2016 Valuation Rule was based. In some instances, the operative facts have changed since 2016. In other instances, ONRR has reconsidered the weighing of different policy priorities and values as they apply to the relevant facts. See generally F.C.C. v. Fox Television Stations, Inc., 556 U.S. 502, 514 (2009); Nat'l Ass'n of Home Builders v. EPA, 682 F.3d 1032, 1038, 1043 (D.C. Cir. 2012); Dana Corp. v. ICC, 703 F.2d 1297, 1305 (D.C. Cir. 1983). With respect to the latter category and as explained further herein, ONRR is implementing this rule, in part, because policy directives issued after July 1, 2016, give different weight to the factual findings, and also set other policy-based priorities. Agency action representing a policy change “is not subject to a more searching review.” F.C.C. v. Fox Television Stations, Inc., 556 U.S. 502, 514 (2009).

Indeed, “regulatory agencies do not establish rules of conduct to last forever.” Am. Trucking Assoc., Inc. v. Atchison, T. & S.F.R. Co., 387 U.S. 397, 416 (1967). An agency must be given ample latitude to “adapt their rules and policies to the demands of changing circumstances.” Permian Basin Area Rate Cases, 390 U.S. 747, 784 (1968). A revised rulemaking based on “a reevaluation of which policy would be better in light of the facts” is “well within an agency's discretion.” Nat'l Ass'n of Home Builders v. EPA, 682 F.3d 1032, 1038 (D.C. Cir. 2012) (citing F.C.C. v. Fox Television Stations, Inc., 556 U.S. 502, 514-15 (2009)). Further, “[a] change in administration brought about by the people casting their votes is a perfectly reasonable basis for an executive agency's reappraisal of the costs and benefits of its programs and regulations.” Id. at 1043 (quoting Motor Vehicle Mfrs. Ass'n of the U.S., Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 59 (1983) (Rehnquist, J., concurring in part and dissenting in part)). An “agency is entitled to have second thoughts, and to sustain action which it considers in the public interest upon whatever basis more mature reflection suggests.” Dana Corp. v. ICC, 703 F.2d 1297, 1305 (D.C. Cir. 1983). An agency is entitled to give more weight to socioeconomic concerns than it may have under a different administration. Am. Trucking Associations v. Atchison, T. & S.F. Ry. Co., 387 U.S. 397, 416, 87 S. Ct. 1608, 1618 (1967); see also, Fox, 556 U.S. at 515-516, 129 S. Ct. at 1811.

D. ONRR's Relevant Prior Rulemakings and Associated Litigation

1. Federal Oil and Gas, and Federal and Indian Coal

i. The 2016 Valuation Rule and Industry Lawsuit

On July 1, 2016, ONRR published the 2016 Valuation Rule, which extensively updated the royalty valuation framework for Federal oil and gas and Federal and Indian coal. The effective date of the 2016 Valuation Rule was January 1, 2017.

ii. The 2017 Postponement Notice

On February 27, 2017, ONRR published the 2017 Postponement Notice, which attempted to postpone the effective date of the 2016 Valuation Rule. In response, the States of California and New Mexico filed suit in the United States District Court for the Northern District of California to challenge the 2017 Postponement Notice. See Becerra v. U.S. Dep't. of the Interior, 276 F. Supp. 3d 953 (N.D. Cal. 2017).

iii. The 2017 Repeal Rule

On August 7, 2017, ONRR published the 2017 Repeal Rule, which attempted to repeal the 2016 Valuation Rule in its entirety. On October 7, 2017, the States of California and New Mexico filed a second suit in the United States District Court for the Northern District of California to challenge the 2017 Repeal Rule. On March 29, 2019, the District Court issued a decision that vacated the 2017 Repeal Rule. Becerra v. U.S. Dep't of the Interior, 381 F. Supp. 3d 1153 (N.D. Cal. 2019). The decision reinstated the 2016 Valuation Rule, including the rule's original effective date of January 1, 2017. Id. at 1179. See also Becerra v. U.S. Dep't of the Interior, Case No. C 17-5948 SBA, Order at page 3 (July 30, 2020).

ONRR included mention of the District Court's findings in the 2020 Proposed Rule (85 FR 62054, 62055-62056), and discusses those findings further below.

Several months after the 2016 Valuation Rule was reinstated, industry filed litigation in the United States District Court for the District of Wyoming, challenging the 2016 Valuation Rule. See Cloud Peak Energy, Inc. v. U.S. Dep't of the Interior, Case No. 19-CV-120-SWS (D. Wyo.). On October 8, 2019, the Wyoming District Court entered an Order granting in part and denying in part industry's request for a preliminary injunction with respect to the 2016 Valuation Rule. The Order stayed all portions of the 2016 Valuation Rule applicable to Federal and Indian coal. Cloud Peak, 415 F. Supp. 3d 1034, 1053 (D. Wyo. 2019). Thus, Federal and Indian coal lessees continue to report and pay royalties under the 1989 Federal and Indian Coal Valuation Regulations (54 FR 1492) while the Cloud Peak case is being litigated.

2. Civil Penalties

ONRR previously amended portions of its civil penalty regulations, at 30 CFR part 1241, on August 1, 2016 (81 FR 50306) in order to clarify the civil penalty regulations and increase transparency about how ONRR assesses civil penalties. API challenged the 2016 Civil Penalty Rule in the United States District Court for the District of Wyoming. The District Court upheld the 2016 Civil Penalty Rule, except as to one issue. See API v. U.S. Dep't. of the Interior, 366 F. Supp. 3d 1292, 1309-10 (D. Wyo. 2018). The exception was 30 CFR 1241.11(b)(5), which provides that a petitioner may forfeit the benefit of a stay of the accrual of civil penalties if an ALJ determines that the petitioner's defense to a previously issued civil penalty is frivolous. The District Court held that the provision was an abuse of discretion and facially not in accordance with the law. See API, 366 F. Supp. 3d at 1310.

API appealed to the United States Court of Appeals for the Tenth Circuit, which vacated the District Court's decision, finding API lacked standing to pursue its facial challenge to the 2016 Civil Penalty Rule. See API v. U.S. Dep't of the Interior, 823 Fed. Appx. 583 (10th Cir. 2020). Upon remand, the District Court dismissed API's claim for lack of jurisdiction. API, Case No. 17-cv-83-NDF, D. Wyo., Order dated Sept. 29, 2020.

E. Public Comment Overview

1. Public Comment Period

On August 7, 2020, the Department issued a press release to notify the public of the 2020 Proposed Rule and, on the same day, ONRR published the text of the 2020 Proposed Rule on its website for the public to view in advance of the 2020 Proposed Rule's publication in the Federal Register.

On October 1, 2020, ONRR published the 2020 Proposed Rule in the Federal Register. The 2020 Proposed Rule provided a 60-day comment period that closed on Monday, November 30, 2020. See 85 FR 62054. ONRR received comments from numerous industry members, trade associations, public interest groups, members of Congress, members of the public, and state and local entities. ONRR received a total of 40,456 pages of comments, of which 38,150 pages were a similar form comment. If the 38,150 pages of form comments are treated as a single comment, ONRR received 2,307 unique pages of comment materials.

2. Specific Comments Requested by ONRR in the 2020 Proposed Rule

In section F of the 2020 Proposed Rule, ONRR requested comments on specific topics (85 FR 62070-62071). This rule addresses those comments in the applicable amendment discussions herein.

3. General Comments

Public Comment: One commenter claimed that ONRR's 2020 Proposed Rule is arbitrary and capricious. ONRR's claim that the 2020 Proposed Rule will increase natural resource production is arbitrary and capricious because it is unsupported in the rulemaking record, the commenter said. The commenter stated that ONRR failed to provide any analysis or record to demonstrate that production increases will occur. According to the commenter, ONRR also contradicted itself by stating that the 2020 Proposed Rule would not materially alter natural resource exploration, production, or transportation.

ONRR Response: In the 2020 Proposed Rule, ONRR provided its rationale for proposing the amendments. ONRR acknowledged instances where it believed additional information could improve its analyses. Consequently, ONRR posed a list of specific, targeted questions in the 2020 Proposed Rule to solicit additional information from public commenters for ONRR's consideration. ONRR reviewed and considered all substantive comments it received, and, where appropriate, revised its analysis in this final rule based on the information provided by the public comments.

The commenter is correct that the 2020 Proposed Rule does not quantify an increase in domestic energy production—neither does this final rule. This rule is not premised on increasing the production of oil, gas, or coal by some measured amount. Instead, this rule, in part, is meant to incentivize both the conservation of natural resources (by extending the life of current operations) and domestic energy production over foreign energy production. The Department typically conducts economic analyses regarding changes in leasing fiscal terms or increased/decreased regulatory burdens. The margin of error for estimating this rule's negligible or marginal impact on actual production is beyond the capability of the Department's existing models, and the Department does not know of other economic models that are sufficiently sensitive to accurately measure these changes. The Department's models are designed to analyze newly available geologic information, changes in prices and fiscal changes to future lease terms. The model results provide estimates of the downstream impact on public lands leasing and production, and it would not be appropriate for ONRR to use these results to estimate to estimate any production changes due to the provisions of this rulemaking because these provisions impact leases currently in production.

ONRR disagrees with the commenter that ONRR contradicted itself in the 2020 Proposed Rule. ONRR believes the commenter misunderstood the separate activities of (1) ONRR's explanation of the rule's objectives and estimating its royalty and administrative impacts, and (2) ONRR's application of certain criteria to determine whether it must make an additional statement or analysis to comply with NEPA requirements.

Public Comment: A commenter also claimed that if production does increase as a result of the rule, then ONRR's failure to address the environmental costs associated with such production increase is arbitrary and capricious. According to the commenter, increased production will result in negative environmental externalities, which ONRR must consider under Federal land management statutes and the APA. The commenter specifically cites to FLPMA, MLA, and OCSLA as authorities that require ONRR to consider environmental impacts when promulgating regulations involving energy production on Federal lands. As the commenter pointed out, the APA also requires agencies to “examine the relevant data and articulate a satisfactory explanation for its action.” Motor Vehicle Assn. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983).

Another commenter raised additional environmental concerns with ONRR's 2020 Proposed Rule. This commenter requested that ONRR consider environmental impacts alongside the effects on the oil and gas industry as a result of this rule. The commenter stated that ONRR is supposed to consider and consult with more stakeholders when engaging in the rulemaking process. The commenter explained that the list of stakeholders should include government agencies, environmentalists, private companies, actors in the fossil fuel industries that operate on Federal and Indian land, and people who consume oil and gas. The commenter stated that this type of stakeholder engagement would make ONRR's rulemakings more comprehensive.

ONRR Response: The environmental impacts of energy and mineral development are analyzed at other stages in the development process, including the land use planning stage, the lease sale stage, and the project-specific development stage when more specific details of the potential environmental impacts and use on the leased area by a proposed project would be readily available. Further environmental review of these projects in the context of this rulemaking is thus duplicative and unnecessary. Generally, an agency's promulgation of regulations must be based within the agency's specific legal mandate and cannot extend beyond the intended reach of the agency's statutory and delegated authority. Similarly, an agency's primary rulemaking objective and goal must align with the stated purpose of the Acts governing the agency's rulemaking. Congress gave the Secretary authority to promulgate regulations concerning “a comprehensive inspection, collection and fiscal and production accounting and auditing system to provide the capability to accurately determine oil and gas royalties, interest, fines, penalties, fees, deposits, and other payments owed, and to collect and account for such amounts in a timely manner.” 30 U.S.C. 1701(a) (emphasis added). See also 30 U.S.C. 1701(b)(2) (“It is the purpose of this chapter . . . to clarify, reaffirm, expand and define the authorities and responsibilities of the Secretary of the Interior to implement and maintain a royalty management system for oil and gas leases on Federal lands, Indian lands, and the [OCS]. . . .”). A similar broad grant of authority to promulgate regulations is provided to the Secretary under the MLA at 30 U.S.C. 189 and OCSLA at 43 U.S.C. 1334. ONRR is amending its royalty valuation and civil penalty regulations, and has considered all relevant information within this context in accordance with the Department's statutory mandate, as set forth under the MLA, OCSLA, and FOGRMA.

Regarding the commenter's reference to FLPMA, that Act governs leasing activities primarily carried out by other Department bureaus and offices. For energy leasing, exploration, and development activities to be conducted on Federal or Indian land, these Department bureaus and offices evaluate the environmental impacts by conducting NEPA analyses. Thus, environmental impacts associated with newly proposed projects or operations are evaluated during the leasing and permitting stages by the appropriate bureau or office. If a project or operation is significantly modified or expanded beyond the initial approvals and corresponding NEPA analysis, the responsible agency will reevaluate any additional environmental impacts and conduct the appropriate NEPA analysis. This rule does not lessen the obligation borne by other Department bureaus and offices to perform NEPA analyses at all appropriate stages in the leasing and lease administration process.

In response to the commenter's statement pertaining to stakeholder involvement, ONRR solicited input from all interested persons and stakeholders, including environmental organizations, as part of this rulemaking. Through the publication of the 2020 Proposed Rule in the Federal Register on October 1, 2020, ONRR provided “interested persons an opportunity to participate in the rule making through submission of written data, views, or arguments” as required under the APA. 5 U.S.C. 553(c). The 2020 Proposed Rule provided all interested persons with a 60-day public comment period to submit information for ONRR's consideration.

Public Comment: Another public commenter stated that ONRR likely will be required to once again change its regulations as a result of a change in Administrations. The commenter cites to statements suggesting that a future Administration would modify or reverse the E.O.s currently relied upon by ONRR for this rulemaking.

ONRR Response: The commenter cited general environmental policy objectives of a new Administration, which are not in place at the time of this rulemaking, and failed to identify any specific conflicts between any such policies and the proposed amendments. ONRR bases its policies on statutory dictates and its current priorities, rather than speculation about what a future administration might do. ONRR, in part, based the 2020 Proposed Rule on E.O.s and S.O.s in effect at the time of its publication, and on the policies underlying those directives. Those same E.O.s and S.O.s are still in effect for ONRR to consider in this final rule. Moreover, the underlying policies are valid, and deserve weight, aside from the particulars of the E.O.s and S.O.s. Please refer to Sec. I.A. for a general overview of this rule's objectives and the amendment discussion sections for additional explanations specific to each amendment.

II. Amendment Discussion—Part 1206 Product Valuation

A. Index-Based Valuation Method To Value Federal Gas

General Comments

Public Comment: ONRR requested and received comments on the index-based valuation method amendments. Specifically, ONRR asked for alternatives to requiring a lessee to evaluate all pricing points where a lessee's gas may flow. Several commenters from or representing the regulated community suggested that ONRR use the pricing point where a lessee's gas actually flows, rather than evaluate all possible pricing points. These commenters suggested this would lessen the burden on a lessee to research all possible index points and create greater certainty that a lessee did not overlook any possible index points.

ONRR Response: As ONRR monitors reporting and payments under the index-based valuation methods adopted in the 2016 Valuation Rule and in this final rule, and systematically examines actual transaction data, ONRR will continue to look for alternatives to evaluating all accessible index pricing points, including alternatives that require tracing production to determine the actual index pricing point. However, at this time, ONRR does not have the data to support the suggested change. Accordingly, ONRR is not making the change in this final rule.

Public Comment: ONRR received several comments requesting ONRR update the transportation and fractionation (“T&F”), and processing adjustments, published at https://www.ONRR.gov,, for the NGL index-based valuation method. These commenters stated that the values are outdated and do not reflect current markets or FERC published rates. The commenters also expressed concerns that the NGL index-based method does not allow for deductions for pre-plant transportation and the transportation deductions for unprocessed and residue gas should apply to NGLs.

ONRR Response: ONRR did not propose amendments to the adjustments to the NGL index-based valuation method. While these comments are beyond the scope of this rulemaking, ONRR regulations state the T&F adjustments will be periodically updated (§ 1206.142(d)(2)(ii)), as outlined in the preamble to the 2016 Valuation Rule. ONRR will continue to periodically review and update these adjustments, as necessary. However, at this time, ONRR is not amending the proposed unprocessed and residue gas transportation deductions to apply to NGLs.

Public Comments: A commenter requested that ONRR develop a valuation method for areas that do not have access to index-pricing points, specifically for gas produced in Alaska.

ONRR Response: Currently, ONRR is not incorporating a specific valuation method for areas that do not have access to index-pricing points. A lessee cannot elect to use an index-based method in these areas, and the lessee must continue using the first arm's-length sale to value Federal gas.

Public Comments: Some commenters requested that ONRR modify the index-based valuation method, and some commenters specifically submitted comments for consideration during future rulemakings. These comments include: (1) ONRR should consider extending the election period to value Federal gas, under the index-based valuation method, from two years to a minimum of three years; (2) ONRR should require or mandate a lessee value Federal gas using the index-based valuation method; (3) ONRR should develop an index-based method to value gas at the wellhead; and (4) ONRR should allow a lessee to propose an alternative valuation method under certain situations that force a lessee to value gas under the index-based valuation method (e.g. gas sold under a keepwhole contract with no arm's-length gross proceeds sales from the same lease, flared gas).

ONRR Response: In this final rule, ONRR will not adopt these suggested changes as these changes are outside of the scope of this rulemaking. Additionally, ONRR will not act to implement suggestions for an extended election period or mandatory use of index-based valuation methods. At this time, both ONRR and lessees are best served in implementation of new valuation methods by shorter commitments and optional use.

1. Expansion of the Federal Gas Index Pricing Valuation Method Under a Non-Arm's-Length Contract to Federal Gas Sold Under Arm's-Length Contracts (§§ 1206.141(c) and 1206.142(d))

The 2016 Valuation Rule amended 30 CFR part 1206 to allow a lessee two valuation methods to value its non-arm's-length Federal gas sales. The first valuation method was to value Federal gas based on the first arm's-length sale occurring after a non-arm's-length sale or transfer of the gas to the lessee's affiliate. The second valuation method was to elect to use an index-based valuation method. This index-based valuation method aligns with a provision from the 2000 Federal Oil Valuation Rule, “Establishing Oil Value for Royalty Due on Federal Leases” (65 FR 14022, March 15, 2000), that allowed a lessee to elect to value Federal oil using index prices when it sells or transfers oil to an affiliate that, in turn, then sells the oil at arm's-length. The 2020 Proposed Rule would extend optional use of the index-based valuation method to arm's-length sales of Federal gas.

Comments on the Proposed Amendment

Public Comment: Several commenters supported the expansion of the index-based valuation method for Federal gas sold under an arm's-length contract. Commenters agreed that having the option to elect an index-based method lessens the burden and provides early certainty for all payors. Commenters noted that a lessee is more likely to use the index-based method if it is applicable to all its Federal gas sales and that this valuation method will truly lessen the administrative burden by allowing a lessee to use one approach to value gas sold under multiple contracts. The commenters reiterated that extending the index-based method to all Federal gas sales will further eliminate the burden to unbundle and comply with marketable condition regulations. One commenter stated that the index-based valuation method should be mandatory instead of being a method that gas producers can select for non-arm's-length sales for two-year periods.

ONRR Response: Many commenters were in favor of the proposed changes published in the 2020 Proposed Rule. In this final rulemaking, ONRR is adopting the amendment as proposed in the 2020 Proposed Rule to allow a lessee with an arm's-length sale to elect to value its gas production under the index-based valuation method. Regarding the commenter's statement that the index-based valuation method should be mandatory, ONRR is not choosing to make it mandatory at this time for all sales, but will collect data based on optional use to inform possible future rulemaking.

Public Comment: Some commenters opposed the extension of the index-based method, and stated that ONRR has not provided enough data to modify the position it took in the 2016 Valuation Rule, including that arm's-length sales are the best indicator of value.

ONRR Response: ONRR maintains that arm's-length sales are generally the best indicator of value. Index prices are derived from arm's-length sales reported to index pricing publications. The index-based valuation method simplifies the current valuation method and, in addition, provides transparency and early certainty to a lessee. The index-based method provides early certainty because the elements of the index-based formula are all known at the time royalty reports are first due, which is the end of the month following the month of production, and not subject to subsequent adjustment. In contrast, when royalty value is based on actual sales prices, transportation costs, and, for gas, processing costs, adjustments to those prices and costs in subsequent months change royalty values and require re-reporting. Also, the sales prices, transportation costs, and processing costs may be disputed through an ONRR audit or other ONRR compliance activity.

The index-based method, in contrast, uses transparent, certain prices published prior to the royalty due date, and a fixed percentage of those published prices as an “allowance” to cover the costs of transportation. ONRR recognizes that ONRR and all Federal lessees can benefit from the certainty and transparency that the index-based valuation method provides. Additionally, complex valuation situations are not limited to non-arm's-length dispositions. In arm's-length transactions, many third-party pipeline and service providers now charge lessees “bundled” fees that include costs to place production into marketable condition. Both ONRR and lessees with arm's-length sales, transportation, and/or processing contracts have found allocating the costs between allowed and disallowed costs is necessary for valuation based on gross proceeds, but administratively costly and time consuming. These are not required with index-based royalty reporting and payment cost allocations.

Public Comment: A commenter suggested that ONRR require a lessee to pay on whichever value is higher between gross proceeds and the index-based valuation method to eliminate the temptation to manipulate index prices.

ONRR Response: Requiring a lessee each and every month to value gas by both gross proceeds and the index-based valuation method forces a lessee to use two valuation methods and increases the burden of either method individually. This would not achieve the mutual goal of a simple or certain valuation method for ONRR or a lessee. While there have been instances of traders attempting to manipulate index prices in recent years, these have been infrequent and involve limited volumes. ONRR believes that index prices are an acceptable method to value royalties for the following reasons: (1) The FERC must approve pricing publications used as the source of index prices for Federal gas royalty reporting and payments; (2) index publishers have protections to prevent and discourage price manipulation; (3) ONRR maintains discretion to disallow the use of an index point; and (4) index prices already influence royalty valuation, as they are used as the sales price or as part of a sales price formula in many arm's-length sales contracts. Further, as discussed in the preamble to the 2020 Proposed Rule, even when a lessee elects to use the index-based valuation method to report and pay royalties, ONRR retains the right and ability to from time to time examine, review, analyze, and audit the lessee's actual transaction data—including sales, transportation, processing, and contracts for services required to place production in marketable condition. By periodically examining actual transaction data, ONRR will be well positioned to ascertain the continuing validity of both the index prices and ONRR's continued use of an index-based valuation method. If ONRR finds an index price unreliable, ONRR will have the opportunity to stop using that index price. And if ONRR finds that its index-based valuation method needs adjustment, ONRR will have the opportunity to change the method through future rulemaking.

ONRR appreciates the comments supporting, seeking modification to, and opposing the proposed amendments to §§ 1206.141(c) and 1206.142(d). After careful consideration, and for the reasons explained in the 2020 Proposed Rule and this final rule, ONRR is adopting the proposed changes to §§ 1206.141(c) and 1206.142(d) as part of this final rule.

2. Published Average Bidweek Price (§§ 1206.141(c)(1)(i) and (ii); and 1206.142(d)(1)(i) and (ii))

For unprocessed gas and residue gas, the 2016 Valuation Rule's index-based valuation method requires use of the highest monthly bidweek price for the index pricing points that a lessee's gas can flow to, whether or not there is a constraint for that production month, less a specified deduction. The 2020 Proposed Rule proposed to amend the 2016 Valuation Rule to use the highest of the monthly bidweek average prices for the index pricing points that a lessee's gas can flow to, whether or not there is a constraint for that production month, instead of the highest of the monthly bidweek high prices. See 85 FR 62058.

When ONRR uses the term in the 2020 Proposed Rule, “published average bidweek price,” or “bidweek average” for short, it refers to what many publications call the “index” or “average” price. For example, the Platts Inside FERC's Gas Market Report labels this price as the “index,” while the Natural Gas Intelligence's (“NGI”) Bidweek Survey labels this price as the “average.”

An index-based valuation method using bidweek average prices still results in a royalty value comparable to the fair market value a lessee could receive under the typical arm's-length contract, and ONRR anticipates this method will be used by more lessees, because it better reflects the average price the average lessee receives, rather than the high price only one lessee receives. Greater use of the index-based valuation method will ease both the lessee's administrative burden and ONRR's.

Lastly, using the bidweek average price for unprocessed gas and residue gas aligns with the use of average prices used in the NGL index-based valuation method (§ 1206.142(d)(2)(i)) and the Federal oil regulations (§ 1206.102). Using average prices for all the index-based valuation methods provides consistency and transparency, increases accuracy, and avoids confusion and potential errors.

Comments on the Proposed Amendment

Public Comment: ONRR received several comments that support using the bidweek average price rather than the bidweek high price in the index-based valuation method. Commenters stated that the bidweek average price more closely reflects the price a lessee could obtain and is closer to the value of gross proceeds. Commenters stated the bidweek average price results in a more reasonable value for royalty purposes and that a lessee is more likely to elect the index-based valuation method. Another commenter stated that bidweek average prices are more certain and reliable because they represent many transactions at the same pricing point. On the contrary, the highest bidweek price may only represent a single transaction, which may or may not reflect normal market dynamics.

ONRR Response: The bidweek high price is the highest price reported for any transaction that qualifies for reporting, which may or may not reflect usual market dynamics. The bidweek average price is just that—an average price from many arm's-length transactions at the same pricing point. For the reasons discussed above, ONRR is adopting the use of the bidweek average price in this final rule.

Public Comment: A commenter supported using the bidweek average prices since a lessee could more easily access the bidweek average price based on its own contract pricing but would have to pay a third-party publication to access the high bidweek prices.

ONRR Response: If a lessee chooses to use contract prices that reference an index price, rather than a price found in a subscription or publication, it is up to the lessee to verify that the contract price is accurate, and that it reflects all possible index pricing-points. ONRR will rely on ONRR's subscriptions to verify pricing in any compliance activity. ONRR is not aware of any difference in subscription costs between publications identifying the bidweek average and the bidweek high prices.

Public Comment: Several commenters stated that ONRR should require the highest of the bidweek high prices, because it better protects the interests of the taxpayers and States. Additionally, commenters opposed adopting any amendment that would decrease royalties paid to ONRR.

ONRR Response: ONRR disagrees that using the bidweek high price better protects the lessor's interest than using the bidweek average price. While the bidweek average price is lower than the bidweek high price, the bidweek average more closely reflects the gross proceeds that a lessee would typically receive in an arm's-length transaction, and therefore is more likely to actually be used by lessees. ONRR maintains that other protections are still in place, such as requiring the lessee to choose this option for a minimum of two years and requiring the lessee to use the highest bidweek average price to which the gas could flow when multiple pricing points are involved.

Furthermore, in the context of the overall rulemaking, it is possible that the index-based valuation method (if actually used) may increase royalties paid under this method. As outlined in the Procedural Matters section, overall royalty values under the 2020 Valuation Rule's index-based valuation method are around $0.04/MMBtu higher than the prices reported to ONRR for arm's-length sales, even with the use of average rather than high bidweek prices.

ONRR appreciates the comments supporting, seeking the modification to, and opposing the proposed amendments to §§ 1206.141(c)(1)(i) and (ii) and 1206.142(d)(1)(i) and (ii). After careful consideration, and for the reasons stated in the 2020 Proposed Rule and this final rule, this final rule adopts the proposed amendment in full.

3. Transportation Deductions (§§ 1206.141(c)(1)(iv) and 1206.142(d)(1)(iv))

The 2016 Valuation Rule amended ONRR's regulations to allow a lessee that elects to use the index-based valuation method to include an adjustment for transportation based on the location of its lease (e.g., OCS, GOM, or all other areas). The rule further constrained the transportation adjustment to a specified range measured in cents per MMbtu. The 2016 Valuation Rule adjustments and minimum-to-maximum ranges were as follows:

Location	Transportation adjustment (%)	Minimum rate (cents per MMbtu)	Maximum rate (cents per MMbtu)
OCS, GOM	5	$0.10	$0.30
All Other Areas	10	0.10	0.30

ONRR based the transportation adjustment and minimum-to-maximum constraint on its analysis of transportation allowances reported to ONRR for production months in calendar years 2007 to 2010 (proposed 2016 Valuation Rule, 80 FR 618, January 6, 2015).

In the 2020 Proposed Rule, ONRR performed the same analysis for production months in calendar years 2014 through 2018. Based on this analysis of more recent time periods, ONRR proposed to revise the allowed transportation adjustments and minimum-to-maximum constraints as follows:

Location	Transportation adjustment (%)	Minimum rate (cents per MMbtu)	Maximum rate (cents per MMbtu)
OCS, GOM	10	$0.10	$0.40
All Other Areas	15	0.10	0.50

The 2020 Proposed Rule explained that these values more closely reflect the actual costs a lessee will incur to transport gas to an index-pricing point. See 85 FR 62058. ONRR will continue to monitor reported transportation allowances to ensure that the adjustments under its regulations for the index-based valuation method continue to be representative of the actual costs that lessees report to ONRR.

Comments on the Proposed Amendment

Public Comment: ONRR received comments supporting the proposal to update the transportation adjustment values in order to more accurately reflect the current markets and rates charged for arm's-length transportation.

ONRR Response: ONRR agrees with these comments that the transportation adjustment amounts should more closely reflect the average cost a lessee incurs to transport gas to an index pricing point. ONRR will continue to monitor transportation allowances reported by lessees, including those who have not elected to report under the index price valuation method but under gross proceeds, and will periodically review, examine, analyze, or audit actual transportation transactions and the costs of placing gas into marketable condition to ensure that the adjustments under these regulations remains representative of the costs a lessee incurs on average.

Public Comment: Commenters stated that ONRR should not update the transportation adjustments for the index-based valuation method. These commenters opposed any amendment that will result in lower royalties paid to the Federal Government and disbursed to State and local governments.

ONRR Response: While ONRR understands these concerns, ONRR's analysis of data supports modifying the adjustments to more closely reflect the average costs a lessee incurs to transport gas to an index pricing point. ONRR will continue to monitor transportation adjustments, and will periodically review, examine, analyze, or audit actual transportation contracts and the costs of placing gas into marketable condition to ensure that the adjustments remain reflective of the average cost lessees incur.

Public Comment: An industry commenter stated that because the transportation adjustments were calculated using data from calendar years 2014 through 2018, they are already outdated. Most transportation contracts have moved to fixed-fee rates since that time and with lower commodity prices, transportation can exceed the updated adjustments. The commenter suggested ONRR find alternatives to a set percentage or evaluate transportation adjustments more frequently.

ONRR Response: ONRR will monitor and review the transportation adjustments. If ONRR finds that the transportation adjustments cease to reflect typical costs, ONRR can take action to update the transportation adjustment to ensure that its index-based valuation method captures a reasonable value for royalty purposes.

Public Comment: A commenter expressed concern that ONRR failed to document and explain its calculations of the revised index-based transportation adjustments. The commenter expressed a need for greater transparency to ensure that ONRR is accountable to the public for its decisions.

ONRR Response: ONRR identified the weighted per unit transportation rate and imputed the transportation percentage from the data reported on the form ONRR-2014 for the months in the noted calendar years for properties reporting a transportation allowance. Using this method, ONRR identified a maximum, minimum, and average range for both OCS and all other properties. ONRR used these values to establish the updated transportation deductions in the 2020 Proposed Rule.

ONRR appreciates the comments supporting, seeking the modification to, and opposing the proposed amendments to §§ 1206.141(c)(1)(iv) and 1206.142(d)(1)(iv). After careful consideration, and for the reasons set out in the 2020 Proposed Rule and this final rule, this final rule will adopt the proposed amendment in full.

4. Zero Value (§§ 1206.141(f) and 1206.142(g))

In the 2020 Proposed Rule, ONRR proposed to add language to the unprocessed (§ 1206.141(f)) and processed (§ 1206.142(g)) gas regulations clarifying ONRR's long-standing policy that the value of any product cannot be reported as less than zero. Consistent with language included in lease documents, including a lessee's duty to market gas at no cost to the Federal Government, lessees have never been permitted to report negative royalty values. Adding this to the regulatory language promotes consistent and clear regulations.

When ONRR published the 2020 Proposed Rule, its systems were unable to accept a reporting line with a $0.00 royalty value. In instances where the royalty value would correctly be $0.00, ONRR instructed reporters to code the reporting line using Transaction Code 20 and report a royalty value less allowances of $0.01. The 2020 Proposed Rule's proposed regulatory text reflected this constraint by including language that, for example, prevented a lessee from reducing “the royalty value of any production to zero.” Emphasis added.

ONRR now has the system capability to accept a report with a $0.00 royalty value, and no longer has a need to include a workaround for that constraint in this final rule. Thus, in the example above, this final rule will modify the proposed amendment to §§ 1206.141(f) and 1206.142(g) to state that “Under no circumstances may your gas be valued for royalty purposes at less than zero.” Emphasis added.

Comments on the Proposed Amendment

Public Comment: A commenter requested ONRR clarify this provision. The commenter stated that payors received guidance from ONRR stating, “for those situations where your value for royalty purposes, plus any disallowed costs or additional consideration under your sales contract, is less than or equal to $0.00, ONRR's regulations and your Federal lease require you to report and value any Federal gas production removed or sold from your lease, even if the value is zero or less than zero.” The guidance further instructed reporters to report those zero royalty values, where the proposed rule does not allow a zero-royalty value. The inconsistency in guidance and the proposed rule changes create confusion and uncertainty, the commenter said.

ONRR Response: ONRR acknowledges that its guidance and the proposed amendment may be inconsistent. However, the purpose of the amendment is to resolve any confusion that may have arisen under ONRR's prior regulations and guidance. If there is an inconsistency between the amendments adopted in this final rule and any prior guidance, this final rule will control. ONRR recognizes that, in the absence of the clarifying language in this final rule, a lessee might seek to report a royalty value of zero in instances where gross proceeds or index prices are at or below zero, after adding back any disallowed costs or additional considerations. However, this final rule clarifies that products cannot be valued, for royalty purposes, less than zero, but can be valued at zero. This regulatory change is consistent with language included in most lease documents, including a lessee's duty to market gas at no cost to the Federal Government. Lessees have never had the ability to report negative royalty values.

ONRR appreciates the comments supporting, seeking the modification to, and opposing the proposed amendments to §§ 1206.141(f) and 1206.142(g). After careful consideration, and for the reasons stated in the 2020 Proposed Rule and this final rule, this final rule adopts the proposed amendment with the modification described above to clarify that a lessee can report a $0.00 royalty value. This modification between the 2020 Proposed Rule and this final rule impacts a limited number of instances to change the reported royalty value from $0.01 to $0.00. As such, ONRR finds there will be no material change to the royalties it collects, and it does not further distinguish the modification in this rule's economic analysis.

5. Providing Sales Records (§§ 1206.141(g) and 1206.142(h))

The 2020 Proposed Rule proposed to add new regulation language to reinforce ONRR's statutory authority under 30 U.S.C. 1713(a), which expressly requires “a lessee, operator, or other person directly involved in developing, producing, transporting, purchasing, or selling oil or gas . . . through the point of first sale or the point of royalty computation, whichever is later, establish and maintain any records, . . . and provide any information” required by rule to ONRR when it is “conducting an audit or investigation.” ONRR proposed the addition of regulatory language to clarify that it may continue to request and receive a lessee's and its affiliate's sales and expense records, even when a lessee pays royalties under an index-based valuation method.

The ability to continue to evaluate sale and expense records will ensure the index-based valuation method remains a fair market value for Federal oil and gas lessees' production. ONRR has the authority to request this information when conducting an audit or investigation, and the new regulatory text will preserve the ability to obtain a lessee's records in order to evaluate whether the index-based valuation method remains a fair value for royalty purposes.

Comments on the Proposed Amendment

Public Comment: Several commenters acknowledge ONRR already has the authority to collect records from a lessee during the normal course of audit and compliance activity. However, the commenters expressed concern that frequent and persistent requests for data will create an unnecessary burden. The commenters referenced the preamble language in the 2020 Proposed Rule and ONRR's suggestion that the index-based method should create simplicity and early certainty when reporting royalties. Commenters expressed concern that ONRR will continue to request and audit these records and eliminate any of the simplicity that the index-based method affords.

ONRR Response: ONRR does not believe that adding this language to regulatory text will create an unnecessary burden on a lessee that elects to use the index-based method. Further, any burden to a lessee is outweighed by the certainty of knowing that ONRR will have access to information needed to periodically evaluate the reliability of individual index prices. Finally, if ONRR requires a lessee to provide information under this section, and that information establishes that the index-based method is no longer representative of fair market value, any change to or repeal of the method would be done through rulemaking, and would only have prospective application.

ONRR appreciates the comments supporting, seeking the modification to, or opposing the proposed amendments to §§ 1206.141(g) and 1206.142(h). After careful consideration, and for the reasons explained in the 2020 Proposed Rule and this final rule, ONRR is adopting the proposed changes to §§ 1206.141(g) and 1206.142(h) as part of this final rule.

B. Transportation Allowance for Certain Offshore Federal Oil and Gas Gathering Costs

In the 2020 Proposed Rule, ONRR explained the origins of its current “gathering” definition and how ONRR and MMS have considered over the years whether to allow the cost of certain offshore gathering activities to be included in a lessee's transportation allowance. See 85 FR 62054. Central to this amendment's discussion are the Deepwater Policy (https://www.onrr.gov/​Laws_​R_​D/​pubcomm/​PDFDocs/​990520.pdf) and the 2016 Valuation Rule, which rescinded the Deepwater Policy. See 81 FR 43338.

Because of the unique nature of the OCS, particularly in the deepwater OCS, the 2020 Proposed Rule proposed to amend ONRR's regulations to permit the same deductions previously taken under the Deepwater Policy. Under the Deepwater Policy, a lessee could claim certain gathering costs in its transportation allowance if certain criteria were met, including:

• A part of the lease must lie in waters deeper than 200 meters.
• The transportation allowance must otherwise be determined in accordance with ONRR's regulations.
• The costs must be allocated between the royalty bearing and non-royalty bearing substances (for example, water or production subject to a zero royalty rate).
• The leases and units must be treated similarly.
• Movement prior to a central accumulation point is still disallowed from a transportation allowance. A central accumulation point, for purposes of the Deepwater Policy, may be a single well, a subsea manifold, the last well in a group of wells connected in series, or a platform extending above the water's surface.
• The movement must be to a facility not located on a lease adjacent to the lease on which the production originated. An adjacent lease is defined as a lease with at least one point of contact with the producing lease or unit.

The 2020 Proposed Rule proposed to permit a lessee to request, and ONRR to approve, an application of the deepwater gathering-as-transportation principles in shallow waters under certain circumstances.

The 2020 Proposed Rule also proposed to remove certain language that the 2016 Valuation Rule added to ONRR regulations. Specifically, through the 2020 Proposed Rule, ONRR removed (1) the language under §§ 1206.110(a)(2)(ii) and 1206.152(a)(2)(ii), which provided “[f]or [production from] the OCS, the movement of [production] from the wellhead to the first platform is not transportation,” and (2) the portion of the “gathering” definition at § 1206.20, which stated that “any movement of bulk production from the wellhead to a platform offshore.”

While the 2020 Proposed Rule's preamble fully explained ONRR's intent behind its proposal to adopt regulatory text that is consistent with the former Deepwater Policy, the proposed regulatory text failed to include all of the Deepwater Policy's requirements. Specifically, the proposed regulatory text was not consistent across the oil and gas sections and did not include the adjacency limitation or the requirement for a lessee to identify a central accumulation point at or near the subsea wellheads (explained in the 6th and 5th bulleted points respectively, supra.).

Comments on the Proposed Amendment

Public Comment: Industry commenters endorsed ONRR's attempt to adopt regulations consistent with the Deepwater Policy. These commenters argued that the Deepwater Policy supported innovative technology development that minimized surface facilities, reduced environmental risks, and increased ultimate recovery. They also argued that adopting regulations consistent with the Deepwater Policy would return a longstanding ONRR practice that lessees relied on to inform their business decisions.

ONRR Response: Based on public comments such as these, adoption of regulations consistent with the Deepwater Policy may reduce a lessee's total royalty burden, resulting in a lower total cost to operate on the OCS, and thereby potentially encouraging continued production and conservation of resource. Additionally, consistent and transparent regulations reduce uncertainty for investors, which provides a competitive advantage for development of domestic production. Recent Executive and Secretarial Orders call on Federal agencies to appropriately promote and unburden domestic energy production, especially OCS resources. See E.O. 13783, “Promoting Energy Independence and Economic Growth,” E.O. 13795, “Implementing an America-First Offshore Energy Strategy,” and S.O. 3350, which promotes the America-First Offshore Energy Strategy.

Public Comment: One industry commenter, while supportive of the Deepwater Policy, argued that adoption of regulations consistent with the Deepwater Policy is moot. This commenter suggested that ONRR intends to disallow deductions for any movement of production that is not fully in marketable condition, and cited DCOR, LLC, ONRR-17-0074-OCS (FE), 2019 WL 6127405 (Aug. 26, 2019) (“DCOR”).

ONRR Response: The fact pattern and analysis in DCOR are distinguishable from the amendments in this rule to allow a lessee to claim certain OCS gathering costs. For example, no part of the leases in DCOR were located in water depths deeper than 200 meters. These amendments provide a specific exception to the general principle that a lessee may not include gathering costs in its transportation allowance.

Public Comment: Several commenters noted the inconsistency between the oil and gas sections of the proposed rule. The oil section at § 1206.110 included the following language: “For oil produced on the OCS in waters deeper than 200 meters, the movement of oil from the wellhead to the first platform is transportation for which a transportation allowance may be claimed” and “On a case-by-case basis, you may apply to ONRR to have your actual, reasonable and necessary costs of the movement of oil produced on the OCS in waters shallower than 200 meters from the wellhead to the first platform to be treated as transportation for which a transportation allowance may be claimed.” See 85 FR 62080. The gas section of the proposed rule, however, included no such language. See 85 FR 62084.

ONRR Response: In the final rule, ONRR is correcting for the omissions in its proposed regulation text at § 1206.110 to clearly adopt regulations consistent with the Deepwater Policy, except for the provision that would have allowed a lessee to apply for treatment of shallow water gathering as deductible transportation. ONRR is inserting parallel language in the gas regulations at § 1206.152.

Public Comment: One commenter suggested that the language at § 1206.110(a)(1)(i) should end with “including” instead of “except.”

ONRR Response: In the final rule, ONRR restructured the regulation text. The movement of bulk production from or near subsea wellheads to the first platform is gathering. However, this regulatory amendment provides an exception to the general application of the gathering and transportation regulations, allowing subsea gathering costs to be included in a transportation allowance when the regulatory requirements are met.

Public Comment: One commenter requested that, when a lessee submits a request to apply the deepwater gathering-as-transportation principles to a lease in shallow waters, the regulation include a time limit for ONRR to respond and require ONRR to provide an explanation if the request is denied.

ONRR Response: This final rule does not allow a lessee to apply for treatment of shallow water gathering as deductible transportation. A lessee may not submit, nor may ONRR approve, such a request under this final rule. Accordingly, there is no need for ONRR to adopt a time limit for its action on a shallow water request. However, ONRR intends to continue studying any need for, and the economic impact of, a shallow water gathering allowance, and may propose a future rulemaking on this subject.

Public Comment: Public interest groups opposed the effort, arguing the policy permitted, in the form of a transportation allowance, is an improper deduction under ONRR's regulatory scheme. A commenter argued that ONRR does not have the authority to incentivize production and should not attempt to do so using a policy like this to minimize a lessee's royalty obligations. Another commenter stated that the oil and gas industry has received several royalty relief measures for offshore production and that the government should not be further helping industry at the taxpayers' expense.

ONRR Response: Although ONRR's primary focus is the collection, verification, and disbursement of natural resources revenues, it shares the Department's policy goals to promote the development of natural resources and to obtain for the public a reasonable financial return on assets that belong to the public. See S.O. 3350 and S.O. 3360. ONRR has the statutory authority to promulgate regulations and to carry out the stated purposes of the Acts as explained further in the introduction of this final rule. The mineral leasing authorities granted to the Secretary by Congress provide broad authorities to “prescribe necessary and proper rules and regulations and to do any and all things necessary to carry out and accomplish the purposes of [the leasing statutes]”, including the collection of all revenues associated with such activities, including the OCS. 30 U.S.C. 189 (MLA); 30 U.S.C. 1751 (FOGRMA); 43 U.S.C. 1334(a) (OCSLA).

Public Comment: The States of California and New Mexico opposed this change, arguing it will cause companies to improperly deduct costs that should be considered gathering and is inconsistent with the definition of gathering clarified in conjunction with the rescission of the Deepwater Policy in the 2016 Valuation Rule. These States asserted the 2016 Valuation Rule allowed for a more consistent and reliable application of the regulations.

ONRR Response: Historically, the regulatory framework for gathering and transportation did not recognize the unique technology and development model, higher risk and substantial cost of developing and producing oil and gas in unique environments, like the deepwater OCS. However, by practice from 1999 until the 2016 Valuation Rule, these types of developments were allowed as part of a lessee's transportation deduction.

The commenters are correct that subsea movement of bulk production before the royalty measurement point would be defined, under the 2016 Valuation Rule and this final rule, as gathering. However, in this final rule, pursuant to the Secretary's authority to create rules and definitions for royalty collection purposes and to provide for the expeditious and orderly development of the OCS, ONRR is creating a new regulatory exception to the rules for gathering and transportation in order to provide a deduction for a lessee that carries the higher risk and cost of production in the deepwater OCS.

This change from the 2016 Valuation Rule is being made at this time because the GOM is currently viewed as a mature hydrocarbon province; most of the acreage available for leasing has received multiple seismic surveys, has been offered for lease a number of times, or is under lease. Many of the remaining reserves are located in smaller fields that do not warrant stand-alone development and are unlikely to be developed, unless using subsea completions with tiebacks to existing platforms. The risks and costs of subsea tiebacks are significant, especially when developing a resource within a high pressure and high temperature reservoir, and many of the remaining undiscovered technically recoverable resources in the GOM are within this type of reservoir. The actual discovery, development, and production of oil and natural gas results not from the inventory and data compiled by the government, but from efforts by a diverse set of companies working to identify oil and gas prospects that warrant investment. When examining alternative investment opportunities, companies will consider not only the oil and gas potential of an area, but also the expected costs of development, as compared to alternative investments. The expected profitability of specific projects will be affected by a company's determinations of geologic and economic risk.

Public Comment: A few public interest groups and States noted that in the 2016 Valuation Rule, ONRR explained the Deepwater Policy had served its purpose and is no longer necessary. These commenters argued that ONRR has not sufficiently explained the reason for adopting regulations consistent with the Deepwater Policy.

ONRR Response: When the Deepwater Policy was written in 1999, the Department's intent was to acknowledge that: “new technologies involved in deepwater development were not specifically contemplated” in the regulations at that time. See 63 FR 56217. In the 2016 Valuation Rule, based on the significant deepwater development that had occurred since 1999, and consistently high commodity prices during the years the 2016 Valuation Rule was in development, the Department determined that the Deepwater Policy had served its purpose and was no longer needed. More recently, however, commodity prices have once again significantly changed. Rather than make policy decisions based on commodity prices that are nearly impossible to predict, the Department has reassessed the statutory direction provided clearly in the OCSLA which states that: “the [OCS] is a vital national resource reserve held by the Federal Government for the public, which should be made available for expeditious and orderly development, subject to environmental safeguards, in a manner which is consistent with the maintenance of competition and other national needs,” (see 43 U.S.C. 1332), and has assessed concrete data provided by BOEM and BSEE on permitting activity as well as geologic prospects on the OCS. Consequently, the decision to adopt regulations consistent with the Deepwater Policy has been made for several reasons.

First, from 2010-2014, the average NYMEX oil price was approximately $92/bbl and the average natural gas price was approximately $3.85/MMBTU, while over the last five years (July 2015 to June 2020), the average NYMEX oil price was approximately $51/bbl and the average natural gas price was approximately $2.67/MMBTU.

In addition to the decreases in commodity prices, APDs in the GOM have declined, from an average of 173 in FY 2016 through FY 2019 to 140 in FY 2020. During the same time period, onshore APDs have significantly increased, from an average of 3,548 in FY 2016 through FY 2019 to 6,234 in FY 2020.

Also, when ONRR's 2016 Valuation Rule was promulgated, BOEM had published its 2011 National Assessment of Undiscovered Oil and Gas Resources of the U.S. Outer Continental Shelf. BOEM's 2016 version of the same assessment—which was not available when the 2016 Valuation Rule was promulgated—showed declines in the GOM's economically recoverable oil resources and significant declines in the economically recoverable natural gas resources. Information from BOEM shows the remaining economically and technically recoverable oil and gas resources are all significantly lower than the 2016 estimates. The estimated number of large GOM oil pools has been reduced and the estimated remaining natural gas resources has been further scaled back.

Regarding other input on this topic, in the 2020 Proposed Rule, ONRR sought comments on how its regulations could be revised to address deductions for other remote areas, like Alaska's North Slope. ONRR thanks several commenters for their helpful responses. ONRR did not include provisions specific to remote areas in this final rule but will continue examining the issue.

In this final rule, ONRR retains the provision allowing lessees to deduct certain offshore deepwater gathering costs in its transportation allowance when certain criteria are met. Certain production environments, like the deepwater OCS, require unique technology and carry more risk and costs than onshore environments, resulting in a deepwater OCS development model that is drastically different from onshore counterparts. Additionally, the GOM is currently viewed as a maturing hydrocarbon province; most of the acreage available for leasing has received multiple seismic surveys and has been leased. Many of the remaining reserves are located in smaller fields that do not warrant stand-alone development and will be developed, if at all, using subsea completions with tiebacks to existing platforms. However, the risks and costs of subsea tiebacks are significant, especially when developing a resource within a high pressure and high temperature reservoir. Many of the remaining undiscovered technically recoverable resources in the GOM are within this type of reservoir. See https://www.boem.gov/​sites/​default/​files/​oil-and-gas-energy-program/​Energy-Economics/​Fair-Market-Value/​2018-GOM-International-Comparison.pdf.

The regulations adopting language consistent with the deepwater policy recognize the benefits that offshore production offers the American public in meeting U.S. demand for oil and gas when compared to onshore U.S. production by allowing for a smaller surface footprint with increased well productivity and longer lifespans. See https://www.nap.edu/​read/​25439/​chapter/​4#14. Additionally, deepwater economic limits are expected to be greater than shallow water economic limits because deepwater structures are larger, more complex, further from shore, and almost all structures are manned. This further emphasizes the impact that granting an allowance for deepwater gathering costs, when applied over the life of a facility, offers by increasing net revenue to shift the break-even cost curve and extend the life of the reservoir. See Mark J. Kaiser, in Decommissioning Forecasting and Operating Cost Estimation, 2019.

Offshore oil and gas production is of strategic national importance, as it has accounted for between 15-20 percent of domestic oil production over the past decade and generates billions of dollars in revenue for the U.S. Treasury, various conservation initiatives, and revenue sharing for four Gulf states. Crude oil produced from the OCS is generally of heavier quality and refined in the Gulf Coast for use throughout the country to meet U.S. national energy needs.

ONRR and its predecessor, MMS, recognized the increased risk, cost, and national importance of producing in the deepwater OCS, but historically did not provide a regulatory mechanism for a lessee to deduct appropriate expenses. In 1999, MMS adopted the Deepwater Policy, which granted deductions for the higher costs of moving production in the deepwater OCS while also creating some confusion about the authority of the policy (provided through Departmental memorandum) and its relationship to MMS' valuation regulations. This final rule resolves that confusion by clearly articulating the elements of the Deepwater Policy in the regulatory text.

ONRR's current regulations prohibit a lessee from including gathering costs in its transportation allowance for all Federal oil and gas production. See §§ 1206.110(a) and 1206.152(a). The regulations define gathering as “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.” See 30 CFR 1206.20. Gathering does not end and transportation does not begin before a lessee moves production to the point where it is measured for royalty purposes. See 30 CFR 1206.20 and 1206.171; 53 FR 1184 at 1190-1191 (January 15, 1988); DCOR, ONRR-17-0074-OCS (FE), 2019 WL 6127405. In adopting regulations consistent with the Deepwater Policy, ONRR is amending § 1206.110(a) and § 1206.152(a) to permit a lessee to include, in its transportation allowance, costs incurred in moving offshore production upstream of the royalty measurement point when certain requirements are satisfied. Solely for purposes of this amendment, ONRR is defining central accumulation point to include a single well, a subsea manifold, the last well in a group of wells connected in a series, or a platform extending above the surface of the water, even when prior to the royalty measurement point, and only to the extent all other regulation requirements are met. See, infra., §§ 1206.110(a)(2)(ii) and 1206.152(a)(2)(ii). In all other situations, the central accumulation point remains at or downstream of the royalty measurement point.

The 2020 Proposed Rule included a provision allowing a lessee to request, and ONRR to approve, an application of the deepwater gathering-as-transportation principles in water depths of 200 meters and shallower. ONRR is not adopting the specific provision relating to shallow water gathering in the final rule. While there was such a provision in ONRR's Deepwater Policy in effect from 1999 through 2016, no lessee ever requested an allowance for its shallow water gathering. The fact lessees did not request such relief shows the provision did not effectively incentivize shallow water production, nor did it provide ONRR with a foundation for estimating the economic impact of a shallow water gathering allowance. While ONRR invited public comment on a possible shallow water gathering allowance in the 2020 Proposed Rule, the public comments received also did not provide sufficient information to justify or quantify the impact of such an allowance. ONRR intends to further examine the matter and, if determined to be appropriate, may make shallow water gathering the subject of a future rulemaking.

In this final rule, ONRR removed the proposed language at § 1206.110. In its place, ONRR is adding regulatory text that is largely consistent with the Deepwater Policy except for the shallow water provision. This language is included in the final rule under both §§ 1206.110(a) and 1206.152(a), and references thereto in the definition of “gathering” under § 1206.20.

C. Allowance Limits for Federal Oil and Gas

The MLA requires a lessee to pay royalties at a minimum of 12.5 percent in amount or value of production removed or sold from the leased lands. 30 U.S.C. 226(b)(1)(A). OCSLA requires a royalty of not less than 12.5 percent in amount or value of production saved, removed, or sold from the leases. 43 U.S.C. 1337(a)(1)(A). Although the MLA and OCSLA do not define the term “value,” it is well-established that the Secretary has the authority and considerable discretion to establish the value for royalty purposes of production from Federal oil and gas leases. United States v. Ohio Oil Co., 163 F.2d 633 (10th Cir. 1947); Cont'l Oil Co. v. United States, 184 F.2d 804 (9th Cir. 1950); Marathon Oil Co. v. United States, 604 F. Supp. 1375 (D. Alaska 1985); Amoco Prod. Co., 29 IBLA 234 (1977).

The regulations at 30 CFR part 1206 govern value and, under these regulations, the Secretary allows deductions for transportation and processing. See, e.g., 30 CFR 1206.110, 1206.152, and 1206.159. Secretarial discretion, augmented by case law, supports the Federal lessor sharing in the increased value to the royalty share and costs of the royalty share when a lessee transports production to a market off the lease or processes natural gas into gas plant products.

From the late 1980s to December 30, 2016, ONRR regulations permitted a lessee to request that ONRR allow it to exceed the regulatory limits for transportation allowances (50 percent limit for Federal oil and Federal gas) or processing allowances (662/3 percent limit for Federal gas) (“request to exceed”). Under a different process, a lessee could provide data and documentation to support its request to claim an extraordinary processing allowance (“request to claim”). The 2016 Valuation Rule converted the prior regulatory limits from a soft cap (that is, one that could be exceeded upon application to and approval by ONRR) to a hard cap (one that could not be exceeded) and terminated all currently-existing approvals. At that time, a significant number of companies had received approvals to exceed the transportation and processing allowance limits and ONRR had approved two applications for extraordinary processing allowances.

In the 2020 Proposed Rule, ONRR proposed to remove the hard caps on transportation and processing costs and revert to soft caps, and also to allow a lessee to once again request an extraordinary processing allowance. As before the 2016 Valuation Rule, the lessee would submit to ONRR a request to exceed form (form ONRR-4393) and ONRR would review and approve the request before the lessee could properly report allowances in excess of soft regulatory limits. Similarly, a lessee requesting ONRR approval for an extraordinary processing allowance would submit documentation supporting its claim for ONRR to review and either approve or deny.

Based on comments ONRR received on the 2020 Proposed Rule and the economic analysis in this final rule, ONRR finds that this final rule should retain the hard caps on transportation and processing allowances but reinstate the provision allowing a lessee to request approval for an extraordinary processing allowance. ONRR's economic analysis shows that the financial impact to the Federal lessor, states, and industry arising from the retention of the hard caps is less than $500,000 per year. This represents a significant change from ONRR's economic analysis in the 2020 Proposed Rule, and the benefit to lessees and financial impact to states is considerably less than ONRR originally estimated. In broad terms, the updated royalty impact associated with changing the hard caps to soft caps is insufficient to support making the change when considered in combination with public comments on this issue and, to a lesser extent, the potential increased administrative burden on ONRR and lessees. Section VII, entitled “Procedural Matters,” of this final rule describes a breakdown of the royalty impacts associated with gas transportation, oil transportation, and gas processing. ONRR addresses public comments on the 2020 Proposed Rule in the Public Comments section of this final rule below.

Finally, with respect to reinstating the language allowing a lessee to request an extraordinary processing allowance, ONRR reviewed comments from industry and the State of Wyoming where the facilities that were the subject of the two prior approvals for extraordinary processing allowances were located. Both were supportive of the proposed change. For the reasons outlined in the extraordinary processing allowance section below, this final rule reinstates a lessee's ability to request approval for an extraordinary processing allowance.

Several commenters provided comments on portions of the 2016 Valuation Rule that were beyond the scope of the 2020 Proposed Rule. The comments ranged in support of continuing to value arm's-length percent-of-proceeds contracts as processed gas, to supporting the requirement that transportation and processing pricing factors be reported as allowances, instead of being netted from the gross sales price or value. Other comments related to the 2016 Valuation Rule included objection to the removal of a provision that allowed a lessee to use FERC or state-approved tariffs to calculate transportation rates in non-arm's-length transportation allowances, the removal of line fill costs in the calculation of arm's-length transportation allowances, and the removal of transportation factors in the price of the product. Several commenters recommended that ONRR restore the 1.3 multiplier to the BBB bond rate used to calculate non-arm's-length transportation costs. These commenters also suggested that, in light of Standard and Poor's decision to no longer provide its BBB bond rate free to industry, ONRR select a different rate and publish the rate on ONRR.gov to alleviate confusion and inconsistency when calculating non-arm's-length transportation allowances. Lastly, ONRR received comments asserting that valuing sales of arm's-length unprocessed gas as processed gas, such as in the case of percent-of-index and percent-of-proceeds contracts, is arbitrary. ONRR appreciates the comments but does not address the comments in the sections below because the comments are outside the scope of this rulemaking.

1. Transportation Allowance Limits for Federal Oil and Gas (§§ 1206.110(d)(1) and (2) and 1206.152(e)(1) and (2))

In the 2016 Valuation Rule, ONRR eliminated the regulations that allowed it to approve oil (§ 1206.110) and gas (§ 1206.152) transportation allowances in excess of 50 percent of the value of a lessee's production.

In the 2020 Proposed Rule, ONRR proposed to revert to the historical practice of treating the 50 percent cap as a soft cap on oil and gas transportation costs. As discussed in the background above, ONRR retains the hard caps from the 2016 Valuation Rule in this final rule.

Comments on the Proposed Amendment

Public Comment: Several commenters supported ONRR's authority to approve transportation allowances in excess of the 50 percent allowance cap. These commenters stated that the option to request approval to exceed the 50 percent cap is necessary because it allows a lessee to deduct its actual, reasonable, and necessary transportation costs, even if those costs exceed 50 percent, which is especially important in a low commodity price environment.

ONRR Response: ONRR agrees that the oil and gas markets changed between the adoption of the 2016 Valuation Rule and the 2020 Proposed Rule. ONRR understands that market volatility and the global pandemic have adversely affected the oil and gas industry. However, it may be counterproductive to make regulatory changes based on market volatility because frequent regulatory changes may decrease early certainty to lessees and make Federal leases less attractive to current and potential lessees. Retaining the hard caps on allowances supports a fair return to the public on their non-renewable natural resources.

Public Comment: A commenter suggested that ONRR approve exceptions to the 50 percent limit prospectively for a two-year or three-year period to reduce the administrative burden associated with applying for and approving or denying these requests. Another commenter stated that ONRR could offset the administrative burden associated with reviewing and approving requests to exceed the transportation allowance limits by approving allowances for more than a single year at a time.

ONRR Response: ONRR appreciates comments and suggestions related to reducing administrative burden. ONRR is retaining the hard caps in this final rule, which eliminates any associated increase in administrative burdens.

Public Comment: A commenter suggested that ONRR modify the allowance to include a 120-day time limit for ONRR to respond to a request and that ONRR provide a detailed explanation if ONRR denies a request. The commenter argues these actions provide certainty to the lessee regarding their allowance calculations.

ONRR Response: ONRR appreciates these suggestions. However, since ONRR is retaining the hard caps rather than removing them in this final rule, there will not be any application to which a 120-day mandate could apply, nor will there be a need to provide a detailed explanation for a denial.

Public Comment: A commenter recommended that ONRR reinstate any approval to exceed the 50 percent transportation allowance limits for oil and gas that was in place prior to the reinstatement of the 2016 Valuation Rule.

ONRR Response: The 2016 Valuation Rule terminated all approvals to exceed the transportation allowance limits prior to its January 1, 2017, effective date. ONRR has no authority to grant future applications retroactively, and is retaining the hard caps in this final rule.

Public Comment: A commenter asserted that ONRR should eliminate transportation allowances entirely because they amount to an uncapped subsidy of the oil, gas, and coal industries.

ONRR Response: Transportation allowances are a well-established standard supported by case law and precedent. See, e.g. 30 CFR 1206.110 and 1206.152 and United States v. Gen. Petroleum Corp. of California, 73 F. Supp. 225, 262 (S.D. Cal. 1946). This final rule retains the hard caps on transportation and processing allowances.

Public Comment: A commenter asserted that ONRR should eliminate allowances entirely because providing a lessee the option to deduct transportation or processing allowances in excess of the caps disincentivizes lessees to reduce their costs. Another commenter asserted that allowing lessees to request to exceed the limits does not incentivize the lessee to lower operational costs and negatively impacts royalty payments, which in some instances support local schools.

ONRR Response: Transportation and processing allowances are intended to benefit both a lessee and the Federal lessor because of typically higher market values found off the lease, or from recovering NGLs. Courts have upheld the use of allowances to calculate the value of Federal oil and gas production for royalty purposes. See United States v. Gen. Petroleum Corp. of California, 73 F. Supp. 225, 262 (S.D. Cal. 1946) (stating “It has been held that if there is no open market in the place where an article ordinarily would be sold, the market value of such article in the nearest open market less cost of transportation to such open market becomes the market value of the article in question.”), aff'd sub nom. Cont'l Oil Co. v. United States, 184 F.2d 802 (9th Cir. 1950).

Also, a lessee already has an incentive to minimize its transportation and processing costs. Typically, the Federal Government's royalty share of production is 121/2 or 162/3 percent. The lessee retains the remaining 871/2 or 831/3 percent respectively, and has every incentive to minimize the transportation and processing costs borne by its sizable share. The Federal Government benefits from the lessee's incentive to be cost-conscious on its greater share. ONRR does not expect limiting the transportation and processing allowances on a smaller share of production to change lessee behavior in incurring transportation and processing expenses borne by the lessee's greater share. In this final rule, ONRR retains the hard caps on allowances, consistent with the commenter's request. ONRR acknowledges that market conditions and the global pandemic have negatively impacted many budgets, including for schools.

Public Comment: A commenter asserted that ONRR did not provide justification for incentivizing production in low-quality reservoirs, which the commenter suggested may cause harmful environmental externalities. A second commenter suggested ONRR did not address any environmental consequences associated with reinstating the requests to exceed the transportation limit. Another commenter asserted that ONRR did not fully perform its due diligence to ensure consistency with multiple use management laws.

ONRR Response: Allowing a lessee to request to exceed the hard caps may not provide sufficient economic incentive for that lessee to continue producing or seek additional production from Federal lands. The Federal Government's royalty share of production is typically 121/2 or 162/3 percent; the lessee's share of production is typically the remaining 871/2 or 831/3 percent. Small changes in the calculation of the value of the Federal Government's 121/2 or 162/3 percent share become even smaller when spread over the value of the lessee's 871/2 or 831/3 percent share, making it difficult for the Federal Government to effectively incentivize industry action. While allowing a lessee to request to exceed the hard caps could provide some economic incentive to the lessee, such action would also increase the lessee's administrative cost burden. See Section V for ONRR's economic analysis. ONRR has determined that, on balance, removing the hard caps is not warranted, and is retaining the hard caps in its regulations.

ONRR addresses public comments about environmental considerations in the introduction to this rule. As to the comment regarding consistency with multiple use management laws, the commenter failed to specify which multiple use management laws ONRR failed to consider. While ONRR cannot respond directly to this comment, it has addressed the specific acts raised by other commenters in the introduction.

Oil: ONRR retained the current language in § 1206.110(d)(1) and (2), which limits transportation allowances to 50 percent of the value of oil transported. Despite the current market volatility, ONRR believes that it is in the public interest to retain the hard cap.

Gas: ONRR retained the current language in § 1206.152(e)(1) and (2), which limits transportation allowances to 50 percent of the value of unprocessed gas, residue gas, or gas plant products transported. Despite the current market volatility, ONRR believes that it is in the public interest to retain the hard cap.

2. Processing Allowance Limits for Federal Gas (§ 1206.159(c)(2) and (3))

In the 2016 Valuation Rule, ONRR eliminated the regulation allowing it to approve gas processing allowances in excess of 662/3 percent of the value of a lessee's gas production.

In the 2020 Proposed Rule, ONRR proposed to revert to historical practices by treating the regulatory limit as a “soft cap” on gas processing costs (662/3 percent regulatory limit). As discussed in the background above, ONRR retains the hard caps from the 2016 Valuation Rule in this final rule.

Comments on the Proposed Amendment

Public Comment: Several commenters supported the 2020 Proposed Rule's provision for ONRR to approve requests to exceed the 662/3 percent limit on processing allowances. The commenters stated that the right to request approval to exceed the 662/3 percent cap needs to be reinstated because its removal denied lessees the ability to deduct all of their actual, reasonable, and necessary processing costs when those costs exceed 662/3 percent. The commenters asserted that this is especially true when the physical make-up of the gas necessitates complex plant designs which result in higher processing costs. Last, a commenter took issue with ONRR terminating any approval that it previously issued for a lessee to exceed the 662/3 percent limitation.

ONRR Response: Although the oil and gas market clearly changed between the drafting of the 2016 Valuation Rule and the 2020 Proposed Rule, and ONRR understands that the oil and gas industry, like many industries, has been adversely affected by market volatility and the global pandemic, ONRR's regulations are designed to continue to function during uncommon or unavoidable circumstances affecting costs and value. ONRR believes retaining the hard caps on allowances supports a fair return to the public on non-renewable natural resources.

Public Comment: A commenter suggested ONRR reduce administrative costs arising from processing the requests to exceed by approving the exception for periods of two or more years for lessees with contracts that have been reviewed and which are consistently over the limits.

ONRR Response: ONRR appreciates the suggestion. Because ONRR is retaining the hard caps in this final rule, there are no associated administrative costs.

Public Comment: A commenter suggested that ONRR modify the allowance to include a 120-day mandate for ONRR to respond to a request and that ONRR provide a detailed explanation if ONRR denies a request.

ONRR Response: ONRR appreciates the suggestions and responded to a parallel suggestion in the discussion of transportation costs, above. That response is applicable here, as well.

Public Comment: A commenter stated they oppose ONRR's approval to exceed the 662/3 percent cap on processing allowances and allowances in general. Another commenter stated that allowing a lessee to request to exceed the 662/3 percent limitation on processing allowances is a savings for industry at the expense of taxpayers due to a reduction in royalty payments.

ONRR Response: The comments regarding the 662/3 percent processing allowance mirror the comments that ONRR received for the 50 percent limitation on transportation allowances for oil. Please refer to ONRR's responses regarding the 50 percent transportation cap.

ONRR retained the current language in § 1206.159(c)(2) and (3), which limits processing allowances to 662/3 percent of the value of the gas plant products recovered. Despite the current volatile market conditions, ONRR believes that it is in the public interest to retain the hard cap on processing allowances.

3. Extraordinary Processing Allowances for Federal Gas (§ 1206.159(c)(4))

The 2016 Valuation Rule removed the provision that was in place between March 1, 1988 (53 FR 1230, January 15, 1988), and December 31, 2016 (81 FR 43338, July 1, 2016), under § 1206.158(d)(2), which allowed a lessee to request an extraordinary processing allowance. Under the prior § 1206.158(d)(2), on application to and with ONRR's approval, a lessee could deduct its actual and reasonable processing costs up to 99 percent of the value of the gas plant products extracted and up to 50 percent of the value of the residue gas. See 81 FR 43353, July 1, 2016. For ONRR's approval, a lessee's application must have demonstrated that the gas stream, plant design, and/or unit costs were extraordinary, unusual, or unconventional relative to standard industry conditions and practice. See e.g. Amoco Prod. Co. v. Baca, 300 F. Supp. 2d 1, 13-14 (D.D.C. 2003); see also Exxon Corp., 118 IBLA 221, n. 7 (1991). In justifying the elimination of extraordinary processing allowances, ONRR stated in the 2016 Valuation Rule that “the markets and the technology have changed sufficiently such that this provision and these approvals are no longer necessary.” See 81 FR 43353 (July 1, 2016).

The 2016 Valuation Rule terminated the two existing ONRR-approved extraordinary processing allowance claims for lessees processing gas at two facilities in Wyoming. In response to the 2020 Proposed Rule, the Governor of Wyoming and the members of Wyoming's Congressional delegation submitted comments stating that this allowance is essential for two major gas-processing facilities in Wyoming. The commenter further explained that this process is challenging and expensive. According to the commenter, these gas processing operations provide an important source of valuable gasses, including helium, which is relied upon by consumers in Wyoming and the rest of the country. The commenters representing Wyoming argued that extraordinary processing allowances are warranted because certain Wyoming gas processing facilities face a serious competitive disadvantage without them, which may cause those plants to be prematurely retired.

Upon receipt of those comments, ONRR reexamined the facts and the assertion in the 2016 Valuation Rule that there were technological advances that rendered the extraordinary processing allowances unnecessary. While gas markets have indisputably changed since MMS added the extraordinary processing allowance provision to the regulations (53 FR 1230, January 15, 1988), and gas processing technologies have improved overall, the technology necessary to process these two gas streams, characterized by high concentrations of nitrogen, carbon dioxide, hydrogen sulfide, methane, and almost no recoverable NGLs, see Exxon Corp., 118 IBLA 221, n. 7 (1991), remains substantially the same. See, e.g., Eow, J.S. (2002), Recovery of sulfur from sour acid gas: A review of the technology. Environ. Prog., 21: 143-162, https://doi.org/​10.1002/​ep.670210312;​; Reviews in Chemical Engineering, Volume 29, Issue 6, Pages 449-470, eISSN 2191-0235, ISSN 0167-8299, DOI: https://doi.org/​10.1515/​revce-2013-0017. Therefore, reinstating the provision that allowed a lessee to request approval to take an extraordinary processing allowance is appropriate, as the technology to process these unique gas streams has not changed, despite technological advances in processing relevant to many other areas and types of gas streams.

Further, as was noted by the Governor of Wyoming and Wyoming's Congressional delegation, one of these unique gas streams contains recoverable quantities of helium, an element that is vital to the Nation's security and economic prosperity. See Final List of Critical Minerals 2018, https://www.usgs.gov/​news/​interior-releases-2018-s-final-list-35-minerals-deemed-critical-us-national-security-and,, published May 18, 2018 (83 FR 23295). Helium production is governed by the Helium Stewardship Act of 2013, Public Law 113-40, codified at 50 U.S.C. 167-167q, and is administered by the BLM. See https://www.blm.gov/​programs/​energy-and-minerals/​helium. Accordingly, the U.S. has important economic and national security interests in ensuring the continuation of a reliable supply of helium, including that recovered from unique gas streams requiring costly equipment to remove carbon dioxide and hydrogen sulfide before helium can be extracted. See, e.g., https://www.nap.edu/​read/​9860/​chapter/​7#41. In instances where a lessee might not otherwise choose to produce a gas resource containing helium, allowing a lessee to apply for an extraordinary processing allowance approval for the natural gas portion of their production stream, may lower natural gas production costs and incentivize new or continued production of helium. However, the extraordinary processing allowance does not apply to helium and to obtain a reduction in helium rates, the helium extractor would need to request this separately with the BLM Amarillo Federal Leased Lands Team.

In light of the foregoing, and after careful consideration of the public comments discussed in more detail below, this final rule reverts to ONRR's long-standing historical practice and reinstates the provision that was in place between March 1, 1988 (53 FR 1230, January 15, 1988), and December 31, 2016 (81 FR 43338, July 1, 2016), under 30 CFR 1206.158(d)(2)(i) to the updated § 1206.159(c)(4). Adoption of this amendment will allow a lessee to apply to ONRR for approval to claim an extraordinary processing allowance.

Comments on the Proposed Amendment

Public Comment: Several commenters stated that ONRR should restore the option for lessees to request approval for extraordinary processing allowances. The commenters argued that ONRR's prior limited approvals were for gas streams with unique gas compositions that were processed at gas plants with complex plant designs and extremely high unit costs. The commenters stated that the lessees with those approvals made investment decisions based on the approvals. Without the ability to deduct additional, extraordinary processing costs against the value of the residue gas recovered, the economic viability of lease operations was questionable. These commenters further asserted that ONRR was incorrect in the 2016 Valuation Rule when it stated that technological advancements since the 1990s meant that these approvals were no longer necessary.

ONRR Response: Reinstating this provision may remove the potential disincentive for a lessee to develop Federal lands disadvantaged by gas streams requiring complex and costly facilities, which, like the composition of the gas streams, are unique, extraordinary, or unconventional. Receiving an approval under this provision may also provide a lessee an incentive to continue producing through uncommon or unavoidable circumstances affecting costs and value. As already discussed, ONRR concedes that, despite other technological advances relevant to processing, the technology necessary to process unique gas streams such as that used at the two Wyoming facilities discussed above has not changed appreciably since the prior approvals were given in the 1990s.

Public Comment: Several commenters requested that ONRR reinstate the extraordinary processing allowance approvals terminated by the 2016 Valuation Rule.

ONRR Response: The 2016 Valuation Rule terminated the prior approvals that ONRR granted before January 1, 2017. 81 FR 43338 (July 1, 2016). This final rule will add language allowing a lessee to again request an approval. However, ONRR will apply this final rule prospectively, beginning with its effective date. ONRR cannot reinstate the two extraordinary processing allowance approvals that the 2016 Valuation Rule terminated, nor can ONRR grant such allowances for the period between January 1, 2017, and the effective date of this final rule. Rather, each of the lessees will need to reapply to ONRR for approval. And, as before the 2016 Valuation Rule, ONRR may only approve a lessee's request after reviewing the lessee's documentation for adequacy, reasonableness, and accuracy. ONRR anticipates that it will again receive few requests and will rarely grant approval under this provision, as was the case when the language was in place between March 1, 1988, and December 31, 2016.

Public Comment: A commenter stated that ONRR should not restore the ability for a lessee to request an extraordinary processing allowance approval because the 2016 Valuation Rule ensured a fair return to the public.

ONRR Response: ONRR is committed to ensuring a fair return to the American public for oil and gas produced from Federal lands. Allowing a lessee to deduct actual, reasonable, extraordinary post-production processing costs is part of ensuring a fair return. Prior to the 2016 Valuation Rule, just two approvals for extraordinary processing allowances were in effect. Both were for leases in Wyoming. The State of Wyoming receives about half of the royalties reported and paid for Federal leases in Wyoming, and shares in any reduction in those royalties, including reductions occasioned by an extraordinary processing allowance. Nonetheless, the comments submitted by the Governor of Wyoming and Wyoming's Congressional delegation urge ONRR to adopt regulations restoring a lessee's ability to apply for extraordinary processing allowances, and state that the positive overall economic impact to Wyoming of continuing operation of the Federal leases that historically benefitted from extraordinary processing allowances outweighs any reduction in royalties Wyoming receives. Further, in more than 30 years, ONRR has received fewer than 10 requests to approve extraordinary processing allowances (and approved only two), which indicates that such requests are very rare.

Public Comment: One commenter stated that, if there is a potential danger to local communities if extraction of high sulfur gas streams goes wrong, the company should pay the taxpayers a fair share (and no less) for the resources.

ONRR Response: As discussed above, allowing a lessee to deduct actual, reasonable post-production processing costs is part of ensuring a fair return for the right to produce Federal resources. And “if extraction of high sulfur gas streams goes wrong,” other laws potentially hold the responsible party liable for personal, property, and environmental damage. ONRR's regulations governing the method of calculating the amount of a lessee's royalty payment were never intended to compensate for accidental personal, property, or environmental damages should someone or something suffer injury or damage as a result of a failure associated with the processing of a natural resource. ONRR further addressed public comments regarding environmental concerns in the General Comments section in this rule's introduction.

ONRR appreciates the comments supporting, seeking the modification to, or opposing the proposed amendment to allow a lessee to apply to ONRR for approval to claim an extraordinary processing allowance. After careful consideration, and for the reasons explained in the introduction above, this final rule will adopt the proposed amendment to § 1206.159(c)(4). In the 2020 Proposed Rule, this paragraph was designated as § 1206.159(c)(4). To account for other changes to § 1206.159, paragraph (c)(4) is redesignated as § 1206.159(c)(5) in this final rule.

D. The Default Provision for Federal Oil, Gas, and Coal and Indian Coal

The 2016 Valuation Rule introduced a provision on how ONRR will exercise the Secretary's authority to establish royalty value when typical valuation methods are unavailable, unreliable, or unworkable. This provision, which appears in several places in the 2016 Valuation Rule, is generally referred to as “the default provision.” ONRR's intent in 2016 was to increase clarity, consistency, and predictability on when and how ONRR would exercise the Secretary's discretion to determine royalty value when other royalty valuation methods fail.

The 2020 Proposed Rule sought to amend 30 CFR part 1206 to eliminate the default provision from four sections and a number of references thereto. The amendment, if adopted, would effectively revert ONRR's practices to those in place prior to publication of the 2016 Valuation Rule. ONRR premised the proposed change on E.O.s 13783 and 13795 and the policies reflected in those directives, and on ONRR's consideration of continuing concerns from regulated entities with respect to how ONRR would apply the default provision, as most recently expressed by industry members in the Petitioners' Joint Opening Brief (ECF No. 89), filed December 4, 2020, in API v. U.S. Dept. of the Interior, et al, Case No. 19-cv-120-S, U.S. District Court for the District of Wyoming.

In the 2016 Valuation Rule and 2020 Proposed Rule, ONRR determined that inserting and subsequently removing the default provision will not affect royalty values because neither the default provision nor its absence changes ONRR's goal, which is to determine the value of the produced commodity for royalty purposes based on the best or a reasonable measure of market value. Further, removing the default provision does not affect ONRR's ability to establish a royalty value in those infrequent instances where a typical valuation method is unavailable, unreliable, or unworkable because the Secretary's discretion to establish a royalty value does not derive from ONRR's regulations. See, e.g., 17 U.S.C. 1751 and BOEM OCS lease form, section 6(b)(“The value of production for purposes of computing royalty shall be the reasonable value of the production as determined by the Lessor.”).

In this final rule, ONRR amends 30 CFR part 1206 to eliminate the default provision found in §§ 1206.105, 1206.144, 1206.254, and 1206.454, and a number of references thereto, effectively returning ONRR's practices to those that were in place for decades prior to the adoption of the 2016 Valuation Rule.

Comments on the Proposed Amendments

Public Comment: Several commenters supported the default provision's elimination because the commenters opine that the default provision introduces ambiguity as to who within ONRR has the authority to invoke the default provision. There was also concern that the default provision would be applied inconsistently. Further, commenters expressed concerns about the lack of criteria for determining “reasonable” sales prices and transportation costs, which could theoretically result in a lessee not being allowed to value royalties based upon arm's-length sales contracts or deduct all reasonable, actual transportation, and processing costs. These commenters assert that the default provision is overly broad and open-ended, allowing ONRR to determine the value of production or the amount of allowance in instances where a lessee cannot provide documentation requested by ONRR the lessee asserts it has no legal or practical ability to obtain. These commenters support regulations with more certainty in valuation, because they lead to less risk, efficiency in reporting and audits, and improved planning for ONRR and lessees.

ONRR Response: Prior to the adoption of the 2016 Valuation Rule, ONRR successfully performed compliance activities and, when appropriate, exercised Secretarial discretion, to establish royalty values, even in the absence of an express default provision. Considering the recent direction given by E.O.s 13783 and 13795, which promote domestic energy production and reduce regulatory burden, together with the confusion around when and how the default provision would be applied, ONRR has reevaluated whether the default provision is necessary. ONRR intended the provision to be used in situations where determination of value was unclear, and not to determine the value of production in cases where reasonable, actual transportation and processing costs are well supported. ONRR agrees that the default provision is unnecessary. Further, the default provision invites litigation over what are the “lowest reasonable measures of market price,” “highest reasonable measure of transportation costs,” “highest reasonable measure of processing costs,” and “highest reasonable measure of washing allowances.” See, e.g., 30 CFR 1206.104(c)(2), 1206.110(f)(2), 1206.143(c)(2), 1206.153(g)(2), 1206.159(e)(2), 1206.253(c)(2) 1206.260(g)(2), 1206.267(d)(2). Also, arguably, the default provision allows a lessee in certain circumstances to report and pay royalties based on sales prices up to ten percent less than the lowest reasonable measure of market price; transportation costs up to ten percent higher than the highest reasonable measure of transportation costs; processing costs up to ten percent higher than the highest reasonable measure of processing costs; and washing allowances up to ten percent higher than the highest reasonable measure of washing allowances. See, e.g., 30 CFR 1206.104(c)(2), 1206.110(f)(2), 1206.143(c)(2), 1206.153(g)(2), 1206.159(e)(2), 1206.253(c)(2), 1206.260(g)(2), 1206.267(d)(2). The default provision does not best protect the United States against inadequate royalty payments and is being removed from ONRR regulations by this final rule.

Public Comment: Some commenters expressed concern over reporting errors causing ONRR to “penalize” a lessee and impose an entirely different (and presumable higher) valuation for royalty purposes through the application of the default provision without first allowing the lessee to correct its reporting to conform to the applicable regulations.

ONRR Response: Where royalty value cannot be determined under the regulations, such as instances of breach of a lessee's duty to market, ONRR will use statutory authority to determine Federal oil and gas royalty value in accordance with the lease terms, statutes, and regulations in the same manner as ONRR did prior to adoption of the 2016 Valuation Rule.

Public Comment: Many commenters expressed concerns over the ten percent variance, arguing that it does not take into account arm's-length sales and transportation contracts, particularly where the lack of fully-developed transportation and processing infrastructure could vary by more than 10 percent from “reasonable measures.” The commenters also stated that the ten percent test is too broadly written and could be triggered by transactions that have the same economic effect but are structured differently.

ONRR Response: ONRR is to capture a reasonable measure of fair market value for production. See, e.g., 43 U.S.C. 1344(a)(4). Fair market value is influenced by sales prices, transportation costs, processing costs, and the costs of placing production in marketable condition. The ten percent variance is problematic, but for reasons other than expressed in these public comments. The ten percent variance is from the lowest reasonable sales price and the highest reasonable transportation and processing costs. For this reason, the default provision is in conflict with ONRR's mandate to capture full, reasonable fair market value, not up to ten percent less.

Public Comment: Several commenters suggested that, if ONRR elects to retain the default provision, it should be narrowly tailored to address the most blatant of reporting discrepancies, and defined in such a way that a lessee is not left to guess if and when ONRR will decide to insert itself into regular business transactions and what the results of such intervention might be. One commenter further asserted that ONRR should indicate when its judgment will or will not be substituted, how such discretion would or would not be wielded, and what factors would or would not be used. The commenters added that ONRR should also clarify how the provision would establish pricing for misconduct, breach of duty to market, or instances where ONRR cannot verify value.

ONRR Response: ONRR appreciates the suggestions to tailor and further define when and how it would use the default provision. However, ONRR believes that the default provision has created uncertainty and unintended consequences in the valuation of production, as discussed above. Therefore, this final rule eliminates the default provision.

Public Comment: One commenter stated that ONRR should give proper notice to a payor so that additional information or justification as to the valuation could be provided first. The commenter further asserted that the default provision should not be triggered by simple or inadvertent reporting errors, nor by some arbitrary percentage below the lowest “reasonable” measure of value in arm's-length situations, or above the highest “reasonable” measure of transportation or processing cost as under the 2016 Valuation Rule.

ONRR Response: In this final rule, ONRR eliminates the default provision contained in the 2016 Valuation Rule because the default provision created uncertainty and a regulatory burden, as well as unintended consequences adverse to the lessor. The final rule reverts to historical practices under which MMS and ONRR successfully performed compliance activities. Where appropriate, ONRR will exercise Secretarial discretion to establish royalty values in the absence of the default provision. ONRR believes that it unintentionally increased uncertainty due to lessees' perception that ONRR might apply the default provision in place of accurate lessee reporting, thereby creating a regulatory burden for lessees.

Public Comment: One commenter suggested that a lessee should be allowed to fix a mis-reported value to conform to ONRR's regulations rather than the agency unilaterally setting its preferred value.

ONRR Response: In the future, ONRR may request more information and/or specific proposals regarding ways to address reporting errors. Lessees are currently required to correct any reporting errors within 30 days of the date the lessee learns of the error. See 30 CFR 1210.30.

Public Comment: A commenter suggested that because several phrases relating to the default provision were not addressed by the 2020 Proposed Rule that ONRR may still exercise seemingly unfettered discretion to review a lessee's royalty valuation that is based on bona fide arm's-length contract. This commenter requested that ONRR issue a separate rulemaking to target the remaining default provisions to meet the intent of the 2020 Proposed Rule.

ONRR Response: ONRR appreciates the suggestions to address the other phrases that were not the subject of the 2020 Proposed Rule. However, it is outside of the scope of this rulemaking.

Public Comment: One commenter stated that ONRR did not provide a reasoned explanation for removing the default provision, and thus creates uncertainty surrounding the valuation of oil, gas, and coal. The commenter went on to say that removal of this provision will reintroduce uncertainty by leaving a lessee unsure when ONRR will exercise the Secretary's discretion. The commenter also stated that ONRR fails to recognize the lessee's right to appeal any order issued by or on behalf of the Secretary regarding royalty valuation, even though those appeals create an important check on the Secretary's power. Further, this commenter argued that ONRR did not consider alternatives and chose to repeal the default provision without providing justification other than broad executive policies. Accordingly, the commenter concluded that removing the default provision is arbitrary and capricious.

ONRR Response: ONRR disagrees with the suggestion that the default provision is necessary or that its removal will cause uncertainty. ONRR used its delegated Secretarial discretion, lease terms, statutes, and regulations to determine Federal oil and gas royalties prior to adoption of the 2016 Valuation Rule, and will continue to do so after the default provision's removal from ONRR regulations. The default provision created uncertainty and unintended consequences as discussed above, and the regulations did not best define the situations when ONRR should apply a default provision.

Public Comment: Another commenter stated that the default provision should be retained because its removal would undermine ONRR's ability to ensure proper royalty collection.

ONRR Response: ONRR disagrees that the default provision is necessary or that its removal will adversely affect its ability to ensure proper royalty collection. In fact, as discussed above, the default provision may have restricted ONRR's ability to use Secretarial discretion when a lessee reports royalties significantly lower than the lowest reasonable value.

ONRR appreciates the commenters supporting, seeking the modification to, and opposing the proposed amendment to §§ 1206.101, 1206.102, 1206.104, 1206.105, 1206.110, 1206.141, 1206.142, 1206.143, 1206.144, 1206.152, 1206.160, 1206.252, 1206.253, 1206.254, 1206.256, 1206.260, 1206.267, 1206.451, 1206.452, 1206.453, 1206.454, 1206.460, 1206.461, 1206.467, and 1206.468. For the reasons explained in the 2020 Proposed Rule and this final rule, this final rule will adopt the proposed amendments to §§ 1206.101, 1206.102, 1206.104, 1206.105, 1206.110, 1206.141, 1206.142, 1206.143, 1206.144, 1206.152, 1206.160, 1206.252, 1206.253, 1206.254, 1206.256, 1206.260, 1206.267, 1206.451, 1206.452, 1206.453, 1206.454, 1206.460, 1206.461, 1206.467, and 1206.468 in full.

E. “Misconduct” Definition for Federal Oil, Gas, and Coal and Indian Coal

In the 2016 Valuation Rule, ONRR added a definition of the term “misconduct” under § 1206.20 to mean: “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.” In the preamble to the 2016 Valuation Rule, ONRR explained that it added the misconduct definition in conjunction with the adoption of the “default” provision. “This new definition will apply to—and in conjunction with the—default provision. Misconduct, in this subpart, is different than—and in addition to—any violations subject to civil penalties under . . . FOGRMA . . . . Behavior that constitutes misconduct under part 1206 does not need to be willful, knowing, voluntary, or intentional. This is a valuation mechanism, not an enforcement tool.”

ONRR is eliminating the default provision from its regulations in this final rule. Accordingly, the definition of “misconduct” added to ONRR regulations in conjunction with and for the operation of the default provision is also being eliminated.

Comments on the Proposed Amendment

Public Comment: Some commenters stated that the 2016 Valuation Rule generated uncertainty for royalty reporters by creating a broad definition of “misconduct.” The commenters argued this definition could be misapplied, leading to the imposition of civil penalties under the 2016 Civil Penalty Rule. The commenters explained that they interpreted the 2016 Valuation Rule's definition of “misconduct” to allow ONRR to penalize a lessee under the “default provision” for reporting an incorrect product code, sales type, or other non-value-based field on a royalty report (form ONRR-2014), without an opportunity to correct the error. Additionally, penalizing a lessee for non-value-based errors is not reasonable, the commenters said, because there are many fields on form ONRR-2014 that do not affect ONRR's ability to ensure that it has collected every dollar due. Thus, these commenters support the 2020 Proposed Valuation Rule's elimination of the definition of “misconduct.”

One commenter stated that the definition of misconduct was expansive enough to capture even inadvertent paperwork errors. Furthermore, the commenter stated that the 2016 definition of misconduct duplicates existing regulations to the extent that a lessee is required to correct reporting errors under § 1206.30.

ONRR Response: The definition of “misconduct” in 30 CFR 1206.20 is no longer needed because the default provision is being eliminated by this final rule.

Public Comment: Some commenters suggested that ONRR amend the definition of “misconduct” in § 1206.20 by including the words “intentional” or “knowing or willful” before “misconduct” where it appears in 30 CFR part 1206. Alternatively, the commenters suggested, ONRR could insert a provision such as “ONRR will not allege misconduct absent some intent by the lessee to lower its royalty payments to the government beyond what is reasonable” to ensure that, for example, the failure of the lessee to conform to formal or informal agency guidance does not establish misconduct, while good faith efforts to comply constitutes mitigating circumstances and should not result in the issuance of a penalty. Another commenter said that intentional conduct aimed at reducing royalties owed should be an aggravating factor, while innocent reporting mistakes, a favorable compliance record, and adherence to ONRR guidance should be mitigating factors.

ONRR Response: ONRR defined “misconduct” in the 2016 Valuation Rule to clarify when ONRR would exercise the Secretary's discretion to determine value of production under the default provision. Because the default provision is being eliminated by this final rule, the related definition of “misconduct” is also being eliminated, and thus, it is unnecessary to amend, in any manner, the definition of misconduct.

Public Comment: One commenter stated that ONRR did not provide a reasoned or substantive explanation for proposing in the 2020 Proposed Rule to remove the misconduct definition. The commenter asserted that ONRR's proposal unnecessarily reintroduces uncertainty to the application of the valuation regulations. Additionally, the commenter opined that ONRR directly contradicted its earlier position on an issue without properly justifying its decision. This commenter suggested that before removing the definition, ONRR must first provide a reasoned explanation for the change. Accordingly, the commenter stated that removing the definition for the term “misconduct” is arbitrary and capricious.

ONRR Response: This final rule provides ONRR's reasoned explanation to remove the definition of “misconduct.” In summary, this rule removes the definition because: (1) ONRR originally added the definition in conjunction with, and for the operation of, the default provision that this rule also removes; (2) in light of this rule's objectives, ONRR gives greater weight to comments that the definition increased uncertainty and undue burdens in the regulated community; and (3) ONRR maintains and has not eroded its ability to ensure and compel accurate reporting including, for example, the requirement under § 1210.30 for a lessee to “submit accurate, complete, and timely information,” regardless of whether those errors were caused by misconduct.

ONRR appreciates the comments supporting, seeking the modification to, and opposing the proposed amendment. After careful consideration, and for the reasons explained above, ONRR is adopting the proposed amendment to remove the definition of “misconduct” in § 1206.20 as part of this final rule.

F. Contract Signature Requirement for Federal Oil, Gas, and Coal and Indian Coal

The 2016 Valuation Rule required a lessee or a lessee's “affiliate [to] make all contracts, contract revisions, or amendments in writing, and all parties to the contract must sign the contract, contract revisions, or amendments” for all valuation methods, including gross proceeds and index-based options, to verify the correctness of royalty reports and payments. See §§ 1206.104(g)(1); 1206.143(g)(1); 1206.253(g)(1); and 1206.453(g)(1) (2016 Valuation Rule). If a written contract was not signed by all parties to the contract, the 2016 Valuation Rule directs that ONRR use the default provision to determine royalty value.

In the 2020 Proposed Rule, ONRR seeks to eliminate the requirement that a lessee create and maintain contracts signed by all parties where the lessee would not do so in the normal course of business, except as required by 30 CFR 1207.5, which states that a lessee must place in written form and retain any oral sales arrangement negotiated by the lessee. The proposed amendment also seeks to create greater consistency with ONRR's definition of contract, which includes oral contracts and written contracts that are not signed by all parties. See 30 CFR 1206.20.

Even with the amendments adopted in this final rule, ONRR will still be able to evaluate a lessee's course of performance under all contracts, oral and written, signed and unsigned, consistent with ONRR's historical agency practice. ONRR has long been able to request copies of a lessee's sales contracts and all agreements, other contracts, and other documents relevant to the valuation of production, including any written or electronic evidence of transportation contracts, processing contracts, and contracts for services to place production in marketable condition. See 30 CFR 1207.5 (“Copies of all sales contracts . . . and copies of all agreements, other contracts, or other documents which are relevant to the valuation of production are to be maintained by the lessee and made available upon request . . . to . . . ONRR . . . .”). Given this broad, long-standing authority to request all lessee's records that bear on royalty value, in the 2020 Proposed Rule ONRR sought public comment on whether the new requirements imposed by the 2016 Valuation Rule should be retained.

ONRR recognizes that contracts may be valid and enforceable, as a matter of law, despite the absence of writing or signatures. See the definition of “contract” in 30 CFR 1206.20. In this final rule, ONRR seeks to resolve the ambiguity that exists between its definition of contract—which recognizes the validity of oral agreements and of written agreements that have not been signed by all parties—and the 2016 Valuation Rule's imposition of a requirement for every contract to be in writing and signed by all parties, despite a lessee's normal business practices to the contrary. ONRR has determined that the 2016 Valuation Rule's new requirement does not align with contract law, that industry operates without signed documents as a matter of course without issue, and that ONRR can use other methods to determine the terms of an oral contract or a written contract that is not signed by all parties.

Comments on the Proposed Amendment

Public Comment: Several industry commenters supported removal of the contract signature requirement, stating that real world practices do not always require written contracts and that there is no need for signatures to affirm a contractual agreement. Additionally, commenters noted that the 2016 Valuation Rule inadvertently contradicted the definition of “contract” in the regulation itself, which, at § 1206.20, defines “contract” as “any oral or written agreement . . . that is enforceable by law,” and which does not require the contract to be signed by the parties. Commenters also noted that eliminating the written contract requirement would not diminish a lessee's obligation to justify its Federal or Indian oil or gas valuation to ONRR, and that the mere absence of a written contract is not a valid reason for ONRR to interject itself and reestablish royalty value by using the default provision.

ONRR Response: ONRR agrees that the 2016 Valuation Rule overlooked the fact that oral agreements and unsigned written agreements may be binding and legally enforceable, eliminating the need for the agency to implement new requirements. Additionally, the 2016 Valuation Rule's requirement of contract signatures is inconsistent with the definition of contract found in 30 CFR 1206.20. This amendment will more readily synchronize ONRR's regulations with the long-standing definition of “contract” that is found in § 1206.20, which acknowledges that a contract may be oral or in writing and does not have to be signed. ONRR also acknowledges that oral contracts are legally enforceable, making the signature requirement unworkable and potentially burdensome upon lessees by creating a heightened requirement that may not be part of standard business practice. ONRR also agrees that eliminating the signed contract requirement does not diminish the lessee's obligation to prove its contract terms and justify its valuation methods to the agency. Long-standing ONRR regulations allow ONRR to request a lessee provide all documents relevant to the valuation of production during the course of its compliance and audit efforts. ONRR believes this provides it with an appropriate mechanism by which to verify appropriate valuation.

Public Comment: One industry commenter stated that many current agreements among producers and other parties active in the market exist electronically or via email exchanges, renew automatically, or include terms that require something not in written form. Further, the commenter indicated that the signed written contract requirement in 2016 Valuation Rule is stricter than what is required to establish a contract under general commercial law. The commenter provided an example, stating that a course of dealing could not be used to satisfy ONRR's signed contract requirement, but could be sufficient to establish a binding arrangement in a court of law, in the event of a contract dispute. This commenter also believes that ONRR has decades of experience evaluating contracts prior to the 2016 Valuation Rule, and this broad authority and experience should be adequate to carry the agency forward.

ONRR Response: ONRR agrees that the 2016 Valuation Rule overlooked the fact that many agreements renew automatically and include terms that require acknowledgement in some manner other than a written agreement signed by all parties. This amendment will eliminate inconsistency between this stated industry practice and ONRR's regulatory requirements that rely on accurate recordkeeping and how those records are to be maintained by lessees over time. ONRR also recognizes the 2016 Valuation Rule created a more stringent standard than what most lessees are subject to as part of their normal commercial transactions, and by adopting the amendment proposed in the 2020 Valuation Rule, ONRR hopes to more readily align with standard commercial practices. ONRR also agrees that prior agency practice and expertise can inform its audit and compliance activities, and that eliminating the signed contract provision will not negatively impact these efforts. These longstanding agency practices include ONRR requests to lessees for documents bearing on the valuation of production, including any written sales, transportation, or processing agreements, any documentation of an oral sales agreement, and any documentation that reflects the existence of, or pertaining to, an oral or written sales, transportation, or processing agreement, or agreement for services to place production into marketable condition.

Public Comment: One industry commenter stated that ONRR's assertion that the contract signature requirement is defective is a premature conclusion for the agency to make. The commenter asserted that ONRR should amend the definition so that it is consistent throughout all product valuation regulations instead of repealing the written contract requirement altogether. Alternatively, the commenter stated that ONRR should broaden the definition of contract to require that all contracts be in writing. The commenter also expressed concern that ONRR is simply returning to an old regimen that, by ONRR's own admission in the preamble to the 2016 Valuation Rule, is outdated and flawed.

ONRR Response: The fact that oral and unsigned, written agreements may be legally binding and enforceable between the parties impacted ONRR's decision to revisit this requirement in the 2020 Proposed Rule. ONRR is adopting the proposed amendment for the reasons stated in this final rule.

Public Comment: Several public-interest commenters stated that this proposed amendment directly contradicts the reason ONRR provided in the 2016 Valuation Rule for the inclusion of contract signatures. These commenters also believe that ONRR has not properly justified this amendment, and that verification activities would suffer without written contracts.

ONRR Response: In terms of ONRR's verification activities, ONRR believes that its compliance and audit processes will not be negatively impacted by eliminating the 2016 Valuation Rule's requirement for written contracts signed by all parties. ONRR has several methods by which it can confirm transaction-based information from a lessee without relying solely on written contracts signed by all parties. This includes ONRR's ongoing ability to request a full array of documents—both signed and unsigned, hard-copy and electronic—along with its continuing use of Generally Accepted Government Auditing Standards (“GAGAS” or “Yellow Book Standards”) to review and audit transactions based on information received from a lessee. In using these different investigatory methods, ONRR ensures compliance and verification activities that meet or exceed its regulatory mandate. ONRR is adopting the proposed amendment for the reasons stated in this final rule.

ONRR is eliminating the requirement that a lessee create and maintain contracts signed by all parties when the lessee would not otherwise do so in the normal course of business. Affected sections are §§ 1206.104(g)(1), 1206.143(g)(1), 1206.253(g)(1), and 1206.453(g)(1).

G. Citation to Legal Precedent as Part of a Valuation Determination Request

The 2016 Valuation Rule introduced a requirement that a lessee provide, along with the lessee's valuation request, any citations to legal precedent, including adverse precedent, that it believes are persuasive as part of its analysis of the issues. These requirements are set forth in §§ 1206.108(a)(5), 1206.148(a)(5), 1206.258(a)(5), and 1206.458(a)(5).

In the 2020 Proposed Rule, ONRR proposes to eliminate this requirement. More specifically, the 2020 Proposed Rule proposed to remove the phrase “including citations to all relevant precedents (including adverse precedents)” from §§ 1206.108(a)(5), 1206.148(a)(5), 1206.258(a)(5), and 1206.458(a)(5).

ONRR is familiar with, and commonly a party to, matters that generate precedent for Federal oil and gas, Federal coal, and Indian coal royalty valuation issues. Although citations might expedite the processing time for a lessee's request for a valuation determination, it is not necessary to require a lessee to provide citations to precedent. Further, ONRR believes that it would be unproductive to attempt to enforce or litigate such a requirement, especially because a failure to include a citation to precedent may not, on its own, provide a sufficient reason to deny an otherwise valid request for a valuation determination. Lessees may always cite precedent when they wish to do so in submitting a valuation request, but it is not necessary to require lessees to do this.

Comments on the Proposed Amendment

Public Comment: One industry commenter found the requirement to provide legal citations to be problematic because the requirement creates an undue burden on lessees which discourages lessees from seeking formal guidance from ONRR. The commenter explained that requiring legal citations amounts to providing a legal brief to ONRR in support of a lessee's request for a valuation determination, which is unduly burdensome and out of reach for many smaller operators with no legal support staff.

ONRR Response: ONRR agrees with this commenter and believes that the requirement to provide legal citations creates an unnecessary burden on lessees. ONRR recognizes that many lessees do not employ in-house legal counsel or have outside legal counsel on retainer who could assist with this degree of detailed legal research. Because of the significant legal costs and operational challenges that result from this requirement of the 2016 Valuation Rule, ONRR agrees that eliminating this provision removes a significant challenge for lessees who seek more formal guidance.

Public Comment: One industry commenter noted that the IBLA oftentimes issues valuation determinations via Orders, which are unpublished and difficult to find using traditional electronic search tools. This creates an issue for lessees because ONRR may be the only entity privy to this information. Further, the commenter stated that it is ONRR's responsibility to ensure that the agency administers its regulations in a consistent manner, not industry's.

ONRR Response: ONRR recognizes this limitation and agrees that the best way to eliminate the issue is to remove the requirement to cite to legal precedent. The IBLA's issuance of unpublished Orders and directives that cannot be accessed by the general public creates an unanticipated burden on lessees that this proposed amendment seeks to rectify. Further, ONRR conducts its own extensive legal research when evaluating the issues in a lessee's request for a valuation determination. Because ONRR already engages in this level of legal analysis, it is unnecessary for a lessee to duplicate efforts that the agency is already conducting as a matter of course.

Public Comment: Several industry commenters were concerned that ONRR will require excessive data and legal analysis in order for a lessee to receive valuation guidance or a determination.

ONRR Response: Although citations might expedite the processing time for a lessee's request, ONRR does not believe that it is necessary to require a lessee to provide citations to legal precedent or regulatory authority. This is particularly true for novel issues for which there may be no legal reference to cite. Therefore, ONRR is removing this requirement.

Public Comment: One industry commenter expressed concern that the lack of sufficient legal citation would give ONRR a reason to deny a request for a valuation determination.

ONRR Response: A lessee always has the option to cite to legal precedent in requesting a valuation determination. Even with the amendment adopted in this final rule, lessees may choose to include legal precedent to support or substantiate its arguments; but such citations are by no means a requisite step in the valuation determination or valuation guidance process.

Public Comment: One industry commenter stated that many mid-sized and smaller independent “Mom and Pop” oil and gas oil companies do not have access to in-house counsel or general counsel to help them research case law and legal citations in support of their valuation determination.

ONRR Response: ONRR addressed a substantially similar comment, above, and refers the commenter to the responses in the preceding section.

Public Comment: A public-interest commenter stated that the burden should remain on the lessee to provide ONRR with citation to legal precedent that bolster or support the lessee's request for a valuation determination.

ONRR Response: Although citations and reference to legal authority might expedite the processing time for a lessee's request, ONRR does not believe that it is necessary to require lessees to provide citations for this purpose. Further, ONRR believes that maintaining this requirement may disincentivize lessees from seeking a valuation determination or valuation guidance. ONRR's position is that all requests for guidance and valuation determinations are welcome, and ONRR should not create a system that discourages lessees from contacting ONRR for support or assistance.

Public Comment: A commenter indicated that citation to case law and other legal precedent may be a good barometer for ONRR to use to decide whether the lessee's request has sufficient merit, especially since a valuation determination may remain in effect for decades or longer.

ONRR Response: ONRR disagrees with this commenter. Although legal citations may provide support for a valuation determination, ONRR must still undertake comprehensive factual and legal research, and a lessee's citation to precedent will not relieve ONRR of the obligation to do so for every valuation determination. Maintaining the regulation that requires citation to legal precedent could inadvertently prevent companies from seeking a valuation determination. ONRR does not want to place unnecessary burdens on lessees and holds that the amendment eliminating the requirement to cite to legal precedent should be adopted.

For the reasons discussed in the 2020 Proposed Rule and this final rule, ONRR is removing the requirements under §§ 1206.108(a)(5), 1206.148(a)(5), 1206.258(a)(5), and 1206.458(a)(5) for a lessee to include citations to legal precedent when requesting a valuation determination.

H. Coal Valued for Royalty Purposes Based on an Electricity Sale

The 2016 Valuation Rule addressed the valuation of coal at 30 CFR 1206.252 (Federal coal) and 30 CFR 1206.452 (Indian coal). In general and consistent with ONRR's view that the best indicator of value is the gross proceeds a lessee receives under an arm's-length contract, these sections, with certain exceptions discussed below, value coal based on the gross proceeds accruing under the first arm's-length contract, less certain allowances.

In a situation where a lessee or its affiliate produces and then uses coal in a power plant owned by the lessee or its affiliate to generate electricity that is sold by the lessee or its affiliate to a variety of customers, no coal sales contract may exist and no arm's-length sale of the coal would have taken place prior to the sale of the electricity. In a situation where the electricity is sold under an arm's-length contract, §§ 1206.252(b) and 1206.452(b) of the 2016 Valuation Rule directs a lessee to value the coal based on the gross proceeds received for the electricity sale less certain allowances. If the electricity is sold under a non-arm's-length contract, these sections require the lessee to propose to ONRR a method to value the coal. ONRR may accept the lessee's proposed method or determine that the lessee needs to adjust its royalty reporting and payment because ONRR's determination resulted in a different value. Further, §§ 1206.252(c)(2) and 1206.452(c)(2) extend these valuation requirements to a lessee who sells coal to another member of a coal cooperative for use in the generation and sale of electricity.

As previously discussed, the United States District Court for the District of Wyoming entered a preliminary injunction which enjoined the implementation of the portions of the 2016 Valuation Rule applicable to Federal and Indian coal. The District Court stated that electricity sales may not be the best or a true indicator of the value of the coal produced from Federal or Indian properties. See Cloud Peak, 415 F. Supp. 3d at 1052-53. Specifically, the District Court stated, inter alia, that “an electricity utility's power supply portfolio typically includes a range of options, from nuclear to coal to natural gas to hydro, wind, and solar.” Id. at 1051 (citation omitted). “Thus, the sales price of the electricity is comprised of much more than just the cost of coal, and that's ignoring the rabbit hole that is electricity sales regulation by both the federal and state governments.” Id.

After careful consideration, of the pleadings filed and arguments raised in the United States District Court for the District of Wyoming relating to the coal cooperative definition and the electricity netback method, and the District Court's rationale underlying the preliminary injunction, together with the public comments discussed below, ONRR concludes that valuing coal on the first arm's-length sale of electricity is unworkable and inadvisable. Many resources contribute to the generation of the electricity. Calculations to determine netback rely on the availability of information on the amount and type of fuels used to generate a kilowatt hour of electricity, detailed data on the capital costs of the plant to include the direct costs of all plant, materials, equipment and buildings, fixed and variable operating costs influenced by the age, efficiency, and limitations of all plant equipment and including voluntarily-supplied labor costs attributable to keeping the plant in operation, as well as consideration of market dynamics such as system load factors and peak-shaving capacity. ONRR lacks authority to compel a power plant to provide these data sources, and, even with the data, it is overly burdensome, exceedingly complex, and too difficult to accurately and meaningfully develop models to simulate individual power plant operations effectively to isolate the contribution of a single non-arm's-length coal source to the value of the electricity, let alone assume that it is an accurate proxy for the value of coal determined based on arm's-length sales. ONRR is removing this unworkable and unduly burdensome requirement from its valuation regulations.

Thus, in the 2020 Proposed Rule, ONRR proposed to amend §§ 1206.252(b) and 1206.452(b) to remove coal valuation based on arm's-length electricity sales. See 85 FR 62055 and 62061. With removal, a lessee will be required to propose a method to value all coal that it or its affiliate uses for the generation and sale of electricity, regardless of whether the electricity is sold under in an arm's-length or a non-arm's-length contract.

Comments on the Proposed Amendment

Public Comment: Some industry commenters supported the removal of provisions that required the valuation of certain coal based on the sale of electricity. The commenters pointed out that it would be impossible to derive a meaningful value for coal from the value of electricity. One commenter argued that ONRR was not upholding its responsibility to obtain a fair market value for Federal coal since it did not provide a method to value coal never sold at arm's-length. Further, these commenters focused on the reduced complexity of valuation computations and reduced administrative burdens that would be recognized by removing this provision.

ONRR Response: ONRR agrees that valuing coal based on the sales price of electricity would result in an overly burdensome series of calculations resulting in a value that would be open to challenge and would be overly burdensome for ONRR to perform compliance activities and verify accurate reporting and payments. Even if ONRR completed such compliance activities and issued an order to the lessee, these audits would likely result in the issuance of orders that would be contested by the lessee and, potentially, modified or overturned by the IBLA or a reviewing court after protracted litigation. ONRR agrees that there is no universal solution or method that can be applied to value all coal used to produce electricity. ONRR further agrees that it is reasonable and proper for the lessee to identify, in the first instance, the situation-specific circumstances that could impact the appropriate method to values royalties. Fortunately, these situations are not common, resulting in only a handful or fewer cases that ONRR will need to review and approve. Even after several decades of experience, ONRR has not found a better solution for instances when coal is converted to another commodity without sales. The valuation solutions in these cases must take into account the lessees' rights under the lease agreements, the MLA, and court-established precedents in order to establish a reasonable method to value this coal. ONRR will work to arrive at a just valuation method for lessees and the lessor where these no-sale situations exist under § 1206.252(b).

Public Comment: Other commenters opposing this change argued that generated electricity is a more accurate indicator of coal's value than any method allowed under § 1206.252. Additionally, some of these commenters advocated that coal should be valued further downstream including, in some cases, the last arm's-length electricity sale.

ONRR Response: As stated above, valuing coal based on the first arm's-length sale of electricity is not a more accurate indicator of the value of coal in the limited circumstances affected by this rule change. Instead, it is a long-standing principle that royalty valuation of production from Federal and Indian leases typically occurs at or near the lease. In addition, ONRR has never looked beyond the first arm's-length sale to the last arm's-length sale. Most coal produced from Federal leases is sold at arm's-length at or near the mine loadout, where mined coal is loaded for shipment to the buyer. Where a lessee moves its production away from the lease prior to this first sale (where ownership of the coal passes from producer to buyer), an allowance for transportation may be deducted from the royalty value. If the lessee sells or transfers the coal to an affiliate, the point of sale is where the first arm's-length sale of the coal by the affiliate occurs. In cases where no coal sale occurs prior to the generation of electricity, the lessee is required to submit a proposed valuation method to ONRR. In turn, ONRR will review and either approve the lessee's method or ONRR will construct a reasonable value using the best information available under § 1206.252(b).

Public Comment: Several industry commenters argued that ONRR is acting arbitrarily and capriciously when it allows lessees the opportunity to propose their own valuation method.

ONRR Response: Over time, ONRR has found that the information that lessees provide when requesting a valuation determination has been sufficient to establish a value for coal that results in a fair royalty value. The proposed amendments will ensure that coal used by the lessee or its affiliate in a power plant for the generation and sale of electricity is fairly valued by requiring (1) the lessee to propose to ONRR a method that provides a proxy for what would be the first arm's-length sale of the coal and (2) to adjust its royalty reporting and payment if ONRR determines that the proposed method does not fairly reflect the coal's value.

Public Comment: Two commenters offered suggestions as to how to value non-arm's-length coal sales. The commenters suggested that ONRR go back to the coal valuation regulations in effect prior to the 2016 Valuation Rule, which used a series of benchmarks to value coal sold in non-arm's-length transactions. They also suggested that the first benchmark be changed so that a lessee could use their own arm's-length sales contracts to establish a range to compare their non-arm's-length sales contracts when determining the appropriateness of the non-arm's-length sales price. The commenters also suggested that ONRR use a published index price to establish a value for coal sold non-arm's-length.

ONRR Response: Typically, the best indicator of value is the gross proceeds received under an arm's-length contract between independent entities who are not affiliates and who have opposing economic interests regarding that contract. Also, typically the best indicator of value under a non-arm's-length sale is the gross proceeds accruing to the lessee or its affiliate under the first arm's-length sale, less applicable allowances.

ONRR is not currently aware of any published index prices for coal that covers a wide array of coal production, which indices are both transparent and widely traded to yield a reasonable value that would represent the true market value of coal.

Public Comment: One commenter also suggested that ONRR should consider adopting an objectively-determinable backstop similar to the major-portion concept applicable to valuing oil and gas produced from Indian leases. Under the major portion process, lessees initially pay royalty based on their application of the valuation regulations (including using benchmarks for certain non-arm's-length transactions). After ONRR collects all the sales data in particular areas from lessees' royalty reports, ONRR calculates and publishes a major-portion price. Any lessee that initially paid royalty on a value less than the major-portion price must re-report and pay any differential.

ONRR Response: The proposal to construct a major portion comparison for coal is not something ONRR is prepared to address in this rulemaking. ONRR may consider this idea in future rulemaking efforts. ONRR applies major-portion pricing based on Secretarial discretion. Currently, ONRR only applies major portion to certain Indian oil and gas leases.

Public Comment: One commenter suggested that ONRR should not establish a floor price for coal. The commenter argued that lessees should be able to sell their coal at below-market prices in order to continue operations. They also argued that it is inconsistent and unreasonable for ONRR to chase the actual arm's-length sale price of coal while also suggesting that a floor value be established when it is to ONRR's benefit.

ONRR Response: To be clear, ONRR does not set prices for commodities. Rather, ONRR ensures royalties are reported and paid based on values typically best reflected in the price received by the lessee in an arm's-length sale of the same or similar commodity. ONRR's regulations require a lessee to market coal for the mutual benefit of the lessee and the lessor. The regulations further provide that the best indicator of value is typically the gross proceeds received under an arm's-length contract between independent entities that are not affiliates and have opposing economic interests. Any uplift in gross proceeds, an increase in the contract sales price, an affiliate of the lessee realizes in an arm's-length sale of the same or a similar commodity after buying coal non-arm's-length from the lessee should be royalty bearing. Sales below market prices “in order to continue operations” do not reflect the value of the resource but rather operating conditions experienced by the lessee.

Public Comment: One commenter stated that the economic impact of removing the electricity netback method from the rule for Federal and Indian coal would be impossible to measure. The commenter also stated that using the first arm's-length sale of coal to value coal sold non-arm's-length for Indian leases should have no economic impact.

ONRR Response: ONRR has estimated, in past rulemakings, that the implementation and now removal of the electricity netback method will have no impact on royalties. As discussed below, ONRR believes, but has not estimated, that removing the electricity netback method will reduce administrative burden for both the lessee and ONRR.

ONRR appreciates comments supporting, seeking modification to, and opposing the proposed amendment. Based on the reasons given in the 2020 Proposed Rule (see 85 FR 62061) where ONRR stated that the valuation method was burdensome and controversial, the pleadings filed and arguments raised in the United States District Court for the District of Wyoming, the District Court's rationale for the preliminary injunction, and the public comments received, ONRR is adopting the amendment as proposed.

I. “Coal Cooperative” Definition

The 2016 Valuation Rule amended ONRR's regulations to add a definition of “coal cooperative,” at 30 CFR 1206.20, to mean “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.” See also 81 FR 43369.

The 2016 Valuation Rule also added §§ 1206.252(c)(1) (Federal coal) and 1206.452(c)(1) (Indian coal). Those sections require a lessee to value coal under §§ 1206.252(a) and 1206.452(a), respectively, if the lessee sells the coal to another member of a coal cooperative and that member, in turn, sells the coal under an arm's-length contract. Sections 1206.252(a) and 1206.452(a) provide that the value of coal is the gross proceeds accruing to the lessee or its affiliate under the first arm's-length contract, less allowances.

The 2016 Valuation Rule also added §§ 1206.252(c)(2) and 1206.452(c)(2), which address the valuation of coal in the situation where a lessee sells coal to another member of a coal cooperative that uses the coal to generate and sell electricity. The 2016 Valuation Rule also explained that, principally, coal cooperatives are formed because of some degree of mutual economic or other business interest. See 81 FR 43338, 43354. Thus, transactions between members of a coal cooperative lack the typical opposing economic interests necessary to create an arm's-length sale.

In the 2020 Proposed Rule, ONRR proposed to amend 30 CFR part 1206 to remove the “coal cooperative” definition under § 1206.20 and the requirements of §§ 1206.252(c)(1)-(2) and 1206.452(c)(1)-(2). See 85 FR 62061. By these proposed amendments, ONRR attempts to relieve concerns with the meaning and effect of the coal cooperative amendments while maintaining the royalty value of coal.

Comments on the Proposed Amendment

Public Comment: Numerous industry commenters agreed that ONRR should remove the coal cooperative definition because its inclusion in ONRR's regulations fails to reflect those entities' corporate structure, would harm small producers, and unduly complicates coal's royalty valuation.

ONRR Response: For the reasons discussed above in the preamble and the 2020 Proposed Rule (see 85 FR 62061), ONRR agrees that the definition of coal cooperatives is overly broad and ambiguous, and would create too much confusion to be effective or enforceable. ONRR also agrees that the definition is unnecessary because ONRR's long-standing definitions of “affiliate” and “non-arm's length” are sufficient to protect the lessor's interest. Under those existing definitions, any transfer of coal between entities lacking opposing economic interest is a non-arm's-length sale. In such cases, the lessee must look to either the first arm's-length sale of the coal by its affiliate, or the lessee must come to ONRR and request a valuation determination. See 81 FR 43369.

Public Comment: Some commenters oppose the amendment to remove the “coal cooperative” definition as well as its recognition that certain sales are not arm's-length transactions. These commenters expressed a concern that cooperative members could use their affiliated status to sell coal to each other at less than market prices, which improperly lowers royalty payments. Some commenters alleged that ONRR failed to provide a reasoned explanation as to why the removal of the “coal cooperative” definition was necessary and also stated that ONRR incorrectly asserted the Wyoming District Court “offered strong criticism” of its definition. These commenters concluded that ONRR's proposed action is arbitrary and capricious.

ONRR Response: ONRR's regulations require coal to be valued, when possible, on the value realized under the first arm's-length sale. Removing the “coal cooperative” definition does not alter that principle or change other methods available to evaluate a coal transaction's nature. The overly broad definition of “coal cooperatives” draws, within its coverage, entities that are not affiliated and which have opposing economic interests when it comes to buying and selling coal. Thus, the definition results in the treatment of some transactions as if they were non-arm's-length when they are, in fact, more appropriately viewed as arm's-length transactions under traditional principles because ONRR's regulations identify what conditions constitute sales between affiliates, and treats those circumstances as non-arm's-length sales. And sales between entities that lack opposing economic interests are also treated as non-arm's-length sales. As demonstrated in its recent filing in the United States District Court for the District of Wyoming, ONRR concurs with the ruling set forth in the District Court's preliminary injunction that suggested that, upon final briefing, the provisions of the 2016 Valuation Rule that require some coal cooperatives to value coal based on the sales price of electricity and the definition of coal cooperative are arbitrary and capricious. Removing the cited provisions fosters the most appropriate treatment of transactions as either arm's-length or non-arm's-length.

ONRR appreciates comments supporting, seeking modification to, and opposing the proposed amendment. After careful consideration of the reasons given in the 2020 Proposed Rule (see 85 FR 62061) that the definition was confusing and unnecessary, the pleadings filed and arguments raised in the United States District Court for the District of Wyoming, the District Court's rationale for the preliminary injunction, and the public comments, ONRR is adopting the amendment to remove the “coal cooperative” definition from § 1206.20 and the valuation requirements for coal sold to coal cooperatives at §§ 1206.252(c)(1) and (2) and 1206.452(c)(1) and (2).

III. Amendment Discussion—Part 1241 Penalties

The first objective of the civil penalty provision of this rule is to increase the transparency and fairness of ONRR's current civil penalty practices for the benefit of regulated parties and interested members of the public. On October 9, 2019, the President issued E.O. 13892, “Promoting the Rule of Law Through Transparency and Fairness in Civil Administrative Enforcement and Adjudication,” which emphasized the importance of transparency in agency civil penalty practices. Specifically, E.O. 13892 directed Federal agencies to “act transparently and fairly with respect to all affected parties . . . when engaged in civil administrative enforcement or adjudication.” Further, E.O. 13892 highlights the need, where feasible, to “foster greater private-sector cooperation in enforcement, promote information sharing with the private sector, and establish predictable outcomes for private conduct.”

The second objective of the civil penalty provision of this rule is to address the analysis of the 2016 Civil Penalty Rule within a now vacated Federal District Court's decision.

In the 2020 Proposed Rule, ONRR discussed three potential amendments to its civil penalty regulations, set forth at 30 CFR part 1241. First, for transparency, ONRR proposed to amend § 1241.70(b) to explain that—for payment violations only—ONRR would consider the monetary impact of the violator's conduct when assessing a civil penalty. In Section F of the 2020 Proposed Rule, ONRR specifically elicited comments on how the proposed amendment to §  1241.70(b) would impact lessees that receive a civil penalty. ONRR received no comments opposing but received several comments supporting this amendment. The supporting comments generally agreed that penalties should be proportionate to the unpaid, underpaid, or late paid royalty obligation. ONRR received no comment describing the specific impact this amendment might have on a lessee. As this amendment merely clarifies ONRR's current practice, ONRR did not anticipate a commenter would identify an impact.

Second, for transparency, ONRR proposed an amendment to §  1241.70 to add §  1241.70(d) to clarify that ONRR may consider aggravating and mitigating circumstances in determining the appropriate penalty. In the 2020 Proposed Rule, ONRR specifically requested comments on how this proposed §  1241.70(d) would impact lessees subject to an ONRR-issued civil penalty and what facts or situations ONRR should treat as aggravating and mitigating circumstances. ONRR received comments generally supporting this amendment and no comments in opposition. The supporting comments generally agreed that ONRR should be more transparent in how it treats mitigating and aggravating circumstances. There was no comment describing any specific impact this amendment would have on a lessee. As this amendment merely clarifies ONRR's current practice, it did not anticipate any impacts. However, ONRR did receive comments suggesting alternative aggravating and mitigating circumstances, which are addressed below in Section III.B.

Third, for fairness, ONRR proposed to amend §  1241.11(b)(5) to return to its historical practice of guaranteeing an appellant the benefit of a stay of the accrual of a civil penalty during an appeal if granted by the Department's ALJ. ONRR specifically sought comments on how eliminating §  1241.11(b)(5) would affect lessees to whom a civil penalty was issued. ONRR received comments generally supporting this amendment and no comments in opposition. The comments in support generally agreed that ONRR should eliminate this provision from its regulations. There was no comment describing any specific impact this amendment would cause on a lessee, other than a general concern that the provision, if not removed, would deter penalized parties from asserting their due process rights.

General Comments

ONRR did not receive comments either supporting, opposing, or seeking to modify the proposed amendments to §§ 1241.11(b)(5) and 1241.70(b), or to the proposed addition of § 1241.70(d). Some commenters sought numerous other civil penalty policy changes, including increasing the number and size of civil penalties or modifying other portions of ONRR's civil penalty regulations were beyond the scope of the 2020 Proposed Rule. One commenter requested that ONRR pursue civil penalties for environmental crimes. Another commenter sought greater collaboration with State and Tribal Royalty Audit Committee members on FOGRMA compliance. This commenter also sought greater royalty accuracy in compliance activities—audits, compliance reviews, and data mining. Commenters sought an increase in civil penalties to pursue policy goals of decreasing emissions and reducing climate change. Other commenters requested that ONRR reconsider the definition of “knowingly or willfully” in § 1241.3(b). Commenters also sought to amend § 1241.60(c), which allows ONRR to consider “any information” including informal email communications, to evaluate whether violations were committed “knowingly or willfully.” One commenter requested ONRR adopt a regulation regarding the posting of civil penalties and enforcement actions on social media. ONRR appreciates these comments and may consider them in the future; however, these comments were beyond the scope of the 2020 Proposed Rule and unrelated to the proposed amendments to §§ 1241.11(b)(5), 1241.70(b), and the proposed addition of § 1241.70(d). Accordingly, ONRR is not implementing policies to enact the proposals in these out-of-scope comments in this final rule.

A. Civil Penalties for Payment Violations

The 2016 Civil Penalty Rule added § 1241.70(b) to clarify that, with respect to reporting violations or other violations arising from a failure to provide required data to ONRR, ONRR does not consider the monetary impact of the violation in the severity analysis performed as part of the determination of the amount of a penalty. The 2016 addition of § 1247.70(b) was meant to distinguish between how ONRR treats non-payment violations from payment violations, the latter of which include a failure to pay royalties, rent, interest, fees, or other demands or obligations. It was ONRR's intent in the 2016 Civil Penalty Rule to clarify that ONRR considers the monetary impact in its severity analysis only when a company's conduct involves a payment violation. This is in addition to ONRR's consideration—in all violation types—of the company's history of noncompliance and business size. Specifically, § 1241.70(b), as added in 2016, states that ONRR “will not consider the royalty consequence of the underlying violation when determining the amount of the civil penalty for a violation under § 1241.50 or § 1241.60(b)(1)(ii) or (b)(2).” The clarification was necessary because most violations arising under § 1241.50 (curable violations) are reporting violations and require correction regardless of amount of money that may be owed because of the reporting violation. Because of the need to correct violations regardless of the monetary amount, reporting violations are similar to failure to permit audit violations under § 1241.60(b)(1)(ii) and knowing or willful submission or maintenance violations under § 1241.60(b)(2).

In the 2020 Proposed Rule, ONRR attempted to further clarify how it treats payment versus non-payment violations with the proposed amendment of § 1241.70(b), stating that ONRR will consider the unpaid, underpaid, or late payment amount in the severity analysis for payment violations only.

In the 2020 Proposed Rule, ONRR explained that adopting the proposed amendment to § 1241.70(b) is consistent with E.O. 13892 which, among the general goals of transparency and fairness in agency civil penalty practices, requires agencies to avoid “unfair surprise” and apply “standards of conduct that have been publicly stated.” See E.O. 13892, Section 4.

ONRR further stated that it would not consider the monetary amount for non-payment obligations. To provide more clarity, ONRR is expressly stating that it considers the monetary impact for all payment violations, which includes payment violations arising under §  1241.50. In contrast, the 2016 Civil Penalty Rule only indicated that ONRR could consider the royalty impact for the knowing or willful failure to pay royalty violations under § 1241.60(b)(1)(i), which was the only violation type left once ONRR excluded “violation under § 1241.50 or § 1241.60(b)(1)(ii) or (b)(2).”

ONRR believes that the proposed amendment furthers the goal of clarifying its civil penalty practices in order to make those practices transparent. Specifically, the proposed amendment adds a sentence clarifying that ONRR will consider the monetary impact of a penalty only when a company's conduct involves a payment violation.

Comments on the Proposed Amendment

Public Comment: ONRR received comments supporting the proposed amendment to § 1241.70(b). These commenters generally agreed that ONRR should consider the monetary consequence of payment violations and supported the proposed change to § 1241.70(b). Commenters support the reasons ONRR outlined in the 2020 Proposed Rule and noted that the proposed amendment would ensure proportionality of the penalty when compared to the amount of the unpaid, underpaid, or late paid royalty obligation at issue. Generally, the commenters supported the amendment, arguing that penalties issued for payment violations should not be excessive in comparison to the monetary impact of the underlying payment violation. To be clear, as stated above, ONRR considers the unpaid, underpaid, or late-paid amount when it considers penalties for payment violations arising under §  1241.50 and for knowing or willful failure to pay royalty violations under § 1241.60(b)(1)(i).

ONRR Response: ONRR appreciates the comments supporting the proposed amendment to 30 CFR 1241.70(b). ONRR agrees that the 2020 Proposed Rule provides greater transparency in ONRR's civil penalty practice.

After careful consideration, including for the reasons explained above, ONRR is adopting the proposed amendment to § 1241.70(b) in full.

B. Consideration of Aggravating and Mitigating Circumstances When ONRR Assesses a Civil Penalty

Section 1241.70(a) identifies three factors that ONRR must consider in assessing the amount of a civil penalty. However, this section, as currently written, does not include language permitting ONRR to consider aggravating and mitigating circumstances. In the 2020 Proposed Rule, ONRR proposed to add new paragraph (d) to § 1241.70 stating that ONRR may adjust the penalty amount upward or downward in a failure to correct civil penalty (“FCCP”) or immediate liability civil penalty (“ILCP”) if ONRR finds aggravating or mitigating circumstances to exist.

Consistent with E.O. 13892's transparency and fairness directives, the proposed addition of § 1241.70(d) explains that ONRR may consider aggravating and mitigating circumstances when calculating the amount of a civil penalty. The amendment also aims to reduce or eliminate any undue surprise for companies in instances where ONRR deviates from the standard penalty assessment because of those circumstances. Additionally, the proposed addition of § 1241.70(d) accomplishes the implementation of the approach directed by E.O. 13924 and E.O. 13892.

Comments on the Proposed Amendment

Public Comment: ONRR received comments supporting the proposed amendment to add § 1241.70(d). The commenters generally supported greater transparency in ONRR's assessment of penalties. The commenters agreed that ONRR should consider aggravating or mitigating circumstances in certain cases and therefore support the addition of § 1241.70(d). Some commenters who supported this amendment did so because it establishes flexibility in ONRR's civil penalty calculations in order to arrive at penalty amounts that are proportionate to the underlying monetary violation.

Some commenters responded to ONRR's request for comment on circumstances that ONRR should consider to be aggravating and mitigating. Some commenters supported the inclusion of an aggravating circumstance to consider “intentional misconduct to reduce royalties otherwise due.” Some commenters suggested including additional mitigating factors, such as innocent reporting mistakes, lack of a history of prior violations of the same or more severe violations, and actions that adhere to guidance from ONRR. One commenter suggested that the proposed provision under § 1241.70(d)(iii), which considers good faith efforts to comply with formal or informal agency guidance, should constitute grounds for eliminating any civil penalty from being assessed. Lastly, another commenter suggested that the list of aggravating and mitigating circumstances is not exhaustive and may lend to ambiguity and agency burden in making case-by-case determinations.

ONRR Response: ONRR appreciates and agrees with the comments supporting the proposed amendment to § 1241.70(d). ONRR acknowledges that the list of circumstances in the proposed regulatory language is not all-inclusive. Although the list is not exhaustive, it provides further transparency and predictability with respect to existing practices. ONRR possesses both the authority and expertise to consider aggravating or mitigating circumstances outside of the list proposed under § 1241.70(d). These considerations do not create an undue or excessive burden to the agency, as one commenter suggested.

Some commenters recommended the inclusion of additional aggravating or mitigating circumstances. ONRR disagrees with the suggestion to include an aggravating circumstance of intentional misconduct to reduce royalties otherwise due, because that circumstance is considered in the standard penalty amount for non-curable violations described under 30 U.S.C. 1719(c) and (d) and 30 CFR 1241.60. ONRR also disagrees with the suggestion to include a mitigating circumstance of innocent reporting mistakes, because that circumstance is considered in the standard penalty amount of curable violations described under 30 U.S.C. 1719(a) and (b) and 30 CFR 1241.50. Consideration of innocent reporting mistakes as a mitigating circumstance would de-emphasize and undermine the importance of correcting the mistakes promptly as required by an ONRR notice of noncompliance (“NONC”). And receipt of an ONRR NONC is a condition precedent to ONRR's assessment of a penalty for a failure to correct an innocent reporting mistake. ONRR also disagrees with the suggestion to include a mitigating circumstance of a lack of a prior violation. ONRR's standard penalty amounts already account for a lack of a history of noncompliance. Finally, ONRR is making no change in response to the suggestion to modify the language that no penalties are appropriate when a violator makes a good faith effort to comply with formal or informal agency guidance. Consistent with its exercise of prosecutorial discretion, ONRR retains the discretion to evaluate mitigating circumstances on a case-by-case basis and conclude that the presence of mitigating circumstances can justify resolving a matter without penalty. See Heckler v. Chaney, 470 U.S. 821 (1985). In exercising its prosecutorial discretion, ONRR will be guided by the principles reflected in E.O. 13924, “Regulatory Relief to Support Economic Recovery,” E.O. 13892, “Promoting the Rule of Law Through Transparency and Fairness in Civil Administrative Enforcement and Adjudication,” E.O. 13891, “Promoting the Rule of Law Through Improved Agency Guidance Documents,” and S.O. 3385, “Enforcement Priorities.” Thus, ONRR already has the discretion to determine that no penalties are appropriate when sufficient mitigating circumstances are present, including a good faith effort to comply with formal or informal agency guidance. Because ONRR intended for the proposed amendment to provide transparency in how it calculates penalty amounts and did not intend to address when it would exercise its prosecutorial discretion, ONRR finds the language regarding guidance in the proposed provision under § 1241.70(d)(2)(iii) sufficient.

ONRR appreciates the comments supporting and seeking the modification to the proposed amendment to § 1241.70(d). After careful consideration, and for the reasons explained above, ONRR is adopting the proposed addition at § 1241.70(d) in full.

C. Forfeiture of a Stay of the Civil Penalty Accrual Under Limited Circumstances

ONRR's 2016 Civil Penalty Rule added § 1241.11(b)(5) to give an ALJ the ability to conclude that a petitioner had raised a frivolous defense and therefore should forfeit the benefit of a previously-granted stay of the accrual of the amount of the civil penalty. Specifically, the 2016 Civil Penalty Rule states that “[n]otwithstanding paragraphs (b)(1), (2), (3), and (4) of this section, if the ALJ determines that your defense to a Notice is frivolous, and a civil penalty is owed, you will forfeit the benefit of the stay, and penalties will be calculated as if no stay had been granted.”

In the 2020 Proposed Rule, ONRR proposed to amend § 1241.11 by removing paragraph (b)(5). The proposed amendment followed the U.S. District Court for the District of Wyoming's decision to vacate § 1241.11(b)(5). See API, 366 F. Supp. 3d at 1309-1311. Although the Tenth Circuit subsequently vacated the District Court's decision on other grounds, ONRR finds the District Court's analysis relevant in its determination to remove paragraph (b)(5) and the mission of ONRR's overall civil penalty program.

The District Court found “unpersuasive” the argument that due process rights are implicated by § 1241.11(b)(5), but still found the provision “an abuse of discretion and not in accordance with law.” API, 366 F. Supp. 3d at 1310. Most problematic to the District Court was the fact that it provided ONRR with “a second bite” to argue a defense was frivolous after an optional chance to oppose the stay and “the potential loss” if a stay were nullified was significant. Id. This analysis is relevant because if a person obtains standing to challenge this provision in the future, ONRR expects it will be invalidated if challenged in the District of Wyoming.

The IBLA, Office of Hearings and Appeals Division's procedural requirements under 43 CFR 4.21(b) establish that “the appellant requesting the stay bears the burden of proof to demonstrate that a stay should be granted.” If the ALJ grants a stay, the accrual of additional penalty amounts would be paused until there is an ALJ decision in ONRR's favor, coupled with a determination that the violation is ongoing. See 30 CFR 1241.11(a) and (b). By adopting the amendment, ONRR returns to its pre-2016 Civil Penalty Rule practice whereby penalties would not accrue during the period of a stay, even if an ALJ subsequently finds a petitioner's defense to the penalty to be frivolous.

ONRR believes § 1241.11(b)(5) is duplicative because ONRR may still safeguard against a frivolous defense by opposing a petition for a stay under § 1241.11(b)(2)(i). As the District Court stated, “If ONRR believes a stay is not warranted, including the argument that the defense is frivolous, ONRR has the right to, and should file a response to the stay petition rather than wait on an outcome at some undetermined later date and then assert frivolity.” API, 366 F. Supp. 3d at 1310. ONRR concurs with the District Court that ONRR has the right to oppose a frivolous stay petition and that it should do so. Additionally, removing § 1241.11(b)(5) would be consistent with executive orders seeking to increase transparency and reduce undue surprise in penalty assessments. Further, by removing § 1241.11(b)(5), ONRR still retains a remedy against frivolous cases, while eliminating unnecessary regulations.

ONRR anticipates that it will be rare that a frivolous defense is both more persuasive than ONRR's response to a petition for stay and ultimately sufficient to convince the ALJ that the petitioner's defense to the penalty was frivolous. ONRR believes that removing § 1241.11(b)(5), in light of the District Court's analysis, remains consistent with the purpose of assessing civil penalties, which is to encourage compliance and discourage noncompliance, and also is consistent with E.O. 13892 and the policies reflected in that order.

Comments on the Proposed Amendment

Public Comment: Some commenters supported the removal of § 1241.11(b)(5). The commenters that supported the amendment fell into two general categories. First, commenters generally supported the reasons described in the 2020 Proposed Rule. Second, commenters supported the amendment because of due process concerns, including the possibility that § 1241.11(b)(5) may discourage a petitioner from exercising its due process rights. ONRR also received one comment suggesting that the 2020 Proposed Rule did not provide sufficient reasons for its repeal of an ALJ's ability to revoke a stay of accrual upon determination of a frivolous claim. The commenters did not advocate for rejecting or modifying the amended regulations as proposed. However, the commenter asserted that the Tenth Circuit's vacatur of the District Court of Wyoming's decision is an insufficient rationale to remove the provisions found in § 1241.11(b)(5).

ONRR Response: ONRR appreciates and agrees with the comments supporting the proposed amendment to § 1241.11(b)(5). ONRR also appreciates this opportunity to afford additional clarity and rationale in the proposed removal of this provision, which is to increase transparency, reduce undue surprise, remove an unnecessary regulation, and still have sufficient protection from frivolous defenses to civil penalties, as further discussed above.

ONRR appreciates the comments supporting the proposed amendment to § 1241.11(b)(5) and the comment indicating that additional rationale is needed to remove this provision. After careful consideration, and for the reasons and additional rationale explained above, ONRR is adopting the proposed amendment to remove § 1241.11(b)(5).

IV. Non-Substantive Corrections

Through this final rule, ONRR is also making non-substantive corrections to the following sections: §§ 1206.108, 1206.148, 1206.252, 1206.258, 1206.261, 1206.268, 1206.452, 1206.458, 1206.460, 1206.461, 1206.467, and 1206.468. Corrections include:

1. ONRR reports to the Assistant Secretary for Policy, Management, and Budget. This final rule replaces instances of the words “Assistant Secretary” with “Assistant Secretary for Policy, Management and Budget” to clarify and specify the correct Assistant Secretary within the Department.

2. 30 CFR 1206.252 and 1206.452 are titled “How do I calculate royalty value for coal that I or my affiliate sell(s) under an arm's-length or non-arm's-length contract?” In addition to addressing the valuation of coal that is sold, these sections also address the valuation of coal that a lessee or its affiliate uses for the generation and sale of electricity. See §§ 1206.252(b) and 1206.452(b). This final rule eliminates any requirement that coal be based on the price received through electricity sales. Even after that amendment, both sections still address the valuation of coal that is used for the generation and sale of electricity, and thus not sold. Specifically, the sections require the lessee to propose a method to ONRR for the valuation of the coal and further require the lessee to use its proposed valuation method until ONRR makes a determination. Id. Since both sections also address situations when coal is not sold, ONRR is amending the title of §§ 1206.252 and 1206.452 as part of this final rule to read: “How do I calculate royalty value for coal?” This amendment conforms the title of the sections to the content thereof.

3. 30 CFR 1206.252(a) and 1206.452(a) provide that the value of coal generally is the “gross proceeds accruing to you or your affiliate under the first arm's-length contract” less certain allowances. Sections 1206.252(a)(1)-(2) and 1206.452(a)(1)-(2) state that this requirement to use gross proceeds to value the coal applies when a lessee sells the coal under an arm's-length contract or the lessee sells or transfers the coal to its “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 coal under an arm's-length contract.” Since the first arm's-length sale of the coal may be by a person other than the lessee or its affiliate under §§ 1206.252(a)(1)-(2) and 1206.452(a)(1)-(2), ONRR is amending §§ 1206.252(a) and 1206.452(a) to reflect that the gross proceeds used to value the coal is the “gross proceeds accruing to you, your affiliate, or another person under the first arm's-length contract” less allowances.

4. The 2020 Proposed Rule also proposed amendments to change certain instances of “may” to “must” in §§ 1206.252(b)(2) and 1206.452(b)(2). The paragraphs apply when a lessee has proposed a valuation method to ONRR for consideration and instruct that the lessee “may” use the method it proposed until ONRR issues a determination. ONRR intended that the lessee would use its proposed method while its proposal was pending with ONRR. A change from “may” to “must” better reflects that intent. For the same reasons, ONRR is making the same change from “may” to “must” in §§ 1206.111(d)(2); 1206.141(e)(2)(ii); 1206.142(f)(2)(ii); 1206.153(d)(1); 1206.160(c)(1); 1206.261(c)(1); 1206.268(c)(1); 1206.461(c)(1); and 1206.468(c)(1) (reporting a washing allowance using a proposed method).

5. This final rule corrects the 2020 Proposed Rule's description of some leases as “Federal” when they should have been identified as “Indian” in §§ 1206.460 and 1206.467.

6. ONRR is correcting a cross-reference in § 1206.458(h) to properly refer to “§ 1206.459” rather than “§ 1206.259,” as was initially published in the 2020 Proposed Rule.

V. Economic Analysis

ONRR shares the Department's statutory mandate to conserve and encourage domestic production of natural resources and develop regulations to achieve these goals. BOEM and BLM have provided information and documentation to ONRR demonstrating that the dynamics of the domestic energy markets have changed since the 2016 Valuation Rule was published. In the years leading up to the 2016 Valuation Rule, domestic energy commodity prices were nearly double those leading up to this rule. Given this, GOM assets have lost value and leasing is less attractive than previously. BOEM information shows reserves in the GOM are declining and GOM bidding, active leases, rig counts, and wells spud have declined significantly since ONRR's Economic Analysis in the 2016 Valuation Rule.

In the 2020 Proposed Rule, ONRR summarized the estimated changes to royalties and regulatory costs that the proposed rule may have on potentially affected groups, including industry, the Federal Government, and State and local governments.

ONRR notes that changes to royalties are transfers that are distinguishable from regulatory costs (or cost savings). The estimated changes in royalties will change both the private cost to the lessee and the amount of revenue collected by the Federal Government and disbursed to State and local governments. The net impact of the amendments adopted by this final rule is an estimated $28.9 million annual decrease in royalty collections. This represents a decrease of less than one-half of one percent of the total Federal oil and gas royalties ONRR collected in 2018. The royalty impact, as evident in the total annual estimate reflected above, does impact the disbursements for the Treasury and for States that are stakeholders and recipients of ONRR's distributions.

ONRR also estimates that the Federal oil and gas industry will face increased annual administrative costs of $2.58 million under this final rule. As discussed below, this is the net impact of various cost increasing and cost saving measures.

ONRR estimates that this rule will have no economic impact on Federal and Indian coal. Please note that, unless otherwise indicated, numbers in the tables in this section are rounded to the nearest thousand, and that the totals may not match due to rounding.

General Comments on the Economic Analysis

Public Comment: Some commenters suggested that the economic analysis is incorrect because it compared the proposed amendments relative to ONRR's current regulations which include the 2016 Valuation Rule amendments, which commenters suggest should have never happened.

ONRR Response: ONRR's current regulations include the 2016 Valuation Rule's amendments. The appropriate baseline for this rule is the rules that are currently in effect. Any change that would be affected by the rule will be measured relative to that baseline.

1. Federal Oil and Gas Industry

This table shows the change in royalties by provision for the first year and each year thereafter:

Summary of Changes to Oil & Gas Royalties Paid

[Annual]

Rule provision	Net change in royalties paid by lessees
Index-Based Valuation Method Extended to Arm's-Length Gas Sales	$5,620,000
Index-Based Valuation Method Extended to Arm's-Length NGL Sales	21,141,000
High to Midpoint Index Price for Non-Arm's-Length Gas Sales	(4,488,000)
Transportation Deduction Non-Arm's-Length Index-Based Valuation Method	(7,121,000)
Extraordinary Processing Allowances	(11,131,000)
Allowances for Certain OCS Deepwater Gathering Costs	(32,900,000)
Total	(28,879,000)

ONRR estimated the administrative cost savings from optional use of the index-based valuation method for arm's-length gas and NGL sales and administrative costs from the calculation of allowances for certain OCS deepwater gathering. These administrative costs to industry totaled approximately $2.58 million annually.

Summary of Annual Administrative Impacts to Industry

Rule provision	Cost (cost savings)
Administrative Cost Savings for Index-Based Valuation Method for Gas & NGLs	(1,354,000)
Administrative Cost for Allowances for Certain OCS Deepwater Gathering	3,931,000
Total	2,577,000

ONRR also estimated industry will incur a one-time administrative cost savings of $4.5 million from the simplification of reporting processing and transportation allowances associated with the optional use of the index-based valuation method. These costs are only calculated by a lessee once to break out allowed from disallowed costs in reported processing and transportation allowances. Unless there is a significant change in processing and transportation costs, this ratio of allowed to disallowed costs should not change from year to year.

One-Time Administrative Impacts to Industry

Rule provision	Cost savings
Administrative Cost-Savings in Lieu of Unbundling Related to Index-Based Valuation Method for Gas & NGLs	$4,520,000

To perform this economic analysis on all the provisions adopted in this final rule, ONRR reviewed royalty data for Federal oil, condensate, residue gas, unprocessed gas, fuel gas, gas lost—flared or vented, carbon dioxide, sulfur, coalbed methane, and natural gas products (product codes 03, 04, 15, 16, 17, 19, 39, 07, 01, 02, 61, 62, 63, 64, and 65) from the five calendar years, 2014-2018. ONRR believes the majority of the reporting used in this analysis was made in compliance with the regulations in place prior to the 2016 Valuation Rule. ONRR used five calendar years of royalty data because this longer time period helped reduce volatility caused by fluctuations in commodity pricing and volume swings. ONRR used this data without adjusting for previous rulemakings because at the time of this analysis, a significant number of lessees and operators had not yet complied with the 2016 Valuation Rule's provisions due to its implementation delays, including the 2017 Repeal Rule, the subsequent 2019 Vacatur, and ONRR's two dear reporter letters providing industry with additional time to come into compliance with the 2016 Valuation Rule following its reinstatement. ONRR adjusted the historical data in this analysis to calendar year 2018 dollars using the Consumer Price Index (all items in U.S. city average, all urban consumers) published by the BLS. ONRR found that some companies aggregate their natural gas volumes from multiple leases into pools and sell that gas under multiple contracts. Lessees report those sales and dispositions using the “POOL” sales type code. Only a small portion of these gas sales are non-arm's-length. ONRR used estimates of 10 percent of the POOL volumes in the economic analysis of non-arm's-length sales and 90 percent of the POOL volumes in the economic analysis of arm's-length sales.

Change in Royalty 1: Using Index-Based Valuation Method To Value Arm's-Length Federal Unprocessed Gas, Residue Gas, Fuel Gas, and Coalbed Methane

To estimate the royalty impact of the option to pay royalties using the index-based valuation method, ONRR reviewed the reported royalty data for all Federal gas sales except for non-arm's-length (discussed below), future valuation agreements, and percentage of proceeds (“POP”) sales. ONRR also adjusted the POOL sales down to 90 percent (as described above), which were spread across 10 major geographic areas with active index prices. The 10 areas account for over 95 percent of all Federal gas produced. ONRR assumes the remaining five percent of Federal gas lessees will not elect the index-based method because areas outside of major producing basins may have infrastructure limitations or limited access to index pricing. The 10 geographic areas are:

Offshore Gulf of Mexico	Big Horn Basin	Green River Basin	Permian Basin	Piceance Basin
Powder River Basin	San Juan Basin	Uinta Basin	Williston Basin	Wind River Basin.

To calculate the estimated impact, ONRR:

(1) Identified the monthly bidweek price index, published by Platts Inside FERC, applicable to each area—Northwest Pipeline Rockies for Green River, Piceance and Uinta basins; El Paso San Juan for San Juan basin; Colorado Interstate Gas for Big Horn, Powder River, Williston, and Wind River basins; El Paso Permian for Permian basin; and Henry Hub for the GOM. ONRR determined the price index applicability based on proximity to the producing area and the frequency by which ONRR's audit and compliance staff verify these index prices in sales contracts.

(2) Subtracted the transportation deduction as modified by this rule (detailed in the transportation section below) from the midpoint index price identified in step (1).

(3) Multiplied the royalty volume by the index price identified per region, less the transportation deduction calculated in step (2).

(4) Totaled the reported royalties less allowances reported on the monthly royalty report (form ONRR-2014) and the estimated royalties based on the index-based valuation method calculated in step (3).

(5) Calculated the annual average of reported royalties and estimated index-based royalties calculated in step (4) by dividing by five (number of years of reported data in the analysis).

(6) Subtracted the difference between the totals calculated in step (5).

ONRR anticipates that some lessees will choose to value their royalties on natural gas sales reported to ONRR using this index-based valuation method, saving administrative costs (described in detail below in Cost Savings 1 and Cost Savings 2), while other lessees will continue to calculate and deduct the actual costs they incur. As discussed above in response to a comment, ONRR cannot precisely estimate how many lessees will elect to use the index-based valuation method since many factors, that are currently unquantifiable, will drive a lessee's decision. For the purposes of this analysis and for consistency with previous similar analyses, ONRR assumed that half of lessees would choose the index-based valuation method to value sales and dispositions eligible for the election. ONRR's assumption that half of lessees will choose this method is an attempt to simplify the countless number of factors such as, unpredictable natural gas price changes, simpler accounting methods for lessees, company-specific break-even analysis in producing regions, and unbundling administrative calculations. ONRR also isolated the GOM from the onshore basins listed above because it accounts for approximately 30 percent of the total Federal gas sales used in this analysis, as well as having different complexities, when compared to onshore areas.

ONRR estimates that the index-based valuation method will increase annual royalty payments on arm's-length unprocessed gas, residue gas, fuel gas, and coalbed methane by approximately $5.6 million. This estimate represents an average increase of approximately one percent, or $0.04 per MMBtu, based on an annualized royalty volume of 296,440,024 MMBtu. ONRR chose not to include POP sales in the above method because the sales are reported inclusive of the NGL value and net of transportation and processing costs. To capture the change in value associated with POP contracts, ONRR applied the $0.04 per MMBtu calculated above to the annualized royalty volume for arm's-length percent of proceeds (“APOP”) sales of 158,772,452 MMBtu. ONRR recognizes that it is not accounting for the value of APOP NGLs, however ONRR does not have a reasonable method to break out those components from the available data.

Annual Net Change in Royalties Paid Using Index-Based Method for Arm's-Length Gas Sales

	Gulf of Mexico	Onshore basins	Total
Annualized Reported Royalties	$235,065,000	$541,124,000	$776,189,000
Royalties Estimated using Index-Based Valuation Method	$250,183,000	$536,564,000	$786,747,000
Difference	$15,118,000	($4,560,000)	$10,558,000
Change per MMBtu	$0.18	($0.02)	$0.04
% Change	6%	(1%)	1%
Annualized POP Royalties using Index-Based Valuation Method			$682,000
Annual Net Change in Royalties Paid using Index-Based Valuation Method			$11,240,000
50% of Lessees Choose Index-Based Valuation Method			$5,620,000

Comments on the Analysis of this Amendment

Public Comment: A commenter stated that ONRR's assumption that half of lessees will choose to use the index-based valuation method is unreasonable and incorrectly overstates the estimated change in royalties.

ONRR Response: ONRR acknowledges the uncertainty associated with predicting the number of lessees who may elect to use the index-based valuation methods as the commenter suggests. One major factor a lessee must look at when deciding whether to elect the index-based valuation method for two consecutive years is a prediction of future natural gas pricing. It is difficult to accurately predict natural gas prices two years into the future at the precise levels required when so many market dynamics are at play. Current domestic natural gas prices have changed compared to recent years and fluctuate up and down regularly. Because of these unknowns and for consistency with previous similar analysis, including the 2016 Valuation Rule, ONRR will continue to use the assumption that half of lessees will adopt this method to provide a baseline of understanding for the impacts of the provision.

Public Comment: ONRR received a comment that claimed in the 2016 Valuation Rule's Preamble, valuing gas transactions based on the first arm's-length sale would result in administrative cost savings of $247,000 for industry. The commenter claims ONRR ignored these 2016 Valuation Rule calculations in the proposed rule when claiming that extending the index-based valuation method to all transactions reduces administrative burden.

ONRR Response: ONRR believes the commenter misunderstood the 2016 Valuation Rule analyses. In both the 2016 Valuation Rule and the 2020 Proposed Rule, using the index-based valuation method creates an administrative cost savings for lessees compared to using the first arm's-length sale made by an affiliate of the lessee.

Change in Royalties 2: Using the Index-Based Valuation Method To Value Arm's-Length Sales of Federal NGLs

Similar to the changes to Federal unprocessed gas, residue gas, pipeline fuel, and coalbed methane, a lessee will have the option to pay royalties on Federal NGLs using an index-based value less a processing allowance defined by regulation and be allowed an adjustment for transportation costs and fractionation costs, which account for the prices realized at the various NGL hubs. ONRR used the same 2014-2018 calendar years for all NGL sales except for non-arm's-length and future valuation agreements. ONRR also adjusted the POOL sales down to 90 percent (as described above). These sales were spread across the same 10 major geographic areas with active index prices for this analysis. To calculate the estimated royalty impact of the index-based valuation method on Federal NGLs, ONRR:

(1) Identified the Platts Oilgram Price Report Price Average Supplement (Platts Conway) or OPIS LP Gas Spot Prices Monthly (OPIS Mont Belvieu) for published monthly midpoint NGL prices per component applicable to each area—Platts Conway for Williston and Wind River basins; and OPIS Mont Belvieu non-TET for the Gulf of Mexico, Big Horn, Green River, Permian, Piceance, Powder River, San Juan, and Uinta basins. In ONRR's audit experience, OPIS' prices are used to value NGLs in contracts more frequently at Mont Belvieu, and Platts' prices are used more frequently at Conway.

(2) Calculated an NGL basket price (a weighted average price to group the individual NGL components to a weighted price), which were compared to the imputed price from the monthly royalty report. The baskets illustrate the difference in the gas composition between Conway, Kansas and Mont Belvieu, Texas. The NGL basket hydrocarbon allocations are:

Platts Conway Basket		OPIS Mont Belvieu Basket
Ethane-propane (EP mix)	40%	Ethane	42%
Propane	28%	Non-TET Propane	28%
Isobutane	10%	Non-TET Isobutane	6%
Normal Butane	7%	Normal Butane	11%
Natural Gasoline	15%	Natural Gasoline	13%

(3) Subtracted the current processing deductions, as well as fractionation costs and transportation costs referenced in the current regulations and published online at https://www.onrr.gov,, as shown in the table below from the NGL basket price calculated in step (2):

NGL Deduction

[$/gal]

	Gulf of Mexico	New Mexico	Other areas
Processing	$0.10	$0.15	$0.15
Transportation and Fractionation	0.05	0.07	0.12
Total ($/gal)	0.15	0.22	0.27

(4) Multiplied the royalty volume by the index price identified for each region, less the NGL deduction calculated in step (3).

(5) Totaled the royalty value less allowances reported on the monthly royalty report, and the estimated royalties based off the index-based valuation method calculated in step (4).

(6) Calculated the annual average of reported royalties and estimated index-based royalties calculated in step (5) by dividing by five (number of years in this analysis).

(7) Subtracted the difference between the totals calculated in step (6).

Because ONRR assumed that half of lessees would choose this option for eligible dispositions, ONRR reduced the total estimate by 50 percent in the following table. ONRR estimates that this change will increase annual royalty payments by approximately $21.1 million. This estimate represents an average increase of approximately 17 percent or $0.0894 per gallon, based on an annualized royalty volume of 475,257,250 gallons [($42,281,000/475,257,250 gal) = $0.0894/gal].

Annual Net Change in Royalties Paid Using Index-Based Valuation Method for Arm's-Length NGL Sales

	Gulf of Mexico	New Mexico	Other areas	Total
Annualized Reported Royalties	$74,438,000	$67,637,000	$70,072,000	$212,147,000
Royalties Estimated using Index-Based Valuation Method	$77,068,000	$66,397,000	$110,962,000	$254,428,000
Annual Net change in Royalties Paid using Index-Based Valuation Method for NGLs	$2,630,000	($1,240,000)	$40,891,000	$42,281,000
Change per Gallon	$0.0174	($0.0081)	$0.2439	$0.0894
% Change	3%	(2%)	37%	17%
50% of Lessees Choose the Index-Based Valuation Method				$21,141,000

Change in Royalties 3: Using the Average Index Price Versus the Highest Published Index Price To Value Non-Arm's-Length Federal Unprocessed Gas, Residue Gas, Coalbed Methane, and NGLs

As noted above, the index-based valuation method will change from using the highest published price for a specific index-pricing point to using the average published bidweek price for the index-pricing point. To estimate the royalty impact of this change from the highest published index price to the average published bidweek price for the index-based valuation method, ONRR used reported royalty data using non-arm's-length (“NARM”) sales and 10 percent of the POOL sales type codes based on the assumption above in the same 10 major geographic areas with active index-pricing points, also listed above.

To calculate the estimated impact, ONRR:

(1) Identified the Platts Inside FERC published monthly midpoint and high prices for the index applicable to each area— Northwest Pipeline Rockies for Green River, Piceance and Uinta basins; El Paso San Juan for San Juan basin; Colorado Interstate Gas for Big Horn, Powder River, Williston, and Wind River basins; El Paso Permian for Permian basin; and Henry Hub for the Gulf of Mexico.

(2) Multiplied the royalty volume by the published index prices identified for each region.

(3) Totaled the estimated royalties using the published index prices calculated in step (2).

(4) Calculated the annual average index-based royalties for both the high and volume-weighted-average prices calculated in step (3) by dividing by five (number of years in this analysis).

(5) Subtracted the difference between the totals calculated in step (4).

As explained in response to a comment above, ONRR assumes that half of lessees would choose this method, and ONRR therefore reduced the total estimate by 50 percent in the following table. ONRR estimates that the result of this change is a decrease in annual royalty payments of approximately $4.5 million. This estimate represents an average decrease of approximately three percent or ten cents ($0.10) per MMBtu, based on an annualized royalty volume of 93,301,478 MMBtu (for NARM and 10 percent POOL reported sales type codes).

Annual Change in Royalties Paid Due to High to Midpoint Modification for Non-Arm's-Length Sales of Natural Gas Using Index-Based Valuation Method

	Gulf of Mexico	Onshore basins	Total
Royalties Estimated Using High Index Price	$107,736,000	$198,170,000	$305,907,000
Royalties Estimated Using Published Average Bidweek Price	107,448,000	189,483,000	296,931,000
Annual Change in Royalties Paid due to High to Midpoint Change	(288,000)	(8,687,000)	(8,975,000)
Change per MMBtu	(0.01)	(0.14)	(0.10)
% Change	0%	(5%)	(3%)
50% of Lessees Choose the Index-Based Method			(4,488,000)

Change in Royalties 4: Modifying the Index-Based Valuation Method Transportation Deduction Used To Value Non-Arm's-Length Federal Unprocessed Gas, Residue Gas, Coalbed Methane, and NGLs

This rulemaking updates the transportation deductions applicable to the non-arm's-length index-based valuation method to reflect changes in industry's transportation contracts terms and more recent allowance data reported to ONRR. To estimate the royalty impact of the modification to the transportation deduction, ONRR used reported royalty data using NARM and 10 percent of the POOL sales type codes from the same 10 major geographic areas with active index-pricing points listed above.

To calculate the estimated impact, ONRR:

(1) Identified appropriate areas using Platts Inside FERC index prices (see list above).

(2) Calculated the transportation deduction as published in the current regulations and the deduction outlined in the table below for each area identified in step (1).

Transportation Deduction of Index-Based Valuation Method for Non-Arm's-Length Gas

[$/MMBtu]

Element	2016 valuation rule	2020 valuation reform and civil penalty rule
Gulf of Mexico %	5%	10%
Gulf of Mexico Low Limit	$0.10	$0.10
Gulf of Mexico High Limit	$0.30	$0.40
Other Areas %	10%	15%
Other Areas Low Limit	$0.10	$0.10
Other Areas High Limit	$0.30	$0.50

(3) Multiplied the royalty volume by the applicable transportation deduction identified for each area calculated in step (2).

(4) Totaled the estimated royalty impact based off both transportation deductions calculated in step (3).

(5) Calculated the annual average royalty impact for both methods calculated in step (4) by dividing by five (number of years in this analysis).

(6) Subtracted the difference between the totals calculated in step (5).

Because ONRR estimates that half of lessees will choose this option, ONRR reduced the total estimate by 50 percent. Please note that the figures in the table below represent the difference between the current transportation adjustment percentage found in the 2016 Valuation Rule and the percentage under the index-based valuation method in the 2020 Proposed Rule. ONRR estimates the change will result in a decrease in annual royalty payments of approximately $7.1 million. This estimate represents an average decrease in royalties paid of approximately 65 percent or 15 cents per MMBtu, based on an annualized royalty volume of 93,301,478 MMBtu (for NARM and 10 percent POOL reported sales type codes).

Annual Change in Royalties Due to Transportation Deduction Modification for Non-Arm's-Length Sales of Natural Gas

	Gulf of Mexico	Other areas	Total
Current Regulations Transport Deduction	$5,387,000	$16,375,000	$21,762,000
Estimate using new Transport Deduction	10,346,000	25,659,000	36,005,000
Difference	4,959,000	9,284,000	14,243,000
Change per MMBtu	0.15	0.15	0.15
50% of Lessees Choose the Index-Based Valuation Method			7,121,000
Annual Change in Royalties Due to Transportation Deduction Modification			(7,121,000)

Clarifying the description of the $0.04/MMBtu and $0.09/MMBtu: In the 2020 Proposed Rule, ONRR noted the estimated changes in royalties under the proposed index-based valuation method. Specifically, the preamble of the 2020 Proposed Rule (85 FR 62054, at 62058) provided, “As we outline in the Procedural Matters section, overall royalty values under the 2016 Valuation Rule's index-based valuation method are still around $0.04/MMBtu higher than the prices reported to ONRR for arm's-length sales. In the 2020 Proposed Rule, the average bidweek price would result in around $0.09 less per MMBtu.” This section was unclear, and should have provided, “As outlined in the Procedural Matters section, overall royalty values under the 2020 Valuation Rule's index-based valuation method are around $0.04/MMBtu higher than the prices reported to ONRR for arm's-length sales. For non-arm's-length dispositions valued under the proposed rule's index-based valuation method, using the average bidweek price instead of the bidweek high price would result in around $0.09 less per MMBtu” (emphasis added). This clarification does not affect the economic analyses conducted in the 2020 Proposed Rule and this final rule.

No Change in Royalties 1: Transportation Allowances in Excess of 50 Percent of the Royalty Value Prior to Allowances for Federal Gas

In certain scenarios, a lessee may incur costs to transport Federal gas at a cost that exceeds the regulatory limit of 50 percent of the gas's royalty value prior to allowances. This rule does not provide a lessee the ability to submit a request to ONRR to exceed the 50 percent limit. The annual number of requests to exceed allowance limits submitted by lessees to ONRR has decreased since the similar analysis was performed for the 2016 Valuation Rule. To estimate the change in royalties associated with the proposed amendment, ONRR first identified all gas transportation allowances reported on the monthly royalty reports exceeding the 50 percent limit for calendar years 2014-2018. Next, ONRR calculated the transportation allowance claimed for each royalty line compared to what the transportation allowance would have been at the 50 percent limit. ONRR then calculated annual totals and averaged them over 5 years. The result in the proposed rule was an estimated annual decrease in royalties paid by industry of approximately $279,000 per year. ONRR is not adopting this regulation change. There is no change in estimated royalties.

No Change in Royalties 2: Transportation Allowances in Excess of 50 Percent of the Royalty Value Prior to Allowances for Federal Oil

Similar to the section above, a lessee may incur costs to transport Federal oil that exceed the regulatory limit of 50 percent of the oil's royalty value prior to allowances. This rule does not provide a lessee the ability to request to exceed that limit. The annual number of requests to exceed allowance limits submitted by lessees to ONRR has decreased since the similar analysis was performed for the 2016 Valuation Rule. To estimate the change in royalties associated with the proposed amendment, ONRR first identified all oil transportation allowances reported on the monthly royalty report that exceeded the 50 percent limit for calendar years 2014-2018. As above, ONRR calculated the transportation allowance claimed for each royalty line compared to what the transportation allowance would have been at the 50 percent limit. ONRR then calculated annual totals and averaged them over five years. The result in the proposed rule was an annual estimated decrease in royalties paid by industry of approximately $11,000 per year. ONRR is not adopting this regulation change. There is no change in estimated royalties.

No Change in Royalties 3: Processing Allowances in Excess of 662/3 Percent of the Royalty Value of Federal NGLs Prior to Allowances

Similar to the transportation allowance amendments, a lessee may incur costs required to process gas that exceed the regulatory limit of 662/3 percent of the royalty value of the NGLs prior to allowances. This rule does not provide a lessee the ability to request to exceed that limit. The annual number of requests to exceed allowance limits submitted by lessees to ONRR has decreased since a similar analysis was performed for the 2016 Valuation Rule. To estimate the change in royalties associated with the proposed amendment, ONRR completed two separate calculations.

First ONRR identified all NGL processing allowances reported on the monthly royalty report that exceeded the 662/3 percent limit for calendar years 2014-2018. Next, ONRR calculated the processing allowance claimed for each royalty line compared to what the processing allowance would have been at the 662/3 percent limit. ONRR then calculated annual totals and averaged them over five years. The result in the proposed rule was an annual estimated decrease in royalties paid by industry of approximately $135,000 per year.

ONRR then calculated the estimated impact for processing allowances exceeding the 662/3 percent limit for POP contract sales. ONRR assumed the lessee retains 85 percent of the value of the residue and NGLs and the processor retains 15 percent. ONRR then assumed that 60 percent of the processor's portion was allocable to transportation and the remaining 40 percent was processing. The total estimated processing allowance attributable to POP sales was $62,390,000. The estimated processing allowance limit attributable to POP sales was $137,316,000. ONRR found the potential processing allowances did not exceed the 662/3 percent limit and there would be no additional change in royalties from POP contract sales. ONRR is not adopting this regulation change. There is no change in estimated royalties.

Comments on the Analysis of This Amendment

Public Comment: One commenter identified to ONRR that its assumption to use a 70/30 split to represent POP contracts when estimating processing allowances in excess of 662/3 percent limit contradicted other ONRR materials and examples used in trainings and on the ONRR website.

ONRR Response: ONRR reviewed several reference documents and further researched the appropriate split for these POP contracts and ONRR agrees with the commenter. ONRR acknowledges that its previous analysis did not adequately account for POP contracts and breaking out transportation and allowances from the fee in ONRR's assumptions. ONRR revised its POP contract analysis of this impact in this provision. After using the 85/15 POP contract split, as well as applying the 60/40 split for the processor's portion being allocable to processing versus transportation, the estimated allowances no longer exceed the 662/3 percent threshold and the estimated royalty impact is eliminated. This change is reflected below.

Change in Royalties 5: Extraordinary Gas Processing Cost Allowances for Federal Gas

This rule allows a lessee to request an extraordinary processing cost allowance. Using the approvals ONRR granted prior to the 2016 Valuation Rule, ONRR identified the 127 leases claiming an extraordinary processing allowance for residue gas, sulfur, and CO₂ for calendar years 2014-2018. The total processing costs are reported across all three products for these unique situations. For these leases, ONRR retrieved all form ONRR-2014 royalty lines with a processing allowance reported by lessees. For CO₂ and sulfur produced from these leases, ONRR then calculated the annual average processing allowances which exceeded the 662/3 percent limit and found that only two years in the analysis showed that the total allowances exceeded the 662/3 percent limit. Under these unique approved exceptions, the processing allowances are also reported against residue gas. To account for this, ONRR added the average annual processing allowances taken for those same leases for residue gas. Based on these calculations, ONRR estimates this change will result in a decrease in annual royalty payments of approximately $11.1 million.

Estimated Annual Change in Royalties Paid

Annual Average Sulfur allowances in excess of 662/3%	($348,000)
Annual Average Residue Gas Allowance	(10,783,000)
Estimated Impact on Royalties	(11,131,000)

Change in Royalties 6: Transportation Allowances for Certain OCS Gathering for Federal Oil and Gas

The Deepwater Policy was in effect from 1999 until January 1, 2017. Under the Deepwater Policy, ONRR allowed a lessee to treat certain expenses for subsea gathering as transportation expenses and to deduct a portion of those costs from its royalty payments. The 2016 Valuation Rule rescinded the Deepwater Policy. To analyze the impact to industry of this regulation amendment, ONRR used data from the BSEE's Technical Information Management System database to identify 113 current subsea pipeline segments, and potentially 169 eligible leases, which may qualify for an allowance under the Deepwater Policy. ONRR assumed that all segments were similar (in other words, no adjustments were made to account for the size, length, or type of pipeline) and considered only the pipeline segments that were in active status and supporting leases in producing status. To determine the range (shown in the tables at the end of this section as low, mid, and high estimates) of changes to royalties, ONRR estimates a 15 percent error rate in the identification of the 113 eligible pipeline segments. This resulted in a range of 96 to 130 eligible pipeline segments. ONRR's audit data is available for 13 subsea gathering segments serving 15 leases covering time periods from 1999 through 2010. ONRR used the data to determine an average initial capital investment in the pipeline segments. ONRR used the initial capital investment total to calculate depreciation and a return on undepreciated capital investment (also known as the return on investment or “ROI”) for eligible pipeline segments and calculated depreciation using a 20-year straight-line depreciation schedule.

ONRR calculated return on investment using the average BBB Bond rate (the BBB Bond rating is a credit rating used by the Standard & Poor's credit agency to signify a certain risk level of long-term bonds and other investments) for January 2018. ONRR based the calculations for depreciation and ROI on the first year a pipeline was in service. From the same audit information, ONRR calculated an average annual operating and maintenance (“O&M”) cost. ONRR increased the O&M cost by 12 percent to account for overhead expenses. ONRR then decreased the total annual O&M cost per pipeline segment by nine percent because, on average, nine percent of wellhead production volume is water which much be excluded from any calculation of a permissible deduction. ONRR chose these two percentages based on knowledge and information gathered during audits in the GOM. Finally, ONRR used an average royalty rate of 14 percent, which is the volume-weighted-average royalty rate for the non-Section 6 (See 43 U.S.C. 1335(a)(9)) leases in the Gulf of Mexico. Based on these calculations, the average annual allowance per pipeline segment during the period when ONRR's audit data was collected was approximately $233,000. ONRR used this value to calculate a per lease cost based on the number of eligible leases during the same period. ONRR then applied this value to the current number of eligible leases. This represents the estimated amount per lease that ONRR would allow a lessee to take as a transportation allowance based on the Deepwater Policy. To calculate a range for the total cost, ONRR multiplied the average annual allowance by the low (96), mid (113), and high (130) number of eligible segments. The low, mid, and high annual allowance estimates are $35 million, $41.1 million, and $47.3 million, respectively.

Of the eligible leases, 68 of 169, or about 40 percent, will qualify for a deduction under the proposed amendment. But due to varying lease terms, multiple royalty relief programs, price thresholds, volume thresholds, and other factors, ONRR estimated that half of the 68, or 34, leases eligible for royalty relief (20 percent of 169) have received royalty relief. ONRR chose to estimate half of lessees for consistency with previous rulemaking analyses and to provide a basis for understanding of this change. ONRR decreased the low, mid, and high annual cost-to-industry estimates by 20 percent. The table below shows this section's estimated royalty impact.

Annual Estimated Cost Savings To Allow Deepwater Gathering

	Low	Mid	High
Royalty Impact	$28,000,000	$32,900,000	$37,900,000

The 2020 Proposed Rule proposed to allow a lessee to request, and ONRR to approve, applications for gathering-as-transportation principles in water depths of 200 meters and shallower, if there is a subsea completion and the other requirements of the regulations are met. This provision was a part of the Deepwater Policy from its inception in 1999 until expressly revoked by the 2016 Valuation Rule. Neither MMS nor ONRR received any application to apply the Deepwater Policy to leases producing from OCS shallow waters. ONRR is not adopting this regulation change. There is no change in estimated royalties associated with gathering in depths 200 meters or shallower.

Comments on the Analysis of This Amendment

Public Comment: ONRR received a comment identifying what the commenter believed was an error in the calculation of the change in royalties related to transportation allowances for Deepwater gathering.

ONRR Response: ONRR appreciates this comment and investigated potential errors in the formulas and data used for the calculation. ONRR revised the analysis for deepwater gathering. During the review of the proposed rule, ONRR found that calculation steps were not explained fully and identified that ONRR's per segment value was overstated by nine percent attributable to the water content. ONRR also identified a miscalculation in the 2020 Proposed Rule that did not accurately incorporate a reduction to account for the 20 percent of leases that were eligible and receiving royalty relief. ONRR revised the explanation of the formula and the calculations accordingly and it is reflected in the section below.

Cost 1: Transportation Allowances for Certain OCS Gathering Costs for Offshore Federal Oil and Gas

This rule, by allowing transportation allowances for deepwater gathering systems, will result in an administrative cost to industry because it requires qualified lessees to monitor their costs and perform calculations. The cost to perform these calculations is significant because industry often hires outside consultants to calculate their subsea transportation allowances. ONRR estimates that each lessee with leases eligible for transportation allowances for deepwater gathering systems will allocate one full-time employee annually to perform the calculation. ONRR used data from the BLS to estimate the hourly cost for industry accountants in a metropolitan area [$42.33 mean hourly wage] with a multiplier of 1.4 for industry benefits to equal approximately $59.26 per hour [$42.33 × 1.4 = $59.26]. Using this fully-burdened labor cost per hour, ONRR estimates that the annual administrative cost to industry would be approximately $3.9 million.

Annual Administrative Cost to Industry To Calculate Deepwater Transportation

	Annual burden hours per company	Industry labor cost/ hour	Companies reporting eligible leases	Estimated cost to industry
Allowance for Certain OCS Deepwater Gathering Costs	2,080	$59.26	32	$3,931,000

No Administrative Cost 1: Request To Exceed Regulatory Allowance Limitation for Transportation and Processing

In the proposed rule ONRR recognized the opportunity for a lessee to request to exceed the regulatory allowance limitation would result in an administrative cost to industry because qualified lessees will spend labor hours filling out the necessary form (form ONRR-4393). ONRR previously completed an Information Collection Request that included review of this ONRR form and identified the number of annual requests ONRR received and the estimated burden hours attributed to those requests each year. Using this information, ONRR calculated the cost to be: [$42.33 × 1.4 (including employee benefits) = $59.26 calculated mean hourly wage] × [19 average annual requests] × [57.68 labor hours to complete and submit form ONRR-4393]. In the proposed rule, ONRR estimated annual administrative costs to industry of approximately $65,000 but those costs will not be realized as ONRR is not adopting this regulation change.

Annual Administrative Cost to Industry To Submit Requests To Exceed Allowance Limits

	Annual burden hours per company	Industry labor cost/ hour	Annual number of requests to exceed	Estimated cost to industry
Requests to Exceed Allowances	58	$59.26	19	$65,000

Cost Savings 1: Administrative Cost Savings From Using Index-Based Valuation Method To Value Federal Unprocessed Gas, Residue Gas, Fuel Gas, Coalbed Methane, and NGLs

ONRR expects that industry will realize administrative-cost savings if lessees choose to use the index-based valuation method to value sales of Federal unprocessed gas, residue gas, fuel gas, coalbed methane, and NGLs. A lessee will have price certainty when calculating its royalties—saving time it currently spends on verifying gross proceeds. ONRR estimates that half of lessees will use the index-based valuation method. Further, ONRR estimates that it will shorten the time burden per line reported by 50 percent (to 1.5 minutes per electronic line submission and 3.5 minutes per manual line submission). As with Cost 1, ONRR used tables from the BLS to estimate the fully-burdened hourly cost for an industry accountant in a metropolitan area working in oil and gas extraction. The industry labor cost factor for accountants would be approximately $59.26 per hour = [$42.33 (mean hourly wage) × 1.4 (including employee benefits)]. Using a labor cost factor of $59.26 per hour, ONRR estimates the annual administrative cost savings to industry will be approximately $1.4 million.

Annual Administrative Cost Savings for Industry

	Time burden per line reported	Estimated lines reported using index- based valuation method (50%)	Annual burden hours
Electronic Reporting (99%)	1.5 min	892,620	22,315
Manual Reporting (1%)	3.5 min	9,016	526
Industry Labor Cost/hour			$59.26
Total Benefit to Industry			$1,354,000

Cost Savings 2: Administrative Cost Savings Using Index-Based Valuation Method To Value Residue Gas and NGLs Simplifying Processing and Transportation Cost Calculations

ONRR expects industry will realize an additional one-time administrative-cost savings if they choose to use the index-based valuation method to value sales of Federal residue gas and NGLs, as this method eliminates the need to unbundle and calculate specific cost allocations related to processing and transportation. These cost allocations, referred to as “unbundling,” are segregated portions of a transportation or processing expense or fee attributable to placing production in marketable condition. Industry would unbundle their applicable plants and transportation systems one time in the absence of this rule and then use those unbundled cost allocations for subsequent royalty calculations. Industry is responsible for calculating these costs, however ONRR has published and calculated a limited number of unbundling cost allocations. In ONRR's experience, it takes approximately 100 hours per gas plant. ONRR calculated the average number of gas plants reported per payor is 3.4, across a total of 448 payors reporting residue gas and NGLs, between 2014-2018. Using the BLS labor cost per hour of $59.26 (described above) and adjusting the assumption to half of lessees choosing the index-based valuation method, ONRR believes this results in a one-time cost savings to industry of $4.5 million dollars.

Change 1: Eliminate Reference To Default Provision Requirements for Federal Oil and Gas

ONRR proposed to remove the default provision from its regulations. In instances of misconduct, breach of a lessee's duty to market, or other situations where royalty value cannot be determined under the rules, ONRR will use statutory authority to determine Federal oil and gas royalty value under lease terms, FOGRMA, and other authorizing legislation in the same manner—as ONRR would have prior to adoption of the 2016 Valuation Rule. ONRR does not believe there is any overall royalty impact from removing the default provision.

State and Local Governments

ONRR estimates that States and certain local governments would receive an overall decrease in royalty share (which, in part, was a reason for California's and New Mexico's challenges to the 2017 Repeal Rule) based on the category the leases falls under, including offshore OCSLA section 8(g) leases (See 43 U.S.C. 1337(g)), Gulf of Mexico Energy Security Act leases (“GOMESA”) ((43 U.S.C. 1337(g))), and onshore Federal lands. ONRR disburses royalties based on where the oil, gas, or coal was produced.

Except for Federal Alaskan production (where Alaska receives 90 percent of the distribution), Section 8(g) leases in the OCS, and qualified leases under GOMESA in the OCS (more information on distribution percentages at https://revenuedata.doi.gov/​how-it-works/​gomesa/​), the following distribution table generally applies:

ONRR Disbursements by Area

	Onshore (%)	Offshore (%)
Federal	51	95.2
State	49	4.8

Please visit https://revenuedata.doi.gov/​explore/​#federal-disbursements to find more information on ONRR's disbursements to any specific State or local government.

The next table in this section summarizes the State and local government royalty decreases.

Indian Lessors

The provisions affecting royalties in this rule only apply to Federal oil and gas leases and are not expected to affect Indian lessors.

Federal Government

The impact of this rule to the Federal Government will be a net decrease in royalty collections. ONRR estimates the net yearly impact on the Federal Government (detailed in the next table of this section) would be a loss of $22,728,000 in royalties and the net effect to the Federal Government and the States would be a loss of $28,879,000 in combined royalties.

Summary of Royalty Impacts and Costs to Industry, State and Local Governments, Indian Lessors, and the Federal Government

In the table below, ONRR presents the net change in royalties by this rulemaking provision. Changes to royalties are neither costs nor benefits, but transfers. The estimated changes in royalties assessed will change both the costs incurred by an operator/lessee and the amount of revenue collected by the Federal Government and the States.

Annual Economic Impacts for Industry, the Federal Government, and States

Rule provision	Net change in royalties	Federal portion	State portion
Index-Based Valuation Method Extended to Arm's-Length Gas Sales	$5,620,000	$3,562,000	$2,058,000
Index-Based Valuation Method Extended to Arm's-Length NGL Sales	21,141,000	14,248,000	6,893,000
High to Midpoint Index Price for Non-Arm's-Length Gas Sales	(4,488,000)	(2,844,000)	(1,644,000)
Transportation Deduction Non-Arm's-Length Index-Based Valuation Method	(7,121,000)	(4,513,000)	(2,608,000)
Extraordinary Processing Allowance	(11,131,000)	(7,054,000)	(4,077,000)
Allowance for Certain OCS Gathering Costs	(32,900,000)	(26,127,000)	(6,773,000)
Total	(28,879,000)	(22,728,000)	(6,151,000)
Note: Totals may not add due to rounding.

Federal and Indian Coal

ONRR estimates that there will be no economic impact in terms of royalties to ONRR, Tribes, individual Indian mineral owners, States, or industry from the changes to coal valuation in this rule. The changes outlined in this rule should result in coal values for royalty purposes similar to those reported and paid to ONRR under the regulations in effect since 1989. Further, as of this writing, lessees have not submitted coal reporting under the 2016 Valuation Rule, so ONRR lacks data showing any changes resulting from implementation of the provisions of the 2016 Valuation Rule.

Change 2: Eliminating the Use of Arm's-Length Electricity Sales To Value Non-Arm's-Length Dispositions of Federal Coal

Comments on the Analysis of This Amendment

Public Comment: ONRR received comments on this amendment expressing concerns about a potential loophole where companies may be able to pay royalties on prices below fair market value.

ONRR Response: ONRR appreciates the comment on this amendment but the commenter does not provide ONRR with enough information or evidence to calculate an economic impact of the loophole mentioned.

In the 2016 Valuation Rule, ONRR estimated no impacts to industry for this provision. Further, because lessees have not submitted reporting under the 2016 Valuation Rule, ONRR lacks data showing any changes that may have been attributable to this provision.

Change 3: Using the First Arm's-Length Sale To Value Non-Arm's-Length Sales of Indian Coal

ONRR did not estimate any impacts to industry for the proposed change from this provision. Currently, lessees of Indian coal sell their entire production at arm's-length, so this proposed change would have no royalty impact on lessees or lessors of Indian coal.

Change 4: Eliminating the Sales of Electricity To Value Non-Arm's-Length Sales of Indian Coal

ONRR did not estimate any impacts to industry for the proposed change for this provision. Currently, lessees of Indian coal sell their entire production at arm's-length so this proposed change would have no royalty impact on lessees or lessors of Indian coal.

Change 5: Using First Arm's-Length Sale To Value Sales of Indian Coal Between Parties That Lack Opposing Economic Interests

At the present time, all producers of Indian coal sell the produced coal under arm's-length transactions. Accordingly, ONRR does not anticipate any impact to royalty collections from the proposed change.

Change 6: Elimination of the Default Provision To Value Federal Oil, Gas, and Coal and Indian Coal

ONRR estimates that the royalty impact would be insignificant because the default provision established a reasonable value of production using market-based transaction data, which has always been, and continues to be, the basis for ONRR's royalty valuation rules.

VI. Severability Statement

If any provision, or portion of a provision, of this rule is found, by a court or tribunal of competent jurisdiction, to be invalid under the law, it shall be regarded as stricken while the remainder of this rule shall continue to be in full effect.

VII. Procedural Matters

A. Regulatory Planning and Review (E.O. 12866 and 13563)

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. OIRA has determined that this final rule is significant. Because the primary effect is on royalty payments, ONRR expects this final rule will largely result in transfers, which are described in the table below. ONRR also anticipates that this rule will result in $2.58 million in annual administrative costs and $4.52 million in one-time administrative cost savings.

Summary of Proposed Changes to Oil & Gas Royalties Paid

[Annual]

Rule provision	Net change in royalties paid by lessees
Index-Based Valuation Method Extended to Arm's-Length Gas Sales	$5,620,000
Index-Based Valuation Method Extended to Arm's-Length NGL Sales	21,141,000
High to Midpoint Index Price for Non-Arm's-Length Gas Sales	(4,488,000)
Transportation Deduction Non-Arm's-Length Index-Based Valuation Method	(7,121,000)
Extraordinary Processing Allowances	(11,131,000)
Allowance for Certain OCS Gathering Costs	(32,900,000)
Total	(28,879,000)

Summary of Annual Administrative Impacts to Industry

Rule provision	Cost (Cost savings)
Administrative Cost Savings for Index-Based Valuation Method for Arm's-Length Gas & NGL Sales	($1,354,000)
Administrative Cost for Allowances for Certain OCS Gathering	3,931,000
Total	2,577,000

One-Time Administrative Impacts to Industry

Rule provision	(Cost savings)
Administrative Cost-savings in lieu of Unbundling related to Index-Based Valuation Method for ARMS Gas & NGLs	($4,520,000)

Net Present Value of Administrative Impacts to Industry

Time horizon	3% Discount rate	7% Discount rate
Administrative Costs over 10 years	$18,100,000	$14,800,000
Administrative Costs over 20 years	35,000,000	24,700,000

To estimate the present value of potential future administrative cost to industry, ONRR looked at two different potential time periods to represent various production lives of oil and gas leases. ONRR applied three percent and seven percent discount rates as described in OMB Circular A-4, using a base year of 2021 and reported in 2020 dollars. As described above, ONRR estimates a cost savings to industry in the first year this regulation is in effect and administrative costs each year thereafter.

E.O. 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. E.O. 13563 directs agencies to consider regulatory approaches that reduce burdens and maintain flexibility and freedom of choice for the public where these approaches are relevant, feasible, and consistent with regulatory objectives. E.O. 13563 emphasizes further that regulations must be based on the best available science and that the rulemaking process must allow for public participation and an open exchange of ideas. ONRR developed this rule in a manner consistent with these requirements.

B. Regulatory Flexibility Act

The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) generally requires Federal agencies to prepare a regulatory flexibility analysis for rules that are subject to the notice-and-comment rulemaking requirements under the Administrative Procedure Act (5 U.S.C. 553), if the rule would have a significant economic impact on a substantial number of small entities. See 5 U.S.C. 601-612.

For the changes to 30 CFR part 1206, this rule would affect lessees of Federal oil and gas leases. For the changes to 30 CFR part 1241, this rule could affect violators of obligations under Federal and Indian mineral leases. Federal and Indian mineral lessees are, generally, companies classified under the North American Industry Classification System (“NAICS”), as follows:

• Code 211111, which includes companies that extract crude petroleum and natural gas;
• Code 212111, which includes companies that extract surface coal; and
• Code 212112, which includes companies that extract underground coal.

Under NAICS code classifications, a small company is one with fewer than 500 employees. ONNR updated its count since the 2020 Proposed Rule to estimate that approximately 1,208 different companies submit royalty reports from Federal oil and gas leases and other Federal mineral leases to ONRR each month. Of these, approximately 106 companies are not considered small businesses because they exceed the employee count threshold established for small businesses. ONRR estimated that the remaining 1,102 companies affected by this rule are small businesses. Accordingly, ONRR has not changed its initial determination from the 2020 Proposed Rule that this rule will have an impact on a substantial number of small entities, but the economic impact on those small entities will not be significant.

As stated in the Summary of Royalty Impacts and Costs Table, shown above, this rule would benefit industry through a reduction in royalties of approximately $28.9 million per year. Small businesses account for about 8 percent of the royalties. Applying that percentage to industry costs, ONRR estimated that the changes in the final rule would result in a private cost savings to small business lessees of approximately $2.3 million per year, or $2,087 per small business, on average. The extent of an economic impact, if any, would vary between companies due to, for example, differences in the volume of production that the small business produces and sells each year. Furthermore, this rule does not require any business to incur new costs. Instead, this rule provides businesses with more flexibility as each entity, including small businesses, are able to determine whether it is economically advantageous to incur increases in administrative costs to reduce the royalties paid, based on an entity's individual circumstances. ONRR believes that the economic impact to small businesses, if any, will be minimal. Accordingly, this rule will not result in a significant economic impact on those small businesses.

In accordance with 5 U.S.C. 605, ONRR hereby certifies that this rule will not have a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act. Thus, ONRR did not prepare a Regulatory Flexibility Act Analysis nor is a Small Entity Compliance Guide required.

C. Small Business Regulatory Enforcement Fairness Act

This final rule is not a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act. This rule:

(a) Does not have an annual effect on the economy of $100 million or more. ONRR estimates that the cumulative effect on all of industry will be a reduction in private cost of nearly $26.32 million per year, which is the sum of $28.9 million in decreased royalty payments and $2.58 million in additional costs due to increased administrative burdens. The net change in royalty payments is a transfer rather than a cost or cost savings. The Summary of Royalty Impacts and Costs Table, as shown above, demonstrates that the cumulative economic impact on industry, State and local governments, and the Federal Government will be well below the $100 million threshold that the Federal Government uses to define a rule as having a significant impact on the economy.

(b) Will not cause a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions. Please see the data tables in the Regulatory Planning and Review (E.O.s 12866 and 13563) section above.

(c) Does not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of United States-based enterprises to compete with foreign-based enterprises. This rule is, in part, meant to incentivize domestic energy production. ONRR has estimated no significant adverse impacts to small business.

D. Unfunded Mandates Reform Act

The final rule does not impose an unfunded mandate on State, local, or Tribal governments, or the private sector of more than $100 million per year. This rule does not have a significant or unique effect on State, local, or Tribal governments, or the private sector. Therefore, ONRR is not required to provide a statement containing the information that the Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq.) requires because this rule is not an unfunded mandate.

E. Takings (E.O. 12630)

Under the criteria in section 2 of E.O. 12630, the final rule does not have any significant takings implications. This rule does not impose conditions or limitations on the use of any private property. This rule applies to the valuation of Federal oil and gas and Federal and Indian coal only. The final rule only makes minor technical changes to ONRR's civil penalty regulations that have no expected economic impact. The final rule does not require a takings implication assessment.

F. Federalism (E.O. 13132)

Under the criteria in section 1 of E.O. 13132, the final rule does not have sufficient Federalism implications to warrant the preparation of a Federalism summary impact statement. The management of Federal oil and gas is the responsibility of the Secretary, and ONRR distributes all of the royalties that it collects under Federal oil and gas leases as directed by the relevant disbursement statutes. This rule does not impose administrative costs on States or local governments. This rule also does not substantially and directly affect the relationship between the Federal and State governments. Because this rule does not alter that relationship, it does not require a Federalism summary impact statement.

G. Civil Justice Reform (E.O. 12988)

The final rule complies with the requirements of E.O. 12988. Specifically, this 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 all regulations be written in clear language using clear legal standards.

H. Consultation With Indian Tribal Governments (E.O. 13175)

The Department strives to strengthen its government-to-government relationship with Indian tribes through a commitment to consultation with Indian tribes and recognition of their right to self-governance and tribal sovereignty. ONRR evaluated this final rule under the Department's consultation policy and under the criteria in E.O. 13175 and have determined that it has no substantial direct effects on Federally-recognized Indian tribes. Thus, consultation under the Department's tribal consultation policy is not required.

ONRR reached this conclusion, in part, based on the consultations it conducted before the adoption of the 2016 Valuation Rule. At that time, ONRR held six tribal consultations with the three tribes (Navajo Nation, Crow Nation, and Hopi Tribe) for which ONRR collected and disbursed Indian coal royalties. Upon the conclusion of each consultation, ONRR and the tribal partners determined that the 2016 Valuation Rule would have no substantial impact on any of the potentially impacted tribes. With the exception of the Kayenta Mine located in Navajo Nation, which ceased production in 2019, the circumstances relevant to the Indian coal leases have not changed since the prior consultations occurred. As with the 2016 Valuation Rule, ONRR's review of the royalty impact to tribes from this rulemaking concludes that there is no substantial impact to the three tribes. Further, this rule estimates no impact to the royalty value of Indian coal.

I. Paperwork Reduction Act (44 U.S.C. 3501 et seq.)

Certain collections of information require OMB's approval under the Paperwork Reduction Act. This final rule does not require any new information collections subject to OMB's approval. Thus, ONRR has not submitted any new information collection requests to OMB related to this rule.

The final rule leaves intact the information collection requirements that OMB has already approved under OMB Control Numbers 1012-0004, 1012-0005, and 1012-0010.

J. National Environmental Policy Act

This final rule does not constitute a major Federal action significantly affecting the quality of the human environment. ONRR is not required to provide a detailed statement under the National Environmental Policy Act of 1969 (“NEPA”) because this rule qualifies for a categorical exclusion under 43 CFR 46.210(c) and (i) and the Department's Departmental Manual, part 516, section 15.4.D: “(c) Routine financial transactions including such things as . . . audits, fees, bonds, and royalties . . . [and] (i) [p]olicies, directives, regulations, and guidelines . . . [t]hat are of an administrative, financial, legal, technical, or procedural nature.” ONRR also determined that this rule does not involved in any of the extraordinary circumstances listed in 43 CFR 46.215 that require further analysis under NEPA.

K. Effects on the Energy Supply (E.O. 13211)

This final rule is not a significant energy action under the definition in E.O. 13211. It is not likely to have a significant adverse effect on the supply, distribution, or use of energy. Moreover, the Administrator of OIRA has not otherwise designated this action as a significant energy action. A Statement of Energy Effects pursuant to E.O. 13211, therefore, is not required.

L. Clarity of This Regulation

E.O.s 12866 (section 1(b)(12)), 12988 (section 3(b)(1)(B)), and 13563 (section 1(a)), and the Presidential Memorandum of June 1, 1998, require ONRR to write all rules in plain language. This means that the rules ONRR publishes must use:

(a) Logical organization.

(b) Active voice to address readers directly.

(c) Clear language rather than jargon.

(d) Short sections and sentences.

(e) Lists and tables wherever possible.

If you believe that ONRR has not met these requirements, send your comments to [e-mail]. To better help ONRR understand your comments, please make your comments as specific as possible. For example, you should tell ONRR the numbers of the sections or paragraphs that you think were written unclearly, the sections or sentences that you think are too long, and the sections for which you believe lists or tables would be useful.

M. Congressional Review Act

Pursuant to the Congressional Review Act, 5 U.S.C. 801 et seq., OIRA has determined that this rulemaking is not a major rulemaking, as defined by 5 U.S.C. 804(2), because this rulemaking has not resulted in, and is unlikely to result in: (1) An annual effect on the economy of $100,000,000 or more; (2) a major increase in costs or prices for consumers, individual industries, Federal, State, or local government, or geographic regions; or (3) significant adverse effects on competition, employment, investment, productivity, innovation, or on the ability of United States-based enterprises to compete with foreign-based enterprises in domestic and export markets.

List of Subjects

30 CFR Part 1206

• Coal
• Continental shelf
• Geothermal energy
• Government contracts
• Indians-lands
• Mineral royalties
• Oil and gas exploration
• Public lands-mineral resources
• Reporting and recordkeeping requirements

30 CFR Part 1241

• Administrative practice and procedure
• Coal
• Geothermal energy
• Indians-lands
• Mineral royalties
• Natural gas
• Oil and gas exploration
• Penalties
• Public lands-mineral resources

Kimbra G. Davis,

Director for Office of Natural Resources Revenue.

Authority and Issuance

For the reasons discussed in the preamble, the Office of Natural Resources Revenue is amending 30 CFR parts 1206 and 1241 as set forth below:

PART 1206—PRODUCT VALUATION

1. 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.

Subpart A—General Provisions and Definitions

2. Amend § 1206.20 by:

a. Removing the definition of “coal cooperative”;

b. Revising the definition of “gathering”; and

c. Removing the definition of “misconduct”.

The revision reads as follows:

§ 1206.20

What definitions apply to this part?

* * * * *

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. Excluded from this definition is the movement of bulk production from a wellhead to an offshore platform which may, for valuation purposes, be considered a function for which a Transportation Allowance is properly taken pursuant to §§ 1206.110(a)(1) and 1206.152(a)(1).

* * * * *

Subpart C—Federal Oil

3. Amend § 1206.101 by:

a. Revising paragraphs (a) introductory text, (c)(1) introductory text, and (c)(1)(i); and

b. Adding paragraph (d).

The revisions and addition read as follows:

§ 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 one of the exceptions in paragraph (d) of this section applies. You must use this paragraph (a) to value oil when:

* * * * *

(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.

(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 require you to value the oil under § 1206.102. You may not otherwise use the price or differential specified in an arm's-length exchange agreement to value your production.

* * * * *

(d) This paragraph contains exceptions to the valuation rule in paragraph (a) of this section. Apply these exceptions on an individual contract basis.

(1) In conducting reviews and audits, if ONRR determines that any arm's-length sales contract does not reflect the total consideration actually transferred either directly or indirectly from the buyer to the seller, ONRR may require that you value the oil sold under that contract either under § 1206.102 or at the total consideration received.

(2) You must value the oil under § 1206.102 if ONRR determines that the value under paragraph (a) of this section does not reflect the reasonable value of the production due to either:

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

(ii) Breach of your duty to market the oil for the mutual benefit of yourself and the lessor.

4. Amend § 1206.102 by revising the introductory text and paragraphs (d) and (e) to read as follows:

§ 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. 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) with ONRR's approval.

* * * * *

(d) Unreasonable value. If ONRR determines that the NYMEX price or ANS spot price does not represent a reasonable royalty value in any particular case, ONRR may establish a reasonable royalty value based on other relevant matters.

(e) Production delivered to your refinery and the NYMEX price or ANS spot price is an unreasonable value. (1) Instead of valuing your production under paragraph (a), (b), or (c) of this section, you may apply to ONRR to establish a value representing the market at the refinery if:

(i) You transport your oil directly to your or your affiliate's refinery, or exchange your oil for oil delivered to your or your affiliate's refinery; and

(ii) You must value your oil under this section at the NYMEX price or ANS spot price; and

(iii) You believe that use of the NYMEX price or ANS spot price results in an unreasonable royalty value.

(2) You must provide adequate documentation and evidence demonstrating the market value at the refinery. That evidence may include, but is not limited to:

(i) Costs of acquiring other crude oil at or for the refinery;

(ii) How adjustments for quality, location, and transportation were factored into the price paid for other oil;

(iii) Volumes acquired for and refined at the refinery; and

(iv) Any other appropriate evidence or documentation that ONRR requires.

(3) If ONRR establishes a value representing market value at the refinery, you may not take an allowance against that value under § 1206.113(b) unless it is included in ONRR's approval.

5. Amend § 1206.104 by revising paragraphs (a)(1), (b), (c) introductory text, (c)(2), (g)(1), and (2) to read as follows:

§ 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 establish a reasonable royalty value based on other relevant matters.

* * * * *

(b) ONRR may examine whether your or your affiliate's contract reflects the total consideration transferred for Federal oil, either directly or indirectly, from the buyer to you or your affiliate. If ONRR determines that additional consideration beyond that reflected in the contract was transferred, or that any portion of the consideration was not included in gross proceeds reported, ONRR may establish a reasonable royalty value based on other relevant matters.

(c) ONRR may establish a reasonable royalty value based on other relevant matters if ONRR determines that the gross proceeds accruing to you or your affiliate under a contract do not reflect reasonable consideration because:

* * * * *

(2) You have breached your duty to market the oil for the mutual benefit of yourself and the lessor; or

* * * * *

(g)(1) You or your affiliate must make all contracts, contract revisions, or amendments in writing.

(2) If you or your affiliate fail(s) to comply with paragraph (g)(1) of this section, ONRR may establish a reasonable royalty value based on other relevant matters.

* * * * *

§ 1206.105

[Removed and Reserved]

6. Remove and reserve § 1206.105.

7. Amend § 1206.108 by:

a. Revising paragraphs (a) introductory text and (a)(5); and

b. Removing the words “Assistant Secretary” in paragraphs (c)(2), (c)(3), (d)(1), (e), (f), and (g) and adding in their place the words “Assistant Secretary for Policy, Management and Budget”.

The revisions read as follows:

§ 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 comply with all of the following:

* * * * *

(5) Provide your analysis of the issue(s);

* * * * *

8. Amend § 1206.110 by revising paragraphs (a), (f) introductory text and (f)(2) to read as follows:

§ 1206.110

What general transportation allowance requirements apply to me?

(a)(1) 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:

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

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

(2) You may not include any gathering costs in your transportation allowance under § 1206.110, 1206.111, or 1206.112, as applicable, except those reasonable, actual gathering costs you incur for oil produced from a lease or unit on the OCS, any part of which lies in waters deeper than 200 meters, that meet all of the following criteria:

(i) The gathering costs are for oil for which you are entitled to take a transportation allowance under paragraph (a)(1) of this section;

(ii) The gathering costs are for movement of oil beyond a central accumulation point. For purposes of paragraph (a)(2) of this section, a central accumulation point may be a single well, a subsea manifold, the last well in a group of wells connected in a series, or a platform extending above the surface of the water;

(iii) The gathering costs are for movement of oil to a facility that is not located on a lease or unit adjacent to the lease or unit on which the production originates. For purposes of paragraph (a)(2) of this section, an adjacent lease or unit is any lease or unit with at least one point of contact with the producing lease or unit. Typically, for a single OCS lease, there are 8 adjacent leases; and

(iv) The gathering costs are only those allocable to the royalty-bearing oil. Gathering costs properly allocable to non-royalty bearing substances, or any royalty-bearing substance other than oil, may not be included in your transportation allowance under this section.

* * * * *

(f) ONRR may direct you to modify your transportation allowance if:

* * * * *

(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; or

* * * * *

9. Amend § 1206.111 by:

a. Removing paragraph (d)(1)

b. Redesignating paragraph (d) introductory text as (d)(1);

c. Revising newly redesignated paragraph (d)(1); and

d. Removing the word “may” in paragraph (d)(2) and adding in its place the word “must”.

The revision reads as follows:

§ 1206.111

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

* * * * *

(d)(1) If you have no written contract for the arm's-length transportation of oil, you must propose to ONRR a method to determine the allowance using the procedures in § 1206.108(a).

* * * * *

10. Amend § 1206.117 by revising paragraph (a) to read as follows:

§ 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 without obtaining ONRR's prior approval under § 1206.110(d)(2), 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 file an exception request that ONRR approves. If you do not file an exception request, or if ONRR does not approve your request, you must pay late payment interest on the excess allowance amount taken from the date that amount is taken until the date you pay the additional royalties owed.

* * * * *

Subpart D—Federal Gas

11. Amend § 1206.141 by:

a. Revising paragraphs (a)(2), (b) introductory text, (b)(2), (b)(3), (c) introductory text, (c)(1)(i), (c)(1)(ii), (c)(1)(iv), (c)(1)(vi), and (e)(2) introductory text;

b. Removing the word “may” in paragraph (e)(2)(ii) and adding in its place the word “must”; and

c. Adding paragraphs (f) and (g).

The revisions and additions read as follows:

§ 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) * * *

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

* * * * *

(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. Unless you elect to value your gas under paragraph (c) of this section, you must use this paragraph (b) to value gas when:

* * * * *

(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;

(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. 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

* * * * *

(c) Alternatively, you may elect to value your unprocessed gas under this paragraph (c), which allows you to use an index-based valuation method to calculate royalty value. 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 published average bidweek price to which your gas may flow for that respective 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 of the published average bidweek prices to which your gas may flow for that respective production month, whether or not there are constraints for that production month.

* * * * *

(iv) You may adjust the number calculated under paragraphs (c)(1)(i) and (ii) of this section by reducing the value by 10 percent, but not less than 10 cents per MMBtu nor more than 40 cents per MMBtu for sales from the OCS Gulf of Mexico and by 15 percent, but not less than 10 cents per MMBtu nor more than 50 cents per MMBtu, for sales from all other areas.

* * * * *

(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 criteria for index pricing points available at www.onrr.gov.

* * * * *

(e) * * *

(2) There is not an index pricing point for the gas, then:

* * * * *

(f) Under no circumstances may your gas be valued for royalty purposes at less than zero.

(g) If you elect to value your gas under paragraph (c) of this section, ONRR reserves the right to collect actual transaction data in the future to assess the validity of the index-based valuation option.

12. Amend § 1206.142 by:

a. Revising paragraphs (c) introductory text, (c)(2), (c)(3), (d)(1)(i), (d)(1)(ii), (d)(1)(iv), and (d)(1)(vi);

b. Removing the word “methodology” from paragraph (d)(2)(ii) and adding in its place the word “method”;

c. Removing the word “may” in paragraph (d)(2)(iii) and adding in its place the word “must”;

d. Revising paragraph (f)(2) introductory text;

e. Removing the word “may” in paragraph (f)(2)(ii) and adding in its place the word “must”; and

f. Adding paragraphs (g) and (h).

The revisions and additions read as follows:

§ 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?

* * * * *

(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. Unless you exercise the option provided in paragraph (d) of this section, you must use this paragraph (c) to value residue gas or any gas plant product when:

* * * * *

(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;

(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, 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

* * * * *

(d) Alternatively, 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 published average bidweek price to which your gas may flow for that respective 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 of the published average bidweek prices to which your gas may flow for that respective production month, whether or not there are constraints for that production month.

* * * * *

(iv) You may adjust the number calculated under paragraphs (d)(1)(i) and (ii) of this section by reducing the value by 10 percent, but not less than 10 cents per MMBtu nor more than 40 cents per MMBtu for sales from the OCS Gulf of Mexico and by 15 percent, but not less than 10 cents per MMBtu nor more than 50 cents per MMBtu for sales from all other areas.

* * * * *

(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 criteria for index pricing points on www.onrr.gov.

* * * * *

(f) * * *

(2) There is not an index pricing point or commercial price bulletin for the gas, then:

* * * * *

(g) Under no circumstances may your gas be valued for royalty purposes at less than zero.

(h) If you elect to value your gas under paragraph (d) of this section, ONRR reserves the right to collect actual transaction data in the future to assess the validity of the index-based valuation option.

13. Amend § 1206.143 by revising paragraphs (a)(1), (b), (c) introductory text, (c)(2), (g)(1), and (g)(2) to read as follows:

§ 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.

* * * * *

(b) ONRR may examine whether your or your affiliate's contract reflects the total consideration transferred for Federal gas, either directly or indirectly, from the buyer to you or your affiliate. If ONRR determines that additional consideration beyond that reflected in the contract was transferred, or that any portion of the consideration was not included in gross proceeds reported, ONRR may establish a reasonable royalty value based on other relevant matters.

(c) ONRR may direct you to use a different measure of royalty value if ONRR determines that the gross proceeds accruing to you or your affiliate under a contract do not reflect reasonable consideration because:

* * * * *

(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; or

* * * * *

(g)(1) You or your affiliate must make all contracts, contract revisions, or amendments in writing.

(2) If you or your affiliate fail(s) to comply with paragraph (g)(1) of this section, ONRR may direct you to use a different measure of royalty value.

* * * * *

§ 1206.144

[Removed and Reserved]

14. Remove and reserve § 1206.144.

15. Amend § 1206.148 by:

a. Revising paragraphs (a) introductory text and (a)(5); and

b. Removing the words “Assistant Secretary” in paragraphs (c)(2), (c)(3), (d)(1), (e), and (f) and adding in their place the words “Assistant Secretary for Policy, Management and Budget”.

The revisions read as follows:

§ 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 comply with all of the following:

* * * * *

(5) Provide your analysis of the issue(s);

* * * * *

16. Amend § 1206.152 by revising paragraph (a), (g) introductory text, and (g)(2) to read as follows:

§ 1206.152

What general transportation allowance requirements apply to me?

(a)(1) 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 § 1206.152, 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 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 from which the residue gas, gas plant products, or unprocessed gas is produced.

(2) You may not include any gathering costs in your transportation allowance under § 1206.152, 1206.153, or 1206.154, as applicable, except those reasonable, actual gathering costs you incur for residue gas, gas plant products, or unprocessed gas produced from a lease or unit on the OCS, any part of which lies in waters deeper than 200 meters, that meet all of the following criteria:

(i) The gathering costs are for residue gas, gas plant products, or unprocessed gas for which you are entitled to take a transportation allowance under paragraph (a)(1) of this section;

(ii) The gathering costs are for movement of residue gas, gas plant products, or unprocessed gas beyond a central accumulation point. For purposes of paragraph (a)(2) of this section, a central accumulation point may be a single well, a subsea manifold, the last well in a group of wells connected in a series, or a platform extending above the surface of the water;

(iii) The gathering costs are for movement of residue gas, gas plant products, or unprocessed gas to a facility that is not located on a lease or unit adjacent to the lease or unit on which the production originates. For purposes of paragraph (a)(2) of this section, an adjacent lease or unit is any lease or unit with at least one point of contact with the producing lease or unit. Typically, for a single OCS lease, there are 8 adjacent leases; and

(iv) The gathering costs are only those allocable to the royalty-bearing residue gas, gas plant products, or unprocessed gas. Gathering costs properly allocable to non-royalty bearing substances, or any royalty-bearing substance other than residue gas, gas plant products, or unprocessed gas, may not be included in a transportation allowance under this section.

* * * * *

(g) ONRR may direct you to modify your transportation allowance if:

* * * * *

(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; or

* * * * *

17. Amend § 1206.153 by revising paragraph (d) to read as follows:

§ 1206.153

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

* * * * *

(d) If you have no written contract for the arm's-length transportation of gas, and neither you nor your affiliate perform your own transportation, you must propose to ONRR a method to determine the transportation allowance using the procedures in § 1206.148(a).

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

(2) [Reserved]

18. Amend § 1206.157 by revising paragraph (b) to read as follows:

§ 1206.157

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

* * * * *

(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 without obtaining ONRR's prior approval under § 1206.152(e)(2), 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 file an exception request that ONRR approves. If you do not file an exception request, or if ONRR does not approve your request, you must pay late payment interest on the excess allowance amount taken from the date that amount is taken until the date you pay the additional royalties owed.

* * * * *

19. Amend § 1206.159 by:

a. Revising paragraph (c)(1);

b. Adding paragraph (c)(5);

c. Redesignating paragraphs (d)(2)(A) and (B) as (d)(2)(i) and (ii); and

d. Revising paragraphs (e) introductory text and (e)(2).

The revisions and additions read as follows:

§ 1206.159

What general processing allowances requirements apply to me?

* * * * *

(c)(1) You may not apply the processing allowance against the value of the residue gas, except as provided in paragraph (c)(5) of this section.

* * * * *

(5) If you incur extraordinary costs for processing gas, you may apply to ONRR for an allowance for those costs which must be in addition to any other processing allowance to which the lessee is entitled pursuant to this section. You must demonstrate that the costs are, by reference to standard industry conditions and practice, extraordinary, unusual, or unconventional. You are not required to receive ONRR approval to continue an extraordinary processing allowance. However, you must report the deduction to ONRR in a form and manner prescribed by ONRR in order to retain the ability to deduct the allowance.

* * * * *

(e) ONRR may direct you to modify your processing allowance if:

* * * * *

(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; or

* * * * *

20. Amend § 1206.160 by:

Revising paragraphs (a)(1) and (c), to read as follows:

§ 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 § 1206.159(e) and subject to the limitation in § 1206.159(c)(2).

* * * * *

(c) If you have no written contract for the arm's-length processing of gas, and neither you nor your affiliate perform your own processing, you must propose to ONRR a method to determine the processing allowance using the procedures in § 1206.148(a).

(1) You must use that method to determine your allowance until ONRR issues a determination.

(2) [Reserved]

21. Amend § 1206.164 by revising paragraph (b) to read as follows:

§ 1206.164

What interest and penalties apply if I improperly report a processing allowance?

* * * * *

(b) If you deduct a processing allowance on form ONRR-2014 that exceeds 662/3 percent of the value of a gas plant product without obtaining ONRR's prior approval under § 1206.159(c)(3), 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 file an exception request that ONRR approves. If you do not file an exception request, or if ONRR does not approve your request, you must pay late payment interest on the excess allowance amount taken from the date that amount is taken until the date you pay the additional royalties owed.

* * * * *

Subpart F—Federal Coal

22. Amend § 1206.252 by revising paragraph (a) introductory text, (b) and removing and reserving paragraph (c) to read as follows:

§ 1206.252

How do I calculate royalty value for coal?

(a) The value of coal under this section for royalty purposes is the gross proceeds accruing to you or your affiliate under the first arm's-length contract, or another person, less an applicable transportation allowance determined under §§ 1206.260 through 1206.262 and washing allowance under §§ 1206.267 through 1206.269. You must use this paragraph (a) to value coal when:

* * * * *

(b) If you have no contract for the sale of coal subject to this section because you or your affiliate used the coal in a power plant that you or your affiliate own(s) for the generation and sale of electricity:

(1) You must propose to ONRR a method to determine the value using the procedures in § 1206.258(a).

(2) You must use that method to determine value, for royalty purposes, until ONRR issues a determination.

(3) After ONRR issues a determination, you must make the adjustments under § 1206.253(a)(2).

* * * * *

23. Amend § 1206.253 by revising paragraphs (a)(1), (b), (c) introductory text, (c)(2), (g)(1) and (2) to read as follows:

§ 1206.253

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 establish a reasonable royalty value based on other relevant matters.

* * * * *

(b) ONRR may examine whether your or your affiliate's contract reflects the total consideration transferred for Federal coal, either directly or indirectly, from the buyer to you or your affiliate. If ONRR determines that additional consideration beyond that reflected in the contract was transferred, or that any portion of the consideration was not included in gross proceeds reported, ONRR may establish a reasonable royalty value based on other relevant matters.

(c) ONRR may establish a reasonable royalty value based on other relevant matters if ONRR determines that the gross proceeds accruing to you or your affiliate under a contract do not reflect reasonable consideration because:

* * * * *

(2) You breached your duty to market the coal for the mutual benefit of yourself and the lessor; or

* * * * *

(g)(1) You or your affiliate must make all contracts, contract revisions, or amendments in writing.

(2) If you or your affiliate fail(s) to comply with paragraph (g)(1) of this section, ONRR may establish a reasonable royalty value based on other relevant matters.

* * * * *

§ 1206.254

[Removed and Reserved]

24. Remove and reserve § 1206.254.

25. Amend § 1206.258 by:

a. Revising paragraphs (a) introductory text and (a)(5);

b. Removing the words “Assistant Secretary” in paragraphs (c)(2), (c)(3), (e), and (f) and adding in their place the words “Assistant Secretary for Policy, Management and Budget”;

c. Revising paragraph (g); and

d. Adding paragraph (h).

The revisions and additions read as follows:

§ 1206.258

How do I request a valuation determination?

(a) You may request a valuation determination from ONRR regarding any coal produced. Your request must comply with all of the following:

* * * * *

(5) Provide your analysis of the issue(s);

* * * * *

(g) ONRR or the Assistant Secretary for Policy, Management and Budget generally will not retroactively modify or rescinds 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 § 1206.259.

26. Amend § 1206.260 by revising paragraphs (g) introductory text and (g)(2) to read as follows:

§ 1206.260

What general transportation allowance requirements apply to me?

* * * * *

(g) ONRR may determine your transportation allowance if:

* * * * *

(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 coal for the mutual benefit of yourself and the lessor by transporting your coal at a cost that is unreasonably high; or

* * * * *

27. Amend § 1206.261 by revising paragraph (c) to read as follows:

§ 1206.261

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

* * * * *

(c) If you have no written contract for the arm's-length transportation of coal, and neither you nor your affiliate perform your own transportation, you must propose to ONRR a method to determine the transportation allowance using the procedures in § 1206.258(a).

(1) You must use that method to determine your allowance until ONRR issues a determination.

(2) [Reserved]

28. Amend § 1206.267 by revising paragraphs (d) introductory text and (d)(2) to read as follows:

§ 1206.267

What general washing allowance requirements apply to me?

* * * * *

(d) ONRR may direct you to modify your washing allowance if:

* * * * *

(2) ONRR determines that the consideration that you or your affiliate paid under an arm's-length washing contract does not reflect the reasonable cost of the washing because you breached your duty to market the coal for the mutual benefit of yourself and the lessor by washing your coal at a cost that is unreasonably high; or

* * * * *

29. Amend § 1206.268 by revising paragraphs (b) and (c) to read as follows:

§ 1206.268

How do I determine washing allowances if I have an arm's-length washing contract or no written arm's-length contract?

* * * * *

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

(c) If you have no written contract for the arm's-length washing of coal, and neither you nor your affiliate perform your own washing, you must propose to ONRR a method to determine the washing allowance using the procedures in § 1206.258(a).

(1) You must use that method to determine your allowance until ONRR issues a determination.

(2) [Reserved]

Subpart J—Indian Coal

30. Amend § 1206.452 by revising the section heading, paragraphs (a) introductory text and (b) and removing and reserving paragraph (c) to read as follows:

§ 1206.452

How do I calculate royalty value for coal?

(a) The value of coal under this section for royalty purposes is the gross proceeds accruing to you or your affiliate under the first arm's-length contract, or another person, less an applicable transportation allowance determined under §§ 1206.460 through 1206.462 and washing allowance under §§ 1206.467 through 1206.469. You must use this paragraph (a) to value coal when:

* * * * *

(b) If you have no contract for the sale of coal subject to this section because you or your affiliate used the coal in a power plant that you or your affiliate own(s) for the generation and sale of electricity:

(1) You must propose to ONRR a method to determine the value using the procedures in § 1206.458(a).

(2) You must use that method to determine value, for royalty purposes, until ONRR issues a determination.

(3) After ONRR issues a determination, you must make the adjustments under § 1206.453(a)(2).

* * * * *

31. Amend § 1206.453 by revising paragraphs (a)(1), (b), (c) introductory text, (c)(2), (g)(1), and (2) to read as follows:

§ 1206.453

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 establish a reasonable royalty value based on other relevant matters.

* * * * *

(b) ONRR may examine whether your or your affiliate's contract reflects the total consideration transferred for Indian coal, either directly or indirectly, from the buyer to you or your affiliate. If ONRR determines that additional consideration beyond that reflected in the contract was transferred, or that any portion of the consideration was not included in gross proceeds reported, ONRR may establish a reasonable royalty value based on other relevant matters.

(c) ONRR may establish a reasonable royalty value based on other relevant matters if ONRR determines that the gross proceeds accruing to you or your affiliate under a contract do not reflect reasonable consideration because:

* * * * *

(2) You breached your duty to market the coal for the mutual benefit of yourself and the lessor; or

* * * * *

(g)(1) You or your affiliate must make all contracts, contract revisions, or amendments in writing.

(2) If you or your affiliate fail(s) to comply with paragraph (g)(1) of this section, ONRR may establish a reasonable royalty value based on other relevant matters.

* * * * *

§ 1206.454

[Removed and Reserved]

32. Remove and reserve § 1206.454.

33. Amend § 1206.458 by:

a. Revising paragraphs (a) introductory text and (a)(5);

b. Removing the words “Assistant Secretary” in paragraphs (c)(2), (c)(3), (d)(1), (e), and (f) and adding in their place the words “Assistant Secretary for Policy, Management and Budget”;

c. Revising paragraph (g); and

d. Adding paragraph (h).

The revisions and additions read as follows:

§ 1206.458

How do I request a valuation determination?

(a) You may request a valuation determination from ONRR regarding any coal produced. Your request must comply with all of the following:

* * * * *

(5) Provide your analysis of the issue(s);

* * * * *

(g) ONRR or the Assistant Secretary for Policy, Management and Budget generally will not retroactively modify or rescinds 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 § 1206.459.

34. Amend § 1206.460 by:

a. Revising paragraph (a)(2);

b. Removing paragraph (a)(3);

c. Removing the words “a Federal” in paragraphs (b)(2) and (b)(3) and adding in their place the words “an Indian”;

d. Removing the word “Federal” in paragraphs (e)(1) and (e)(2) and adding in its place the word “Indian”; and

e. Revising paragraphs (g) introductory text and (g)(2).

The revisions read as follows:

§ 1206.460

What general transportation allowance requirements apply to me?

(a)(1) * * *

(2) You do not need ONRR's approval before reporting a transportation allowance for costs incurred.

* * * * *

(g) ONRR may determine your transportation allowance if:

* * * * *

(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 coal for the mutual benefit of yourself and the lessor by transporting your coal at a cost that is unreasonably high; or

* * * * *

35. Amend § 1206.461 by revising paragraph (c) to read as follows:

§ 1206.461

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

* * * * *

(c) If you have no written contract for the arm's-length transportation of coal, then you must propose to ONRR a method to determine the allowance using the procedures in § 1206.458(a). You may use that method to determine your allowance until ONRR issues a determination.

(1) You must use that method to determine your allowance until ONRR issues a determination.

(2) [Reserved]

36. Amend § 1206.467 by:

a. Revising paragraph (a)(2);

b. Removing the word “Federal” in paragraph (b)(2) and adding in its place the word “Indian”; and

c. Revising paragraphs (d) introductory text and (d)(2).

The revisions read as follows:

§ 1206.467

What general washing allowance requirements app ly to me?

(a)(1) * * *

(2) You do not need ONRR's approval before reporting a washing allowance.

* * * * *

(d) ONRR may direct you to modify your washing allowance if:

* * * * *

(2) ONRR determines that the consideration that you or your affiliate paid under an arm's-length washing contract does not reflect the reasonable cost of the washing because you breached your duty to market the coal for the mutual benefit of yourself and the lessor by washing your coal at a cost that is unreasonably high; or

* * * * *

37. Amend § 1206.468 by revising paragraph (c) to read as follows:

§ 1206.468

How do I determine washing allowances if I have an arm's-length washing contract or no written arm's-length contract?

* * * * *

(c) If you have no written contract for the arm's-length washing of coal, and neither you nor your affiliate perform your own washing, you must propose to ONRR a method to determine the washing allowance using the procedures in § 1206.458(a).

(1) You must use that method to determine your allowance until ONRR issues a determination.

(2) [Reserved]

* * * * *

PART 1241—PENALTIES

38. The authority citation for part 1241 continues to read as follows:

Authority: 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.; 43 U.S.C. 1301 et seq., 1331 et seq., 1801 et seq.

Subpart A—General Provisions

39. Amend § 1241.11 by removing paragraph (b)(5).

Subpart C—Penalty Amount, Interest, and Collections

40. Amend § 1241.70 by:

a. Revising paragraph (b); and

b. Adding paragraph (d).

The revision and addition read as follows:

§ 1241.70

How does ONRR decide the amount of the penalty to assess?

* * * * *

(b) For payment violations only, we will consider the unpaid, underpaid, or late payment amount in our analysis of the severity of the violation.

* * * * *

(d) After we provisionally determine the civil penalty amount using the criteria and matrices described in paragraphs (a), (b), and (c) of this section, we may adjust the penalty amount in the FCCP or ILCP upward or downward if we find aggravating or mitigating circumstances to exist.

(1) Aggravating circumstances may include, but are not limited to:

(i) Committing a violation because you determined that the cost of a potential penalty is less than the cost of compliance;

(ii) Committing a violation where you have no recent history of noncompliance of the same type, but you have a history of noncompliance of other violation types;

(iii) Committing a violation that is also a criminal act.

(2) Mitigating circumstances may include, but are not limited to:

(i) Operational impacts resulting from the unexpected illness or death of an employee, natural disasters, pandemics, acts of terrorism, civil unrest, or armed conflict;

(ii) Delays caused by government action or inaction, including as a result of a government shutdown and an extended ONRR-system downtime;

(iii) Good-faith efforts to comply with formal or informal agency guidance.