2021-20979. ONRR 2020 Valuation Reform and Civil Penalty Rule: Final Withdrawal Rule

AGENCY:

Office of Natural Resources Revenue (“ONRR”), Interior.

ACTION:

Final rule; withdrawal.

SUMMARY:

ONRR is withdrawing the ONRR 2020 Valuation Reform and Civil Penalty Rule (“2020 Rule”).

DATES:

As of November 1, 2021, ONRR's 2020 Rule, published in the Federal Register on January 15, 2021 at 86 FR 4612, currently effective November 1, 2021 (as extended at 86 FR 9286 and 86 FR 20032), is withdrawn.

FOR FURTHER INFORMATION CONTACT:

For questions, contact Luis Aguilar, Regulatory Specialist, Appeals & Regulations, ONRR, by email at [e-mail], or by telephone [phone].

SUPPLEMENTARY INFORMATION:

Table of Abbreviations and Commonly Used Acronyms in This Rule

Abbreviation	What it means
2016 Valuation Rule	Consolidated Federal Oil & Gas and Federal & Indian Coal Valuation Reform Rule, 81 FR 43338 (July 1, 2016).
2016 Civil Penalty Rule	Amendments to Civil Penalty Regulations, 81 FR 50306 (August 1, 2016).
2017 Repeal Rule	Repeal of Consolidated Federal Oil & Gas and Federal & Indian Coal Valuation Reform, 82 FR 36934 (August 7, 2017).
2020 Rule	ONRR 2020 Valuation Reform and Civil Penalty Rule, 86 FR 4612 (January 15, 2021).
ALJ	Administrative Law Judge.
APA	Administrative Procedure Act of 1946, as amended, 5 U.S.C. 551, et seq.
BLM	Bureau of Land Management.
BLS	Bureau of Labor Statistics.
BOEM	Bureau of Ocean Energy Management.
BSEE	Bureau of Safety and Environmental Enforcement.
Deepwater Policy	MMS' May 20, 1999, memorandum entitled “Guidance for Determining Transportation Allowances for Production from Leases in Water Depths Greater Than 200 Meters”.
DOI	U.S. Department of the Interior.
E.O.	Executive Order.
FERC	Federal Energy Regulatory Commission.
First Delay Rule	ONRR 2020 Valuation Reform and Civil Penalty Rule: Delay of Effective Date; Request for Public Comment, 86 FR 9286 (February 12, 2021).
FOGRMA	Federal Oil and Gas Royalty Management Act of 1982, 30 U.S.C. 1701, et seq.
MLA	Mineral Leasing Act of 1920, 30 U.S.C. 181, et seq.
MMS	Minerals Management Service.
NEPA	National Environmental Policy Act of 1970, as amended, 42 U.S.C. 4321, et seq.
NGL	Natural Gas Liquids.
OCS	Outer Continental Shelf.
OCSLA	Outer Continental Shelf Lands Act of 1953, 43 U.S.C. 1331, et seq.
OMB	Office of Management and Budget.
ONRR	Office of Natural Resources Revenue.
Proposed 2020 Rule	ONRR 2020 Valuation Reform and Civil Penalty Rule (a proposed rule), 85 FR 62054 (October 1, 2020).
Proposed Withdrawal Rule	ONRR 2020 Valuation Reform and Civil Penalty Rule: Notification of Proposed Withdrawal, 86 FR 31196 (June 11, 2021).
Second Delay Rule	ONRR 2020 Valuation Reform and Civil Penalty Rule: Delay of Effective Date, 86 FR 20032 (April 16, 2021).
Secretary	Secretary of the Department of the Interior.
S.O.	Secretarial Order.

I. Introduction

The 2020 Rule, as published, amends a number of provisions adopted by ONRR in the 2016 Valuation Rule and the 2016 Civil Penalty Rule relating to the valuation of oil and gas produced from Federal leases for royalty purposes; the valuation of coal produced from Federal and Indian leases for royalty purposes; and the assessment of civil penalties. 86 FR 4612. The 2020 Rule amended the following portions of ONRR's valuation regulations that were adopted via the 2016 Valuation Rule in the following ways:

1. Deepwater gathering—codifies the principles of the Deepwater Policy to allow certain gathering costs to be deducted as part of a lessee's transportation allowance for Federal oil and gas produced on the OCS at depths greater than 200 meters.

2. Extraordinary processing allowances—reinstates a lessee's ability to apply for approval to claim an extraordinary processing allowance for Federal gas in situations where the gas stream, plant design, and/or unit costs are extraordinary, unusual, or unconventional relative to standard industry conditions and practice.

3. Index to be used in index-based valuation option—lowers the applicable index from the highest bidweek price to the average bidweek price.

4. Percentage deduction allowable for transportation in index-based valuation option—increases the percentage reduction to index stated in the 2016 Valuation Rule to reflect an average of more recently reported transportation cost data.

5. Arm's-length valuation option—extends the index-based valuation option (previously allowed in non-arm's-length sales) to arm's-length Federal gas sales.

6. Default provision—eliminates the default provision and references thereto from the Federal oil and gas and Federal and Indian coal regulations, which provision established criteria explaining how ONRR would exercise the Secretary's authority to establish royalty value when typical valuation methods are unavailable, unreliable, or unworkable.

7. Misconduct—eliminates the definition of “misconduct.”

8. Signed contracts—eliminates the requirement that a lessee have contracts signed by all parties.

9. Citation to legal precedent—eliminates the requirement to cite legal precedent when seeking a valuation determination.

10. Valuation of coal based on electricity sales—eliminates the requirement to value certain Federal and Indian coal based on the sales price of electricity.

11. Coal cooperative—removes the definition of “coal cooperative” and the method to value sales between members of a “coal cooperative” for Federal and Indian coal.

12. Non-substantive corrections—amends various regulations by making non-substantive corrections.

The 2020 Rule amended the following provisions of ONRR's civil penalty regulations that were adopted in the 2016 Civil Penalty Rule in the following ways:

1. Facts considered in assessing penalties for payment violations—specifies that ONRR considers unpaid, underpaid, or late payment amounts in the severity analysis for payment violations.

2. Consideration of aggravating and mitigating circumstances—specifies that ONRR may consider aggravating and mitigating circumstances when calculating the amount of a civil penalty.

3. Conforming civil penalty regulations to a court decision—eliminates 30 CFR 1241.11(b)(5), which permitted an ALJ to vacate a previously-granted stay of an accrual of penalties if the ALJ later determined that a violator's defense to a notice of noncompliance or assessment of civil penalties was frivolous.

The 2020 Rule has not, however, gone into effect. See 86 FR 9286 and 86 FR 20032.

The Proposed Withdrawal Rule described the procedural history of ONRR's publication of the Proposed 2020 Rule, the 2020 Rule, the First Delay Rule, and the Second Delay Rule. See 86 FR 31197-31198. ONRR published the Proposed 2020 Rule on October 1, 2020. On January 15, 2021, ONRR published the 2020 Rule. The effective date of the 2020 Rule was originally February 16, 2021.

On January 20, 2021, two memoranda were issued, one by the Assistant to the President and Chief of Staff and one by OMB, which directed agencies to consider a delay of the effective date of rules published in the Federal Register that had not yet become effective and to invite public comment on issues of fact, law, and policy raised by those rules. 86 FR 7424.

On February 12, 2021, ONRR published the First Delay Rule which delayed the effective date of the 2020 Rule by 60 days and opened a 30-day comment period on the facts, law, and policy underpinning the 2020 Rule as well as on the impact of a delay in the effective date of the 2020 Rule. After the close of the First Delay Rule's comment period, ONRR determined that a second delay of the 2020 Rule's effective date was needed. Thus, on April 16, 2021, ONRR published a second final rule which further delayed the effective date until November 1, 2021.

ONRR published the Proposed Withdrawal Rule on June 11, 2021. The Proposed Withdrawal Rule invited comment on a complete withdrawal of the 2020 Rule as well as potential alternatives. See 86 FR 31215. The Proposed Withdrawal Rule also requested comments pertaining to the substance or merits of the 2020 Rule and the regulatory scheme it replaced. Id.

In response to the Proposed Withdrawal Rule, ONRR received ten comment submissions and 151 pages of new comment materials from oil, gas, and coal trade associations and representatives, public interest groups, and State entities. After consideration of the public comment and further analysis by the agency, ONRR publishes this final rule pursuant to the authority delegated to it. See 30 U.S.C. 189 (MLA); 30 U.S.C. 1751 (FOGRMA); 43 U.S.C. 1334 (OCSLA); See S.O. 3299, sec. 5; and S.O. 3306, sec. 3-4.

II. Rationale for Withdrawal of the 2020 Rule

After completing a review of the regulatory history and the public comment submissions received, ONRR determined that the defects discussed below require withdrawal of the 2020 Rule. These defects necessitating withdrawal of the 2020 Rule include, among others, (1) an inadequate comment period, (2) absence of discussion of alternatives, (3) lack of reasoned explanations for many of the amendments proposed in that rule, (4) inadequate justification for changes in recently adopted policies reflected in the 2016 Valuation Rule, and (5) flawed economic analysis. ONRR continues to consider and evaluate whether some of the provisions in the now withdrawn 2020 Rule should be adopted in the future. ONRR anticipates re-proposing some of these provisions, particularly ones to amend the 2016 Civil Penalty Rule, in the near future. If ONRR does so, it will avoid the defects that permeated the rulemaking process that resulted in the 2020 Rule and which necessitate the withdrawal of that Rule. Thus, DOI has determined to withdraw the 2020 Rule and to begin any new rulemaking in a manner that avoids the defects described herein.

A. Inadequate Comment Period

Several years ago, ONRR amended the 30 CFR part 1206 regulations when it adopted the 2016 Valuation Rule. See 81 FR 43338. Though the 2016 Valuation Rule followed a public comment period of 120 days, the 2020 Rule followed a 60-day public comment period. In litigation construing ONRR's adoption of the 2017 Repeal Rule, the United States District Court for the Northern District of California found that ONRR did not provide meaningful opportunity for comment when it repealed the 2016 Valuation Rule without a comment period of commensurate length to the 2016 Valuation Rule's public comment period. California v. U.S. Dep't of the Interior, 381 F. Supp. 3d 1153, 1177-78 (N.D. Cal. 2019). Specifically, the District Court found that the 30-day comment period used for the 2017 repeal of the 2016 Valuation Rule was too brief when ONRR had a much longer comment period for the adoption of the 2016 Valuation Rule—approximately 120 days. Id.

While California is a decision by a tribunal of inferior jurisdiction and not binding on litigants who did not appear in that case, ONRR was a party to the case. Because ONRR did not appeal the California case, it is bound by the decision in a manner not applicable to other Federal agencies and bureaus. Here, though ONRR allowed for more than 30 days of comment on the 2020 Rule, ONRR provided a 60-day comment period on the Proposed 2020 Rule when the 2016 Valuation Rule was adopted after a 120-day comment period. ONRR needed to provide the public with more than a 60-day comment period for review and comment on the 2020 Rule even though some of the amendments may be less complex or controversial than others because the public needed time to consider the lengthy rulemaking history dating back to the 2016 Valuation Rule and how the amendments interrelate. ONRR's decision to combine various oil, gas, and coal valuation amendments with civil penalty amendments into one rulemaking, when previously it had addressed many of these topics in separate rulemakings in the 2016 Valuation Rule and 2016 Civil Penalty Rule, further added to the necessary review and comment time. Thus, ONRR must withdraw the 2020 Rule.

Public Comment: A commenter stated that the 2020 Rule did not rescind the entire 2016 Valuation Rule or fully reinstate the prior regulations.

ONRR Response: The 2020 Rule, while not fully repealing the 2016 Valuation Rule, repealed nearly all the revenue-impacting provisions adopted in the 2016 Valuation Rule. Thus, the 2020 Rule is fairly considered a targeted repeal of many of the substantive, revenue-impacting provisions of the 2016 Valuation Rule. Because ONRR is uniquely bound by California and most of the amendments have a lengthy, complex rulemaking history, ONRR should have provided the public with a comment period of commensurate length with respect to its targeted repeal of the substantive provisions of the 2016 Valuation Rule as was employed when those provisions were adopted in the 2016 Valuation Rule. This is especially the case since ONRR combined valuation and civil penalty amendments together in the 2020 Rule.

Public Comment: Multiple commenters stated that the public had sufficient notice and opportunity to comment on the 2020 Rule. The commenters stated that the Proposed Withdrawal Rule failed to acknowledge that the Proposed 2020 Rule was available on ONRR's website for almost two months prior to its publication in the Federal Register . The commenters stated that, with the additional time factored in, the public had approximately 115 days to comment on the 2020 Rule, similar to the 120-day comment period provided for the 2016 Valuation Rule.

ONRR Response: There is no legal authority supporting a conclusion that publication on ONRR's website can be substituted, in whole or in part, for the notice required under the APA. See 5 U.S.C. 553(b) (stating that, with only limited exceptions not applicable here, “notice of proposed rulemaking shall be published in the Federal Register ”). Moreover, there is no demonstration that the general public was perusing ONRR's website for advance notice of a proposed rule instead of relying on the traditional and statutorily-authorized method of notice in the Federal Register . In addition, the public was unable to submit comments for ONRR's review during the 55 days the draft was available only on ONRR's website. The comment period for the 2020 Rule did not open until its publication in the Federal Register and was only open for a 60-day period. Therefore, the commenters' assertions do not adequately consider the notice and comment requirements under the APA. See 5 U.S.C. 553(b); see also California, 381 F. Supp. at 1177 (finding legal deficiencies in a comment period for ONRR's withdrawal rule that was substantially shorter than the comment period employed when ONRR adopted the rule).

B. No Discussion of Alternatives

The Proposed 2020 Rule did not demonstrate that ONRR considered alternatives to the repeal of the provisions adopted via the 2016 Valuation Rule or the provisions adopted via the 2016 Civil Penalty Rule. Although the Proposed 2020 Rule solicited comment on alternatives, that alone was not sufficient since ONRR had to comply with the requirements of the California case. According to California, ONRR needed to discuss alternatives when adopting the 2020 Rule because, as discussed herein, ONRR was attempting, through the 2020 Rule, to repeal most of the substantive provisions adopted in 2016. California, 381 F. Supp. 3d at 1168-69. The 2020 Rule should have discussed alternatives. For example, ONRR should have discussed alternatives to the substantive, revenue impacting provisions instead of simply reversing course and reinstating a deepwater gathering policy (which had been overturned by the 2016 Valuation Rule), reinstating extraordinary processing allowances (which had been repealed by the 2016 Valuation Rule), and making changes to the index-based pricing options (which had been discussed but rejected in the 2016 Valuation Rule). Likewise, instead of merely repealing the default provision, the definition of misconduct, the requirement for signatures on contracts, and the requirement to cite legal precedent in requests for valuation determinations, ONRR should have discussed other alternatives which could have included further amendment of the existing provisions or amendments to related provisions.

These shortcomings resemble ONRR's 2017 attempt to repeal the 2016 Valuation Rule, where the United States District Court for the Northern District of California found that ONRR did not discuss alternatives to a full repeal of the 2016 Valuation Rule and explained that an agency must discuss alternatives even if the agency is repealing less than an entire rulemaking. See California, 381 F. Supp. 3d at 1168-69; Yakima Valley Cablevision, Inc. v. F.C.C., 794 F.2d 737, 746 n. 36 (D.C. Cir. 1986).

With respect to the repeal of the two coal provisions, ONRR notes that the position taken in the 2020 Rule is consistent with, but not identical to, the position taken by the Federal defendants in the Cloud Peak case, specifically that the coal cooperative provisions and the provisions providing for valuation of certain coal sales based on electricity are defective. See Cloud Peak Energy Inc. v. U.S. Dep't of the Interior, 415 F. Supp. 3d 1034 (D. Wyo. 2019). However, on September 8, 2021, the United States District Court for the District of Wyoming issued a ruling on the merits of the Cloud Peak petitions, which ruling renders moot the portions of the 2020 Rule applicable to Federal and Indian coal.

Public Comment: A commenter stated that ONRR's Proposed Withdrawal Rule fails to cite any legal support for its assertion that the APA requires an analysis of the alternatives to a repeal of regulations. The commenter also stated that ONRR failed to quantify the amount of discussion required to meet this standard. The commenter asserted that ONRR's reliance on California is unhelpful to its position because, according to the commenter, the case is currently under appeal at the U.S. Court of Appeals for the Ninth Circuit. The commenter also argued that the case law relied upon by ONRR is inapplicable in this instance. More specifically, the commenter stated that the California case primarily focused on rule repeals. The commenter further stated that the 2020 Rule did not repeal the entire 2016 Valuation Rule, but instead modified only some of the regulations promulgated through the 2016 Valuation Rule.

Another commenter noted appreciation for the alternatives provided in the Proposed Withdrawal Rule. However, this commenter stated that a full withdrawal of the 2020 Rule is necessary due to the legal and procedural deficiencies underpinning the 2020 Rule.

ONRR Response: As shown in the Proposed 2020 Rule, ONRR cited authority, including California, 381 F. Supp. 3d at 1168-69, that supports the requirement that ONRR must discuss alternatives due to the unique factual circumstances of this rule, its attempted repeal of the 2016 Valuation Rule, and the California decision. See also DHS v. Regents of the Univ. of Cal., 140 S. Ct. 1891, 1913-15 (2020) (discussing the requirement to consider alternatives). In addition, the commenter's statement regarding the status of the California litigation is incorrect. California is a final decision, binding on ONRR, because no party to that case appealed any of the District Court's decisions, including the final merits decision (dated March 29, 2019).

C. Lack of Reasoned Explanation

The Proposed 2020 Rule did not fully explain why the amendments were being proposed. ONRR needed to provide a reasoned explanation for repealing most of the substantive provisions adopted in 2016 Valuation Rule. The California Court noted a similar flaw in ONRR's 2017 proposal to repeal the 2016 Valuation Rule, finding that ONRR did not identify the reasons supporting its proposed repeal. 381 F. Supp. 3d at 1173-74 (“The Court concludes that, by failing to provide the requisite information to adequately apprise the public regarding the reasons the ONRR was seeking to repeal the Valuation Rule in favor of the former regulations it had just replaced, the ONRR effectively precluded interested parties from meaningfully commenting on the proposed repeal. The Court therefore concludes that Federal Defendants violated the APA by failing to comply with the notice and comment requirement.”) (citations omitted). Specifically, ONRR's Proposed 2020 Rule lacked the full statement of the reasons why ONRR was both proposing to return to some of the “historical practices” and suggesting other changes that were eventually adopted by the 2020 Rule, most of which targeted the changes adopted in the 2016 Valuation Rule and 2016 Civil Penalty Rule. While the Proposed 2020 Rule identified the proposed changes, discussed the anticipated economic impact of the changes, and set forth the language of the proposed amendments, ONRR did not fully discuss why it was repealing most of the substantive provisions adopted in 2016 Valuation Rule. Cf. 85 FR 62056-62062 with 86 FR 4617-4640. ONRR needed to provide such an explanation in light of the California case, the lengthy and complex rulemaking history, and the repeal of most of the substantive provisions adopted in 2016 Valuation Rule. Moreover, for the changes that were reverting to “historical practices” ( i.e., those existing before the 2016 Valuation Rule was adopted), ONRR did not fully explain why it was reverting to practices it had rejected in its last substantive rulemaking. Thus, the Proposed 2020 Rule did not provide sufficient notice of the reasons for the 2020 Rule. As such, the public was deprived of a meaningful opportunity to comment.

Public Comment: A commenter stated that frequent rule changes create confusion and unnecessary cost within the regulated community.

ONRR Response: While ONRR understands there may be confusion caused by the recent change in requirements due to the successive adoption of the 2016 Valuation Rule, publication of the 2020 Rule, and now this withdrawal, ONRR notes that the 2020 Rule has never gone into effect and no company has ever been required to report thereunder. ONRR also notes that the 2016 Valuation Rule has been in effect for a relatively short period of time. Withdrawing the 2020 Rule will avoid additional rule changes until such time as the public has had adequate opportunity to review and comment on any proposed amendments and ONRR has considered the associated costs of any changes to the regulated community.

Public Comment: Some commenters agreed with ONRR's analysis in the Proposed Withdrawal Rule, agreeing that the 2020 Rule lacked evidentiary support and a reasoned justification for the rulemaking.

ONRR Response: ONRR agrees. For the reasons stated in the Proposed Withdrawal Rule and herein, the withdrawal of the 2020 Rule is appropriate.

D. Inadequate Justification for Change in Recently Adopted Policy

At the time the Proposed 2020 Rule was published, the 2016 Valuation Rule was in force only from March 29, 2019, when the repeal of the 2016 Valuation Rule was overturned, to October 1, 2020, and full compliance with the 2016 Valuation Rule was delayed by the series of Dear Reporter letters to October 1, 2020. Given that the Proposed 2020 Rule was, in many instances, an attempt to return to the valuation rules that existed prior to the 2016 Valuation Rule, ONRR should have included justifications for the proposed changes in the Proposed 2020 Rule to allow for public comment thereon. In addition, ONRR should have explained the inconsistencies between the 2016 Valuation Rule and the amendments described in the Proposed 2020 Rule and adequately explained its potential rejection of the position under which the agency and the regulated public had been operating for only a brief period of time. California, 381 F. Supp. 3d at 1173-74.

For example, the 2016 Valuation Rule discussed, but rejected, extending the index-based valuation option to arm's-length sales of gas. 81 FR 43347. The 2020 Rule did not adequately explain its change in position to adopt a provision rejected in the 2016 Valuation Rule. Similarly, the 2016 Valuation Rule rejected the request to use average bidweek prices for the index-based valuation option. Id. When it was published, the 2020 Rule took the position that the average bidweek price should be used but failed to explain why the change in position was warranted after being rejected by the 2016 Valuation Rule. Additionally, the 2016 Valuation Rule established that any movement of bulk production from the wellhead to a platform offshore is gathering and not transportation and effectively rescinded the Deepwater Policy. See 81 FR 43340. The 2020 Rule, however, allowed a lessee producing in waters deeper than 200 meters to deduct the costs incurred in gathering to be deducted as part of its transportation allowance. 86 FR 4613, 4622-4624. The 2020 Rule did not explain why ONRR was adopting a position so recently rejected in the 2016 Valuation Rule.

Because ONRR failed to explain, in the Proposed 2020 Rule, its reasons for changing rules adopted in 2016 and only belatedly did so in the 2020 Rule, the 2020 Rule is defective under the APA. See California, 381 F. Supp. 3d at 1166-68.

E. The 2020 Rule's Economic Analysis Is Flawed

As discussed in the Economic Analysis of this Final Rule, the economic analyses set forth in the Proposed 2020 Rule and the 2020 Rule were flawed. See Section V, infra. The numerous flaws in the economic analysis in the Proposed 2020 Rule and the 2020 Rule could have a direct impact on the changes made relative to the transportation allowances allowed under 30 CFR 1206.141(c)(1)(iv) and 1206.142(d)(1)(iv) if a lessee elects optional index-based reporting. Accordingly, the 2020 Rule should be withdrawn in order to allow ONRR to propose changes to its valuation rules that are based on sound economic analysis.

F. Comments Regarding the Support Needed for a Full Withdrawal

Public Comment: Multiple commenters stated that the Proposed Withdrawal Rule does not justify a full withdrawal of the 2020 Rule. According to the commenters, the Proposed Withdrawal Rule did not provide ONRR's rationale for the withdrawal of the 2020 Rule's revenue-neutral amendments, such as the default provision, coal valuation, and civil penalties amendments. One commenter suggested that ONRR provide another opportunity for notice and comment before proceeding with a full withdrawal.

ONRR Response: ONRR has considered the commenters' statements and disagrees. Upon careful review, the defects of the 2020 Rule, including the lack of adequate comment period (Section II.A), the inadequate discussion of alternatives (Section II.B), the lack of reasoned explanation (Section II.C), and the inadequate justification for change in recently adopted policy (Section II.D) necessitate the withdrawal of the rule. As stated above, ONRR has the present intention to open a new rulemaking process with respect to some provisions that were adopted in the 2020 Rule.

III. Additional Reasons for the Withdrawal of Certain Amendments

Citing now-withdrawn E.O.s and S.O.s, the 2020 Rule adopted the deepwater gathering allowance, extraordinary processing allowance, and amendments to index-based valuation for Federal oil and gas production (“revenue-impacting amendments”) to incentivize oil and gas production. 86 FR 4614-4615. ONRR is withdrawing these revenue-impacting amendments for the reasons identified in Section II above and the additional reasons set forth in this section.

A. Unwarranted and Overbroad Attempt To Incentivize Production

ONRR was formed when the Secretary reorganized the former MMS into BOEM, BSEE, and ONRR. See S.O. 3299 (Aug. 29, 2011). This reorganization was to “improve the management, oversight, and accountability of activities on the [OCS]; ensure a fair return to the taxpayer from royalty and revenue collection and disbursement activities; and provide independent safety and environmental oversight and enforcement of offshore activities.” Id. at Sec. 1. As part of this reorganization, ONRR assumed the royalty and revenue management functions of MMS, “including, but not limited to, royalty and revenue collection, distribution, auditing and compliance, investigation and enforcement, and asset management for both onshore and offshore activities . . . .” Id. at Sec. 5. Consistent with these responsibilities, ONRR promulgated detailed regulations governing mineral royalty reporting, valuation, auditing, collection, and disbursement. See 30 CFR Chapter XII.

BLM, BOEM, and BSEE, on the other hand, are primarily responsible for mineral leasing functions, such as awarding leases, setting royalty rates, and granting royalty relief when appropriate. 86 FR 31201. This royalty relief authority originates in the MLA and OCSLA. For onshore leases, the MLA authorizes the Secretary to “reduce the royalty on an entire leasehold . . . whenever in his judgment it is necessary to do so in order to promote development, or . . . the leases cannot be successfully operated under the terms provided therein.” 30 U.S.C. 209. For offshore leases, OCSLA authorizes the Secretary to “reduce or eliminate any royalty” to “promote increased production on the lease area.” 43 U.S.C. 1337(a)(3). To implement the Secretary's royalty relief authority, BLM and BSEE promulgated regulations requiring detailed technical and economic information for each lease or lease area for which royalty relief is sought. See 30 CFR part 203; 76 FR 64432, 64435 (Oct. 18, 2011) (for offshore leases, stating that “BSEE is responsible for the regulatory oversight of need-based royalty relief awarded after lease issuance and the tracking of all royalty-free production.”); 43 CFR 3103.4-1(b)(1) (for onshore leases, requiring that an operator file a relief application with the appropriate BLM office for BLM's consideration).

ONRR departed from its traditional role in the DOI in seeking to incentivize other oil and gas development and production through the revenue-impacting amendments. See 86 FR 31200. This was unwarranted because BLM, BOEM, and BSEE have primary authority, experience, and expertise to determine when royalty relief is needed for individual leases or lease areas to promote development or increase production. Id. at 31201. These entities review and consider royalty relief applications and can grant targeted royalty relief where needed. See, e.g., Special Case Royalty Relief, https://www.bsee.gov/​what-we-do/​conservation/​gulf-of-mexico-deepwater-province/​special-case-royalty-relief-overview. The 2020 Rule's revenue-impacting amendments, in contrast, are overbroad because those amendments apply to all leases, including highly profitable leases and lease areas that are being produced or will be developed and produced even without the incentives contained in the 2020 Rule. Id. This global reduction of royalties on profitable oil and gas production for the purpose of incentivizing other development and production undermines and conflicts with the royalty rate setting and royalty relief functions of BLM, BSEE, and BOEM and exceeds ONRR's expertise and area of delegated authorities.

Although the 2020 Rule cited certain E.O.s and S.O.s as a basis for incentivizing production, these E.O.s and S.O.s, before they were revoked, expressly required that they be implemented consistent with applicable law. See, e.g., E.O. 13783, Sec. 8(b). As discussed above, the MLA and OCSLA, and BOEM and BSEE's regulations, authorize targeted royalty relief for a lease or lease area. The revenue-impacting amendments are inconsistent with this targeted royalty relief because these amendments apply to all production, including production in highly profitable areas. Further, the E.O.s and S.O.s upon which the 2020 Rule was premised were revoked prior to the effective date of the 2020 Rule. See E.O. 13990, Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis, Sec. 7 (Jan. 20, 2021) (revoking E.O.s 13783 and 13795); E.O. 13992, Revocation of Certain Executive Orders Concerning Federal Regulation, Sec. 2 (Jan. 20, 2021) (revoking E.O. 13892); and S.O. 3398, Sec. 4 (Apr. 16, 2021) (revoking S.O.s 3350 and 3360). Thus, the global incentivization of production exceeded ONRR's delegated authority and should not have been cited as a basis for the 2020 Rule. 86 FR 31200.

Further, regardless of whether ONRR has a role to play in the DOI in incentivizing oil and gas production, ONRR still would withdraw the amendments because there is insufficient basis to conclude that the amendments would maintain or incentivize oil and gas production in the United States above levels that would occur in their absence. 86 FR 31201. Many factors, such as oil and gas prices, national and international supply, market forecasts, alternative energy sources, credit markets, and competition, play a role in decisions on oil and gas development and production. The 2020 Rule fails to cite an economic study or contain an economic analysis demonstrating that the amendments would incentivize higher levels of oil and gas production from Federal lands. Nor does the 2020 Rule demonstrate that the royalties paid on any additional oil and gas production will offset the reduction in royalties attributable to the deepwater gathering allowance, extraordinary processing allowance, and amendments to the index-based valuation option contained in the 2020 Rule.

Public Comment: A commenter stated that ONRR departed from its primary accounting and auditing role in seeking to incentivize development and production. This commenter pointed to the long-held policy that gathering costs are considered costs of placing gas into marketable condition. This commenter supports withdrawal of the allowance to restore taxpayer protections, uphold valuation standards, and prevent the loss of hundreds of millions of dollars in royalty revenue over the next decade.

ONRR Response: ONRR acted outside of its traditional accounting and auditing role in seeking to incentivize oil and gas development and production.

Public Comment: A commenter stated that 2020 Rule was premised in part on a drop in commodity prices, that commodity prices have since recovered, and that commodity prices cannot be a basis for consistent Federal policy.

ONRR Response: In general, it is not advisable for ONRR to amend royalty valuation regulations based on temporary fluctuations in commodity prices. FOGRMA directs the Secretary to maintain a comprehensive inspection, collection, and fiscal and production accounting and auditing system that: (1) Accurately determines mineral royalties, interest, and other payments owed, (2) collects and accounts for such amounts in a timely manner, and (3) disburses the funds collected. See 30 U.S.C. 1701 and 1711. ONRR performs these mineral revenue management responsibilities for the Secretary. See S.O. 3299. Under its delegated authority, ONRR's function is to ensure fair return ( i.e., fair value) for the taxpayer from royalty and revenue collection and disbursement activities. Id. It has no statutory mandate or delegated authority to change its valuation regulations to account for fluctuations in commodity prices. The valuation regulations already account for changes in commodity prices because valuation often is based on the prices received for the mineral production, and in instances when the price received is lower, the dollar amount of the royalty obligation is lower. BLM, BOEM, and BSEE have authority to and are better positioned to address temporary drops in commodity prices when needed to incentive oil and gas development or production.

B. Deepwater Gathering Allowance

The 2020 Rule adopted a deepwater gathering allowance for the stated purpose of incentivizing deepwater oil and gas development and production. See 86 FR 4654. The allowance mirrors the Deepwater Policy that was expressly overturned by the 2016 Valuation Rule. ONRR is withdrawing the deepwater gathering allowance for the reasons stated in Sections II and III.A, and the additional reasons below.

1. Unwarranted Allowance for Bulk Oil and Gas Production Not Treated or Measured for Royalty Purposes

ONRR is withdrawing the deepwater gathering allowance for the additional reason that the DOI has long required that oil and gas “be placed into marketable condition at no cost to the Federal lessor” and “gathering has consistently been held to be a part of that process.” See, e.g., Nexen Petroleum U.S.A., Inc. v. Norton, No. 02-3543, 2004 WL 722435, at *9 (E.D. La. Mar. 31, 2004). Consistent with the marketable condition requirement, ONRR's regulations define gathering as “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.” 30 CFR 1206.20. ONRR views the movement of bulk oil and gas production that has not been separated, treated, and measured for royalty purposes as gathering because these processes are integral to placing oil and gas into marketable condition. See 53 FR 1190-1191, 1193 (Jan. 15, 1988); Devon Energy Corp., Acting Asst. Sec. Decision, Valuation Determination for Coalbed Methane Production from the Kitty, Spotted Horse, and Rough Draw Fields, Powder River Basin, Wyoming, at 2, 18, 21-22, 32-33 (Oct. 9, 2003) (“Devon Valuation Determination”), aff'd sub nom., Devon Energy Corp v. Norton, No. 04-CV-0821 (GK), 2007 WL 2422005 (D.D.C. Aug. 23, 2007), aff'd sub nom., Devon Energy Corp. v. Kempthorne, 551 F.3d 1030 (D.C. Cir. 2008), cert. denied, 558 U.S. 819 (2009); Nexen, 2004 WL 722435, at *1, 4-5, 9-12; Marathon Oil Co., MMS-00-0063-OCS (FE), 2005 WL 6733988 (Oct. 20, 2005); Kerr-McGee Corp., 147 IBLA 277 (1999); CNG Producing Co. v. Royalty Valuation & Standards Div., MMS-96-0370-0CS, 1997 WL 34843496 (Oct. 16, 1997); see also DCOR, LLC, ONRR-17-0074-OCS (FE), 2019 WL 6127405, at *7-15 (Aug. 26, 2019).

Public Comment: Some commenters stated that the deepwater gathering allowance is needed to incentivize deepwater offshore oil and gas production, with one asserting that the deepwater gathering allowance should not be withdrawn because it benefits the United States to receive royalties and share in the costs of subsea transportation rather than forego development altogether. This commenter asserted that the development of offshore resources promotes one of ONRR's primary functions, i.e., to ensure fair return for the public.

ONRR Response: These commenters provided no information demonstrating that the deepwater gathering allowance would result in additional deepwater development or increased production and ONRR has no such information in its possession. If appropriate, BSEE could grant targeted royalty relief for individual leases and lease areas to promote increased development and production when necessary and supported by economic analysis.

Public Comment: While agreeing that gathering is not deductible, some commenters opposed withdrawing the deepwater gathering allowance because they view all subsea movement of oil and gas to a facility not located on a lease or unit adjacent to the lease on which the production originates to be transportation even if the production has not been separated, treated, or measured for royalty purposes. These commenters asserted that ONRR has considered such movement to always be transportation since the Deepwater Policy was issued in 1999. Consistent with this position, one of these commenters objected to referring to the allowance as a “deepwater gathering allowance” because that commenter considers such movement to always be transportation.

ONRR Response: The commenters' view that subsea movement of bulk oil and gas production to a facility off the lease or an adjacent lease is always transportation does not comport with ONRR's view that gathering is part of placing oil and gas into marketable condition; oil and gas that has not been separated, treated, and measured for royalty purposes has not been fully gathered and thus is not in marketable condition. Moreover, the commenters' position fails to recognize that the Deepwater Policy was an exception to the then-existing rules. Thus, even the Deepwater Policy acknowledged the movement would traditionally be considered gathering but allowed a lessee to claim such movement as part of its transportation allowance. Notably, the Deepwater Policy was never codified or otherwise made part of ONRR's regulations. It was properly set aside by the 2016 Valuation Rule because it was not a published rule and because it was inconsistent with published rules. As a result, the 2016 Valuation Rule clearly established, consistent with the language of the pre-existing regulations, that gathering does not end until oil and gas is separated, treated, and measured for royalty purposes.

Public Comment: A commenter supported the deepwater gathering allowance and claimed that industry relied on the Deepwater Policy between 1999 and 2016 when making financial investments and leasing and development decisions. This commenter suggested that retroactively eliminating the allowance would present legal vulnerabilities (stating that it was unlawful for ONRR to eliminate the deepwater gathering allowance considering that a lessee relied on it to make leasing and development decisions) and may disincentivize future investment and development on the OCS.

ONRR Response: The United States District Court for the District of Wyoming recently upheld ONRR's decision to rescind the deepwater gathering policy in litigation filed to challenge the 2016 Valuation Rule. See Cloud Peak Energy, Inc. v. Dep't of the Interior, Case No. 2:19-cv-00120-SWS, Order Upholding In Part And Reversing In Part 2016 Valuation Rule (D. Wyo. Sept. 8, 2021). Noting that ONRR “acknowledged and considered” reliance interests, the District Court stated that “ONRR considered the relevant information and articulated a rational basis based on the relevant information for its decision to vacate the Deep Water Policy.” Id. at 15. The District Court concluded that “Petitioners have not established that ONRR acted arbitrarily or capriciously, abused its discretion, or exceed[ed] its lawful authority by rescinding the Deep Water Policy.” Id.

Notably, the referenced reliance comment was general and not supported by discussion of specific leases or evidentiary materials. The commenter presented no evidence and did not explain how any specific investment was, in fact, premised on the future receipt of a relatively small allowance for gathering. Such general, unsubstantiated, and unquantified reliance interests do not outweigh the other interests and policy considerations that support withdrawal of the deepwater gathering allowance. 81 FR 43340.

An agency must comply with the APA to either promulgate new legally binding regulations or to substantively amend or modify existing regulations. The reasonableness of a lessee's reliance on an informal memorandum that directly contradicted the language of properly adopted rules is questionable. See, e.g., Glycine & More, Inc., v. United States, 880 F.3d 1335 (Fed. Cir. 2018). Even if the Deepwater Policy were found to qualify as a legally binding rule, standard OCS lease language illustrates that the reasonableness of expecting it to exist in perpetuity is also questionable. See Form BOEM-2005, § 1 (Feb. 2017) (“It is expressly understood that amendments to existing statutes and regulations . . . as well as the enactment of new statutes and promulgation of new regulations, which do not explicitly conflict with an express provision of this lease may be made and that the Lessee bears the risk that such may increase or decrease the Lessee's obligations under the lease.”). Moreover, to the extent any OCS lease contains terms consistent with the Deepwater Policy, those leases will continue to control regardless of any conflict with the valuation regulations. See 30 CFR 1206.100(d) and 1206.140(c); Form BOEM-2005, § 1 (Feb. 2017).

Public Comment: A commenter supporting the 2020 Rule's deepwater gathering allowance asserted that ONRR's elimination of the Deepwater Policy in the 2016 Valuation Rule violated both contract law and the APA. The commenter pointed to a term in Section 6(c) of the Form BOEM-2005 (Feb. 2017) OCS lease template. The commenter also cited Kerr-McGee Corp., 22 IBLA 124 (1975) to suggest that royalties to the Federal government should be the same regardless of whether it is paid in volume or value.

ONRR Response: Section 6(c) of the Form BOEM-2005 (Feb. 2017) OCS lease template is expressly limited to royalties paid in amount ( i.e., in kind), not in value: “When paid in amount, such royalties shall be delivered at pipeline connections or in tanks provided by the Lessee. Such deliveries shall be made at reasonable times and intervals and, at the Lessor's option, shall be effected either (i) on or immediately adjacent to the leased area, without cost to the Lessor, or (ii) at a more convenient point closer to shore or on shore, in which event the Lessee shall be entitled to reimbursement for the reasonable cost of transporting the royalty production to such delivery point.” The Secretary phased out the DOI's royalty-in-kind program starting in 2009. See 75 FR 15725. Moreover, lease terms govern if the lease terms are inconsistent with any of the valuation regulations. See 30 CFR 1206.100(d) and 1206.140(c). Thus, withdrawal of the deepwater gathering allowance would have no impact on the referenced lease term in the unique situation suggested by the commenter.

In addition, the commenter's reliance on Kerr-McGee Corp., 22 IBLA 124 (1975) is misplaced. Kerr-McGee was decided under the historic concept of “field” gathering and is devoid of any traditional contract law analysis. When the concept of “field” gathering was replaced in 1988 by the adoption of regulations containing a definition of gathering, that rulemaking also affected previously existing precedents that discussed the concept of “field” gathering. 53 FR 1184, 1193 (Jan. 15, 1988) (rejecting recommendations to “limit gathering to the lease or unit area so a transportation allowance may be obtained for all off-lease movement”); 53 FR 1230, 1240 (Jan. 15, 1988) (same); Devon Valuation Determination, at 18 (explaining how the regulatory definitions of gathering may impact precedents applying the historic concept of “field” gathering). As a result, the line between gathering and transportation may not be the same for royalties paid in amount and royalties paid in value. Compare Form BOEM-2005, § 6 (Feb. 2017) and 30 CFR 1206.20, 1206.110, and 1206.152.

Additionally, the commenter's statement that the elimination of the Deepwater Policy violated the APA is not supported by explanation or analysis. MMS' royalty and revenue management functions were transferred to ONRR in 2010. See 76 FR 64432 (Oct. 18, 2011). At that time, ONRR became responsible for MMS' regulations governing gathering and transportation. ONRR subsequently determined that the Deepwater Policy was inconsistent with the regulatory definitions of gathering and Departmental decisions interpreting that term. See 85 FR 62054, 62059 (Oct. 1, 2020); 80 FR 608, 624 (Jan. 6, 2015). Consequently, it rescinded the Deepwater Policy in the 2016 Valuation Rule. See id. This final rule affects the 2020 Rule, not any provision of the 2016 Valuation Rule.

2. Missing Regulatory Text

While the Proposed 2020 Rule's preamble explained ONRR's intention to adopt a deepwater gathering allowance in 30 CFR 1206.110 (oil) and 1206.152 (gas), consistent with the former Deepwater Policy, key components and criteria for a deepwater gathering allowance were omitted from the proposed regulation text. For oil, the Proposed 2020 Rule omitted language later added by the 2020 Rule that expanded the proposed allowance from oil produced in waters deeper than 200 meters to oil produced from a lease or unit any part of which lies in waters deeper than 200 meters. Cf. 85 FR 62080 with 86 FR 4654. The Proposed 2020 Rule further omitted other key requirements of the Deepwater Policy, including that the movement is not to a facility that is located on a lease or unit adjacent to the lease or unit on which the production originates, that the movement is beyond a central accumulation point, defined 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, and that the gathering costs are only those allocable to the royalty-bearing oil. Id. For gas, the Proposed 2020 Rule completely omitted the deepwater gathering allowance in the proposed regulation text for §  1206.152. See 85 FR 4656.

Because ONRR made significant, substantive additions to the §§  1206.110(a) and 1206.152(a) without reopening the comment period, the public had inadequate opportunity to review and comment on the substantially revised regulatory text prior to publication of the 2020 Rule. Accordingly, the adoption of a deepwater gathering allowance in the 2020 Rule was defective because ONRR did not give the public adequate notice of the intended regulatory language and the scope of the allowance.

Public Comment: A commenter stated that ONRR revealed, in the preamble to the Proposed 2020 Rule, an intention to revert back to the Deepwater Policy and that any prospective commenter could review the Deepwater Policy. This commenter noted that several commenters pointed out the error in the text language in response to the Proposed 2020 Rule, suggesting that interested entities had access to information sufficient to formulate meaningful comments.

ONRR Response: ONRR disagrees. The Deepwater Policy was not adopted through any recognized form of rulemaking. The proposed regulation text was not included in the Proposed 2020 Rule, despite a general discussion appearing in the Proposed 2020 Rule's preamble. Moreover, the absence of the regulation text created a high likelihood of confusion regarding the precise parameters of the allowance being proposed. Moreover, because the meaning of unambiguous regulatory text is not changed by conflicting preamble language, some commenters may have reviewed and commented on the proposed regulatory text without reading the preamble and its general discussion. Because much of the intended regulatory text was missing from the Proposed 2020 Rule, including key provisions relating to deepwater allowances, the public was not provided with adequate notice and an opportunity to comment.

3. Procedural Defects Specific to the Deepwater Gathering Provision

Prior to adopting the deepwater gathering allowance, ONRR was required to offer a rationale for the adoption of the amendment in order to allow interested parties a meaningful opportunity to comment. See Sections II.C and II.D. As its basis for the deepwater gathering allowance, the Proposed 2020 Rule stated that a lessee may be unable (without great costs, impaired engineering efficiency, or both) to satisfy ONRR's gathering definition before production reaches the platform due to unique environmental and operational factors in deepwater. 85 FR 62060. While this may be true for some deepwater leases, the 2020 Rule does not explain why these unique factors justify a deepwater gathering allowance that is applicable to all deepwater leases. Many locations, both onshore and offshore, have unique environmental and operational factors. The burdens placed on a lessee by the environment in which it operates are matters considered at the time the lease is issued, and reflected in the amount of bonus bids and, in some cases, the royalty rate. See 53 FR 1205 (Jan. 15, 1988). Thus, environmental and operational factors alone are inadequate justifications for a deepwater gathering allowance.

The 2020 Rule added new rationale for the deepwater gathering allowance. For example, the 2020 Rule stated that the Gulf of Mexico is currently viewed as a mature hydrocarbon province; that 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; that many of the remaining reserves are located in smaller fields that do not warrant stand- alone development and are unlikely to be developed absent subsea completions with tiebacks to existing platforms; that 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; and that the expected profitability of specific projects will be affected by a company's determinations of geologic and economic risk. 86 FR 4623.

However, the 2020 Rule cited no economic studies or research supporting this new rationale. It also did not explain why these facts, if true, justify a deepwater gathering allowance on all deepwater leases. Where gathering ends and transportation begins should not, for example, depend on whether a hydrocarbon reserve is mature. The maturity of a hydrocarbon reserve may be a factor that BLM, BSEE, or BOEM takes into consideration in setting royalty rates or granting royalty relief, but it is not a factor relevant to the determination as to where gathering ends. Finally, regardless of whether this new rationale might have been a legitimate basis for the deepwater gathering allowance, the public did not have a meaningful opportunity to comment on it because it was not stated in the 2020 Proposed Rule.

C. Extraordinary Processing Allowance

ONRR's valuation regulations allow a lessee to deduct the reasonable and actual costs incurred in processing gas. 30 CFR 1206.159(a)(1). A lessee cannot claim the processing allowance against the value of the residue gas. 30 CFR 1206.159(c)(1). Instead, it must allocate its processing costs among the other gas plant products, with NGLs being a single product. 30 CFR 1206.159(b). Additionally, the allowance cannot exceed 66 2/3 percent of the value of the gas plant product against which the allowance is taken. 30 CFR 1206.159(c)(2).

Prior to the 2016 Valuation Rule, ONRR could, upon request of a lessee, authorize a lessee to exceed the 66 2/3 percent cap. 53 FR 1281. Upon request of a lessee, ONRR could also authorize a lessee to claim an allowance for extraordinary processing costs actually incurred. Id. To qualify for an extraordinary processing allowance, a lessee's request had to demonstrate that the costs were, by reference to standard industry conditions and practice, extraordinary, unusual, or unconventional. Id.

The 2016 Valuation Rule eliminated ONRR's authority to allow a lessee to exceed the 66 2/3 percent cap and to take an extraordinary processing allowance. 81 FR 43353. The 2016 Valuation Rule also terminated any extraordinary processing allowances that ONRR previously approved. Id. At the time, there were two extraordinary processing allowances approved by ONRR for gas processed at two facilities in Wyoming. Id.

The 2020 Rule reinstated a lessee's ability to request to claim an extraordinary processing allowance but not its ability to request to exceed the 66 2/3 percent cap. 86 FR 4625-4626. The reinstatement of extraordinary processing allowances was justified as a way for ONRR to incentivize production or remove a disincentive to production having such costs. Id.

ONRR is withdrawing the extraordinary processing allowance amendment for the reasons stated in Sections II and III.A., and for the additional reasons below.

1. Unwarranted, Overbroad, and Unsupported Incentivization of Production

As discussed in Section III.A, ONRR's attempt to incentivize production through the adoption of the 2020 Rule, including through its reinstatement of a lessee's ability to apply for and receive an extraordinary processing allowance, is unwarranted. ONRR notes that no supporter of the 2020 Rule submitted a report or study demonstrating that the reinstatement of the extraordinary processing allowance would increase development or production. Moreover, this amendment is overbroad because it could potentially apply in areas where production is already profitable. Other DOI bureaus have programs in place to incentivize development or production where necessary. See Section III.A and 86 FR 31201-31202.

Public Comment: Some commenters asserted that the extraordinary processing allowance encourages continued and future production of unique hydrocarbon streams and the production of gas in atypical areas. Commenters also suggested that a few lessees may have relied on the historical extraordinary processing allowance approvals relating to the two processing facilities in Wyoming, and made investment decisions based on those then-existing approvals. These commenters opined that, absent the extraordinary processing allowances, the viability of lease operations associated with the two Wyoming facilities is questionable. Finally, some commenters stated that the extraordinary processing allowances are necessary to maximize hydrocarbon recovery, prevent waste due to premature lease abandonment, and provide a mechanism to reduce royalty payments when costs exceed profits.

ONRR Response: Although commenters assert that extraordinary processing allowances are needed to incentivize future production and ensure the viability of certain lease operations, no commenter provided support to show that, without the extraordinary processing allowances, a lessee would curtail production, or that ONRR's reinstatement of extraordinary processing allowances would increase gas production, including from leases serviced at the two Wyoming facilities. Notably, the preamble to the 2020 Rule recognized that the production impact of the rule's amendments, including the extraordinary processing amendment, is “negligible or marginal.” 86 FR 4616. Further, the historical rarity of submissions and approvals of applications for extraordinary processing allowances suggests that extraordinary processing allowances do not incentivize production to the degree commenters assert. In the almost 30 years an extraordinary processing allowance could have been sought, fewer than ten applications were submitted and only two were approved, neither of which was approved after 1996. To the extent that potential waste, premature lease abandonment, or production profitability are legitimate concerns, other bureaus within the DOI may have programs designed to address those issues.

Public Comment: A commenter asserted that the extraordinary processing allowance is needed to increase helium production because helium is critical for national security.

ONRR Response: ONRR's gas valuation regulations do not apply to helium. See Exxon Corp., 118 IBLA 221, 229 n.9 (1991) (noting that MMS does not consider helium in valuing a gas stream for royalty purposes because “it is not a leasable mineral”). Rather, helium production from Federal lands is administered by BLM and governed by the Helium Stewardship Act of 2013, codified at 50 U.S.C. 167-167q, and BLM regulations, 43 CFR part 16. See also https://www.blm.gov/​programs/​energy-and-minerals/​helium/​division-of-helium-resources (noting that BLM's Division of Helium Resources “adjudicates, collects, and audits monies for helium extracted from Federal lands”). Thus, any responsibility to incentivize helium production lies with BLM, not ONRR.

The 2020 Rule stated that “allowing a lessee to apply for an extraordinary processing allowance approval for the natural gas portion of [its] production stream, may lower natural gas production costs and incentivize new or continued production of helium.” 86 FR 4628. But as noted in Section III.A above, ONRR lacks evidence to substantiate that an extraordinary processing allowance will incentivize gas production, and more particular to this discussion, lacks evidence that an extraordinary processing allowance is likely to boost helium production. Moreover, of the two prior extraordinary processing allowances that ONRR approved, only one impacted a helium-bearing gas stream. Likewise, none of the public comments contain any support for the proposition that reinstating the extraordinary processing allowance will result in additional helium production from this stream. Thus, even if the United States has “important economic and national security interests in ensuring the continuation of a reliable supply of helium”—as noted in the 2020 Rule and referenced in the public comment—the extraordinary processing allowance has not been shown to be an effective means to increase helium production. Id.

Finally, DOI recently implemented other statutory shifts that encourage investment in helium production, but which were not mentioned in the 2020 Rule or by the commenter. The Dingell Act, Public Law 116-9, Section 1109, “Maintenance of Federal Mineral Leases Based on Extraction of Helium,” amended the MLA on March 12, 2019, to allow the production of helium to maintain a Federal oil and gas lease beyond its primary term. See 30 U.S.C. 181 (“extraction of helium from gas produced from such lands shall maintain the lease as if the extracted helium were oil and gas”). Prior to this amendment, the initial ten-year lease term could only be extended if oil or gas, not helium, was produced in paying quantities. A consequence of the prior MLA framework was that revenue from the sale of helium was not factored into whether a well was producing in “paying quantities” and thus qualified for an extension of the initial lease term beyond ten years. The shift away from considering only the production of oil and natural gas as holding the lease seems likely to encourage investment in helium production. The targeted amendment to the MLA negates any contention that the modest relief potentially available through an extraordinary processing allowance is effective to encourage helium production.

2. ONRR's Authority To Modify Processing Allowance Regulations

Public Comment: A commenter suggested that withdrawing ONRR's authority to permit extraordinary processing allowances would improperly inflate royalties due because a lessee cannot deduct its reasonable, actual gas processing costs as allowed under the gas valuation rules. The commenter further noted that the Proposed Withdrawal Rule does not question whether the previously approved extraordinary processing allowances comprised reasonable, actual processing costs for qualifying operations.

ONRR Response: ONRR agrees that the gas valuation rules permit a lessee to deduct most reasonable and actual gas processing costs. 30 CFR 1206.159(a)(1). But gas processing allowances have never been without limits. Rather, the mineral leasing statutes recognize ONRR's authority to create and subsequently modify regulations, including those related to processing allowances. See, e.g., 30 U.S.C. 189 (authorizing the Secretary, under the MLA, to “prescribe necessary and proper rules and regulations and to do any and all things necessary to carry out and accomplish the purposes of this chapter”); 43 U.S.C. 1334(a) (authorizing the Secretary to “prescribe such rules and regulations as may be necessary to carry out” the provisions of OCSLA); 30 U.S.C. 1751(a) (authorizing the Secretary, under FOGRMA, to “prescribe such rules and regulations as he deems reasonably necessary to carry out this chapter”).

The MLA, OCSLA, and FOGRMA do not define “royalty value.” None of those statutes mention processing costs, let alone mandate adoption of regulations allowing a deduction for processing costs. Instead, the agency-developed regulations at 30 CFR part 1206 to authorize processing allowances. The agency established the deductions by regulation and is authorized to change the regulations, as it did here. In Cloud Peak Energy Inc. v. U.S. Dep't of the Interior, 415 F. Supp. 3d 1034, 1046 (D. Wyo. 2019), the United States District Court for the District of Wyoming commented on the “wide latitude of discretion” ONRR has to enact “rules and regulations enabling [the DOI] to complete the tasks it [is] assigned.” This discretion would necessarily include the ability to change allowances adopted by regulation. Id. at 17, 24, 29; see also Am. Trucking Ass'ns v. Atchison, Topeka, & Santa Fe Ry. Co., 387 U.S. 397, 416 (1967) (stating that “[r]egulatory agencies do not establish rules of conduct to last forever”); FCC v. Fox Television Stations, 556 U.S. 502, 515 (2009) (recognizing agency authority to change regulatory course).

Public Comment: A commenter asserted that the extraordinary processing allowance prevented receipt of fair market value for minerals extracted from Federal land and should be withdrawn.

ONRR Response: ONRR is withdrawing the extraordinary processing allowance for the reasons discussed herein, consistent with the comment.

3. Additional Administrative Burden and Reduced Royalties

The 2020 Rule states that “ONRR anticipates . . . it will again receive very 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.” 86 FR 4628. Consistent with this, a commenter asserts that ONRR will not be impacted if it reinstates its authority to approve extraordinary processing allowances because ONRR maintains control of the approval process and is not required to grant all requests. Notably, however, when ONRR drafted the 2020 Rule, no consideration was given to the potential interplay between the reinstatement of ONRR's authority to permit extraordinary processing allowances and the retention of the hard cap on processing allowances, which could impact the number of extraordinary processing allowance applications submitted.

Prior to the adoption of the 2016 Valuation Rule, a lessee could apply, under specified circumstances, for an extraordinary processing allowance and to exceed the soft cap of 66 2/3 percent on processing allowances. The 2016 Valuation Rule eliminated extraordinary processing allowances and changed the soft cap to a hard cap ( i.e., a firm limit on the processing allowance cap). See 30 CFR 1206.159(c)(2). The Proposed 2020 Rule proposed to reinstate both the extraordinary processing allowance and soft caps. 85 FR 62058.

Between the publication of the Proposed 2020 Rule and the publication of the 2020 Rule, ONRR performed a new economic analysis. Based thereon, the 2020 Rule reinstated ONRR's authority to permit extraordinary processing allowances but did not restore a lessee's ability to seek to exceed the cap on processing allowances. 86 FR 4625. Thus, under the 2020 Rule, an extraordinary processing allowance application is the only mechanism by which a lessee can request to exceed limits on processing allowances, a circumstance that might cause ONRR to receive more applications for approval of an extraordinary processing allowance than it did historically. ONRR did not consider this possibility or the effect on royalty payments that might result if additional extraordinary processing allowance requests are submitted and approved.

Public Comment: Some commenters stated that ONRR will not be impacted if it reinstates its authority to approve extraordinary processing allowances because ONRR maintains control of the approval process and is not required to grant all requests.

ONRR Response: While the comments regarding the broad discretion of the approval process are generally valid, the comments are not sufficiently specific for ONRR to act on. Moreover, reinstatement of ONRR's authority to permit extraordinary processing allowances may create the unintended and unanticipated consequences discussed above. ONRR must analyze those circumstances before it could permit the extraordinary processing allowance to go into effect.

4. Procedural Defects Specific to the Extraordinary Processing Allowances

The Proposed 2020 Rule failed to provide a reasoned explanation, or adequate justification for the change, as required under the APA to provide sufficient notice to the public of the reasons for the reinstatement of the extraordinary processing allowance. See Sections II.C and II.D.

First, ONRR published the Proposed 2020 Rule on October 1, 2020. At that time, the 2016 Valuation Rule was reinstated for only eighteen months, but lessees had not yet been required to comply with the rule. Thus, ONRR had, at most, a limited opportunity to assess the impact of the withdrawal of its authority to permit extraordinary processing allowances.

Second, in the Proposed 2020 Rule, the amendment was premised on the notion of incentivizing production. See 85 FR 62058. However, the 2020 Rule contained inconsistent positions on incentivization. In response to public comments, the 2020 Rule stated that it was “not premised on increasing production of oil, gas or coal by some measured amount” and instead was “meant to incentivize both the conservation of natural resources . . . and domestic energy production over foreign energy production.” 86 FR 4616. The 2020 Rule also stated that the anticipated impact of the rule's amendments on production would be “negligible.” 86 FR 4626. The 2020 Rule similarly stated that, in most cases, allowing a lessee to exceed the processing allowance cap would not be sufficient to incentivize production. See 86 FR 4626-4629 (noting a lessee's greater royalty share of production negates any incentive to continue producing from a Federal lease under suboptimal circumstances). Further, neither the Proposed 2020 Rule nor the 2020 Rule explained the purported connection between the extraordinary processing allowance and increased production.

Finally, the public was not provided a meaningful opportunity to comment on the rationale that ultimately formed the basis for the reinstatement of the extraordinary processing allowance because it was not set forth in the Proposed 2020 Rule. Apart from an unpersuasive argument about incentivizing production, ONRR relied entirely on reasons submitted in response to the Proposed 2020 Rule to support its reinstatement of the extraordinary processing allowance. See 86 FR 31204 (identifying five additional justifications in the 2020 Rule for reinstatement of the extraordinary processing allowance, each of which was based on comments submitted in response to the Proposed 2020 Rule). Therefore, the public did not have an opportunity to comment on most of the reasons contained in the 2020 Rule to justify the reinstatement of the extraordinary processing allowance.

D. Index Prices

1. Unwarranted Change From Highest Bidweek Price to Average Bidweek Price

For the first time, the 2016 Valuation Rule allowed a lessee to calculate the royalty value of its production by using an index-based valuation formula for its non-arm's-length sales of Federal gas, instead of actual sales prices, transportation costs, and processing costs. 30 CFR 1206.141(c) and 1206.142(d). This index-based valuation method is required if there is an index pricing point and the lessee has no written contract for the sale of the gas or there is no sale of the gas, which is the case for approximately 0.3 percent of all Federal gas. 30 CFR 1206.141(e) and 1206.142(f). The index-based valuation formula is otherwise optional. 30 CFR 1206.141(c) and 1206.142(d).

Under the 2016 Valuation Rule, a lessee electing to use the index-based valuation formula must report and pay royalties based on the highest bidweek price for the index pricing points to which the gas could flow, reduced by an amount intended to account for average transportation costs. 30 CFR 1206.141(c)(1) and 1206.142(d)(1). The 2016 Valuation Rule considered and rejected comments that using the highest bidweek price results in an inflated value for royalty purposes, which is neither reasonable nor justified. 81 FR 43347. ONRR disagreed with those comments, stating that the “provision protects the interests of the Federal lessor, while also simplifying the royalty reporting process for industry.” Id.

The 2020 Rule amended the index-based valuation formula by substituting the average bidweek price for the highest bidweek price. 86 FR 4619. The 2020 Rule posited that “[w]hile 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.” 86 FR 4619-4620. Using an average, however, means that there are transactions where a lessee receives a higher price. And because index-based pricing is optional for all but 0.3 percent of Federal gas, a lessee who generally receives more than the average bidweek price could choose to report and pay based on the average bidweek price in order to reduce its royalty obligations, as could a lessee with lower than average transportation costs.

Conversely, a lessee who generally receives less than the average bidweek price or pays higher than average transportation costs could continue to report and pay royalties based on its actual sales and transaction data specific to the gas at issue rather than the index-based valuation formula. Thus, a lessee could avoid higher royalties by not using the index-based valuation option. 30 CFR 1206.141(c), 1206.142(d). In other words, a lessee would have an increased opportunity to pay royalties on the lower of two values. As a result, changing the formula to reduce the bidweek price used from highest to average is expected to reduce total Federal gas royalties due the United States by $5,062,000 per year, as detailed in the Economic Analysis, below.

In adopting the 2020 Rule, ONRR was required to explain why it was rejecting the position it adopted in the 2016 Valuation Rule that the use of the highest bidweek price is necessary to protect the interests of the Federal lessor. See California, 381 F. Supp. 3d at 1173-74. Use of the highest bidweek price helps ensure that the United States receives a fair market value, while allowing a lessee the option of a formula if the lessee is motivated to save on administrative costs incident to reporting, payment, and potential audit of actual sales prices, transportation costs, and processing costs, as well as the cost of any ensuing disputes. For the reasons described in Section II, which discusses various defects in the promulgation of the 2020 Rule, and III.A, which describes ONRR's unwarranted and overbroad attempt to incentivize production, and because the 2020 Rule did not adequately explain why it was shifting to average index prices, ONRR withdraws this provision of the 2020 Rule.

Similarly, the use of the highest bidweek price is consistent with frequently-seen royalty schemes—the lessee is required to pay the lessor on the higher or highest of multiple measures of royalty value to protect against valuation measures that may prove inapplicable or otherwise fail in some instances, and to minimize the impact of any self-dealing or exercise of poor business judgment. See, e.g., Federal and Indian lease and regulation provisions requiring payment based on (a) a major portion price if higher ( see 30 CFR 1206.54 and 1206.174(a)(4) and 47 FR 47774 (Oct. 27, 1982)), (b) the value of gas as unprocessed gas if higher than the value of gas as processed gas (30 CFR 1206.176 and 52 FR 1257 (Jan. 15, 1988)), and (c) no less than gross proceeds (30 CFR 1206.174(g) and 53 FR 1275 (Jan. 15, 1988)) ; see also, Competitive Oil and Gas Lease, State of Alaska, Department of Natural Resources, Sec. 36(a), https://dog.dnr.alaska.gov/​Documents/​Leasing/​SaleDocuments/​AKPeninsula/​2016/​LeaseForm-DOG201503.pdf , which requires royalty payments based on the highest of four measures of value; and Oil and Gas Lease, State of Wyoming, Sec. 1(d)(iv), https://lands.wyo.gov/​trust-land-management/​mineral-leasing/​oil-gas-leases,, which requires payment based a value no less than that received by the United States for its royalties in the same field.

Public Comment: Some commenters stated that by requiring the highest bidweek price, ONRR is extracting royalties above what it may be entitled to receive because the average bidweek price is more representative of the gross proceeds that a typical lessee may receive.

ONRR Response: With very minor exceptions, no lessee is required, but rather elects, to use the index-based valuation option for its non-arm's-length gas sales. 30 CFR 1206.141(c) and 1206.142(d). A lessee that concludes that its use of the index-based valuation formula would increase its royalty obligation above what it considers due the United States does not have to use the formula. Moreover, neither the governing statutes nor lease terms cap royalty value at an individual lessee's gross proceeds or typical or average gross proceeds. Also, as referenced above, lessors frequently require that royalties be paid on the highest of multiple measures of royalty value, including measures that may exceed a lessee's average gross proceeds.

Public Comment: Some commenters opposed the withdrawal of the 2020 Rule, alleging it creates inconsistency between valuation of Federal gas, Federal oil, and Federal NGLs. Another commenter stated it creates an inconsistency with Indian gas valuation.

ONRR Response: No statute or lease term requires identical treatment for Federal oil, Federal NGLs, Federal gas, and Indian gas, and there are many instances where those commodities are treated differently. Cf. 30 CFR 1206.153(b)(1) (allowing a transportation allowance for Federal gas for the unused portion of an arm's-length contract's firm demand fee) with 30 CFR 1206.178 (allowing only the used portion of that fee for Indian gas).

Furthermore, with respect to the difference between Federal residue gas and NGLs, index-based valuation is, in most instances, an optional reporting methodology. See 30 CFR 1206.141(c) and 1206.142(d). In designing an optional reporting methodology, ONRR strives to find a path that ensures it receives a fair return. As a result, ONRR determined in the 2016 Valuation Rule that a lessee who elects to use the index-based valuation option must apply the highest bidweek price to value its residue gas. 81 FR 43347. On the other hand, because it is optional for all but a small number of lessees, most lessees can eschew the option and, instead, use actual sales prices, transportation costs, and processing costs.

Public Comment: Some commenters wrote that using the highest bidweek price instead of the average bidweek price will reduce the number of lessees that elect to use index-based pricing.

ONRR Response: ONRR is under no statutory obligation to offer an index-based pricing option. If, as reporting under the index-based valuation option in 2016 continues, lessees' reporting shows no or insignificant use of index-based reporting, ONRR will have data upon which to evaluate the further use of index-based reporting, including the possible need to amend the price. However, at this time, ONRR believes use of the highest bid-week price is necessary to ensure that the Federal lessor receives fair market value for its mineral resources.

2. Defective Reduction to Index To Account for Transportation

The 2016 Valuation Rule's index-based valuation method provided for a reduction to index prices to account for transportation costs. The amount of the reduction was calculated by ONRR based on ONRR's review and analysis of lessee-reported transportation costs for production years 2007-2010. For those years, the average reported transportation cost for the Gulf of Mexico was 4.6 percent of index value, and for all other areas, it was 8.6 percent of index value. In the 2016 Valuation Rule, the index-based valuation formula included a 5 percent reduction to index for the Gulf of Mexico and a 10 percent reduction for all other areas. 30 CFR 1206.141(c)(1)(iv) and 1206.142(d)(1)(iv).

Since the promulgation of the 2016 Valuation Rule, ONRR conducted a similar economic analysis for three other time periods. One of those time periods predated the Proposed 2020 Rule and ONRR's drafting of the final 2020 Rule. That period was used as a basis for the 2020 Rule. For production years 2014-2018, ONRR's analysis showed average lessee-reported transportation costs of 13.7 percent for the Gulf of Mexico and 16.8 percent for all other areas. Based on this information, the 2020 Rule increased the reductions to index from 5 percent to 10 percent for the Gulf of Mexico and from 10 percent to 15 percent for all other areas, again bounded by certain minimum and maximum amounts. 86 FR 4655.

Since publication of the 2020 Rule, ONRR conducted two additional analyses—one of production years 2016-2020 and the second for production years 2007-2020. These analyses showed average lessee-reported transportation costs of 19.6 percent and 14 percent for the Gulf of Mexico and 16.6 percent and 16.9 percent for all other areas, respectively.

In ONRR's experience, lessee-reported transportation costs may overstate allowable transportation costs for several reasons. First, costs reported at or soon after the time of production are estimates, and while, under 30 CFR 1210.30, a lessee must amend its reported royalties within 30 days of the discovery of an error, a lessee generally has up to six years after its initial royalty reporting is due to amend its reported costs. 30 U.S.C. 1721a(a). As a result, reported costs for recent time periods can be unreliable.

Second, a lessee frequently claims transportation costs in excess of the amounts allowed. Too often, a lessee fails to reduce the charges of an affiliated or third-party pipeline service provider to eliminate non-allowable costs such as gathering costs and other expenses of placing gas in marketable condition. While ONRR audits a lessee's reports to determine if excessive transportation allowances have been claimed, ONRR has seven years within which to do so. 30 U.S.C. 1724(b)(1). Thus, reported costs for recent time periods are potentially unreliable.

Finally, ONRR does not have sufficient resources to audit or conduct other compliance activities on every reported transportation allowance. As a result, some overstated allowances will be missed. For all these reasons, reported—and particularly recently-reported—transportation costs may be higher than the reduction to index ONRR authorizes to account for transportation in any index-based valuation method.

Further, for the reasons discussed above in evaluating whether to use high or average bidweek prices, ONRR should err, if at all, by allowing lower rather than higher reductions to index prices to account for the lessee's transportation costs in any index-based valuation option.

ONRR is withdrawing the 2020 Rule for the reasons set forth in Section II. Nonetheless, the over-time increase in reported transportation costs relative to index is notable. Absent the other flaws in the 2020 Rule discussed in Sections II and III.A of this final rule, ONRR might conclude in a future rulemaking following notice and comment that it is appropriate to increase the reduction to index to account for transportation in much the same way as it did in the 2020 Rule. But any such action will take place in a separate rulemaking action, and this provision of the 2020 Rule is withdrawn at this time due to the deficiencies of the 2020 Rule.

3. Unwarranted Expansion of Index-Based Valuation Option to Arm's-Length Gas Sales

The 2016 Valuation Rule introduced the index-based valuation option for Federal gas disposed of in non-arm's-length transactions, which most often take the form of sales by a lessee to its affiliate. 30 CFR 1206.141(c) and 1206.142(d). The 2016 Valuation Rule considered and rejected comments strongly urging that the index-based valuation option also be available for arm's-length transactions, stating that “[g]ross proceeds under valid arm's-length transactions are the best measure of value.” 81 FR 43347.

The 2020 Rule expanded the index-based valuation option to Federal gas sold at arm's-length. 86 FR 4613. For the reasons described in Sections II and III.A, and the additional reasons set forth below, ONRR is withdrawing its expansion of the index-based valuation option to arm's-length sales, subject to the possibility of revisiting the topic in future rulemaking.

ONRR generally considers a lessee's arm's-length sale of gas to be the best indicator of value. 86 FR 4618. This position was reiterated in the 2020 Rule. Id. This indicator of value, however, is not always available when a lessee sells gas to its affiliate or otherwise disposes of gas in non-arm's-length transactions. Index prices can be a more reliable indicator of value than affiliate and other non-arm's-length sales prices because they are based on reported arm's-length sales. But an index-based valuation formula generally is not as reliable a measure of royalty value as is the use of actual sales prices, transportation costs, and processing costs obtained or incurred in arm's-length transactions. This is because, at a minimum, the implicit transportation deduction included in the index-based valuation formula is based on an average of all reported transportation costs for either the Gulf of Mexico or all other areas of the nation, and therefore is most often higher or lower than the transportation costs actually incurred for the gas being valued.

The 2016 Valuation Rule recognized this, reasoning that index prices are published prices derived from reported arm's-length transactions. ONRR considered the index-based valuation formula included in the 2016 Valuation Rule a simpler, acceptable, and potentially preferrable method to value gas disposed of in non-arm's-length (or affiliate) transactions. 81 FR 43338, 43346-43348. In short, under the 2016 Valuation Rule, the index-based valuation option allowed a lessee to, in effect, use a compilation of arm's-length transaction data to value gas not sold at arm's-length.

ONRR should have offered justification for why the 2020 Rule was adopting a provision expressly rejected by the 2016 Valuation Rule-declining to extend index-based valuation to arm's-length transactions-but it did not. See Section II.D. Using an index-based valuation formula to value arm's-length sales of Federal gas is problematic. For arm's-length transactions, the generally best indicator of value is typically available, and it is based on actual arm's-length transaction data specific to the gas at issue. 30 CFR 1206.141(b) and 1206.142(c). Nonetheless, the 2020 Rule extended the index-based option to gas sold at arm's-length. 86 FR 4618. The decision to do so was unsupported and premature, though ONRR may reexamine the issue in the future, after it has sufficient time to review, audit, and compare royalties received for index-based valuation of Federal gas sold at non-arm's-length and actual transaction data for Federal gas sold at arm's-length received after the reinstatement of the 2016 Valuation Rule. At this time, ONRR cannot determine whether the index-based valuation option adequately protects Federal and State royalty interests in Federal gas sold at arm's-length. Therefore, ONRR withdraws this portion of the 2020 Rule.

Public Comment: A few commenters, including multiple States, supported the withdrawal of the extension of the index-based option, asserting that ONRR should gain experience in administering an index-option for non-arm's-length sales before expanding index-based reporting into other areas. Similarly, commenters also stated but did not explain that extension of the index-based option is premature in light of pending Federal court litigation in Cloud Peak Energy Inc. v. U.S. Dep't of the Interior, No. 19-cv-120-SWS (D. Wyo.).

ONRR Response: ONRR agrees that the extension of the index-based option to arm's-length gas sales is premature at this time.

Public Comment: One commenter supported the withdrawal of this provision of the 2020 Rule because index prices and the index-based valuation option are not sufficiently transparent to the public.

ONRR Response: ONRR is withdrawing this provision of the 2020 Rule for reasons discussed in this final rule. ONRR monitors published index points to verify they meet specific liquidity requirements defined on onrr.gov. Additionally, index price publication companies have many checks in place to ensure the prices reported are transparent and representative of the market. They analyze transactions reported to the publication and validate any prices outside of a predetermined threshold. They also monitor and publish the number of reported trades and the total volumes associated with those trades.

Public Comment: Some commenters asserted that withdrawal of this portion of the 2020 Rule will increase administrative burdens; require lessees to maintain cross-departmental unbundling teams to analyze and continuously update unbundling cost methodologies; require lessees to obtain proprietary information from processors or make their best guess when the data is not provided; and increase the number of unbundling-related compliance reviews and audits, as well as the administrative and legal costs to respond to such compliance reviews and audits.

ONRR Response: ONRR acknowledges that a lessee would realize an administrative cost savings if the index-based valuation option were available for arm's-length sales. In the Economic Analysis below, ONRR has estimated the administrative cost savings to lessees to be $1,077,000 per year. Further, ONRR has estimated that the 2020 Rule's extension of the option to arm's-length sales would reduce lessees' royalty payments by $7,460,000 per year otherwise due the United States ($6,800,000 for gas plus $660,000 for natural gas liquids (“NGLs”)). A lessee's cost savings, as outlined in the Economic Analysis, also does not change the fact that actual arm's-length sales, transportation, and processing data specific to the gas being valued are most often better measures of its value than a formula derived from reported data relating to indices compiled from data relevant to other arm's-length transactions.

Among the obligations that Congress placed on the Secretary is the responsibility to audit lessee's royalties and reporting. 30 U.S.C. 1711(c). A lessee, operator, or other person directly involved in developing, producing, transporting, purchasing, or selling oil or gas must establish and maintain any records that the Secretary may require. 30 U.S.C. 1713(a) and 30 CFR 1212.50-1212.52. ONRR and its predecessor agencies, as the Secretary's designees, have historically performed audits based on the records the commenters find burdensome to maintain or acquire and produce. Further, ONRR's methods have been upheld by Federal Courts. Devon Energy Corp. v. Kempthorne, 551 F.3d 1030 (D.C. Cir. 2008), aff'g Devon Valuation Determination; Amoco Prod. Co. v. Watson, 410 F.3d 722 (D.C. Cir. 2005), aff'd sub nom. BP Am. Prod. Co. v. Burton, 549 U.S. 84 (2006); Burlington Res. Oil & Gas Co., 183 IBLA 333 (Apr. 23, 2013), aff'd 2014 WL 3721210 (N.D. Okla. July 24, 2014). When a lessee produces Federal oil and gas, it is foreseeable that it may be subject to ONRR compliance activities, including audit, and will incur associated administrative costs.

The commenters also ignore the fact that Federal oil and gas lessees have long been subject to the marketable condition rule, which is the source of the obligation to unbundle. Lessees are aware of the information and accounting that is required to comply with the marketable condition rule. Federal oil and gas lessees have long been required to calculate their gross proceeds, deduct transportation costs and processing costs, and segregate out (or unbundle) any marketable condition expenses if they seek to report the lowest allowable royalty value for gas. Further, in addition to entering into Federal oil and gas leases, lessees voluntarily enter into contracts with third-party and affiliate buyers, transporters, and processors. Nothing prevents each lessee from requiring its counterpart, by contract or otherwise, to provide the information necessary to accurately report royalty value, including the costs justifying the lessee's allowances. The Federal Government and its State beneficiaries are not obligated to save lessees the administrative costs of doing so.

Finally, even assuming arguendo that E.O.s 13783 and 13795 and S.O.s 3350 and 3360 policy objectives can still be relied upon, the 2020 Rule did not sufficiently support how the index-based option promotes its stated objective. The 2020 Rule states that it “[wa]s not premised on increasing the production of oil, gas, or coal by some measured amount,” but rather to generally “incentivize both the conservation of natural resources (by extending the life of current operations) and domestic energy production over foreign energy production.” 86 FR 4616. Because this conclusory statement is made without any supporting data, ONRR cannot determine, at this time, whether the 2020 Rule's extension of the index-based valuation provision to arm's-length sales would result in additional production. Thus, it was unsupported and must be withdrawn.

Public Comment: Some commenters opposed the withdrawal of this provision of the 2020 Rule because doing so reintroduces uncertainty in valuing Federal gas sold under arm's-length contracts.

ONRR Response: A lessee knows the amount at which it contracts to sell, transport, and process its gas. To ensure its compliance with its royalty reporting and payment obligations, the lessee can contract with the transporter or processor to require sharing of the information needed to accurately report royalty value. As long as a lessee negotiates contracts in a manner that allows it to meet its royalty obligations, its own actions minimize uncertainty. ONRR is not required to adopt an index-based valuation option for arm's-length sales simply because some lessees failed to secure rights to the data necessary to support the lessee's reported allowances.

Public Comment: One commenter stated that ONRR's revised economic analysis is an insufficient justification for a withdrawal of the index amendments because the difference between the 2020 Rule estimates as compared to the revised index analysis is nominal. According to the commenter, ONRR has collected $9 billion in royalties, rents and bonuses from oil and gas production per year over the past decade, and the 2020 Rule results in a $20.6 million decrease of in royalty collections per year, which equates to only a 0.2 percent decrease in average annual revenue collected. The commenter concluded that this achieves ONRR's objective of promulgating revenue neutral regulations.

ONRR Response: The 2020 Rule's economic analysis estimated that extending the index-based valuation option to arm's-length sales would increase royalties paid to the United States by $26,741,000 per year, but that the rule as a whole would decrease royalties paid by $28,879,000 per year. 86 FR 4641. The Proposed Withdrawal Rule and this final rule have improved on the methodology used to estimate economic impacts and now quantify the 2020 Rule's effect on royalties as follows: Extending the index-based valuation option to arm's-length sales would decrease royalties paid to the United States by $7,460,000 per year, and the 2020 Rule as a whole would decrease royalties paid by $64,600,000 per year. Cf. 86 FR 31208 with Economic Analysis, below.

ONRR does not consider these impacts revenue neutral. Further, judging the impact of an optional change in valuation available for some but not all Federal gas to the entirety of revenues from Federal oil, gas, coal, and other minerals distorts its significance. Finally, ONRR is not basing its withdrawal of any one of the five provisions discussed in this Section III on whether it incentivizes production or impacts revenue alone, but on the entirety of considerations discussed in this final rule. ONRR is withdrawing the five provisions for the additional reasons set forth in Section II above, and the defects set forth in this Section III further support withdrawal of the 2020 Rule.

IV. Other Public Comments Received in Response to the Proposed Withdrawal Rule

The following addresses additional comments received in response to the Proposed Withdrawal Rule.

A. Impacts of Frequent Rule Changes on Industry

Public Comment: Rule changes are costly and time consuming. Commenters stated that, if new rules or rule revisions become more frequent, confusion increases, and industry will be tempted to not make changes because industry may anticipate that those rules will be reversed in a few years. Commenters stated that rules should not change with each new administration, especially reversing and re-doing the rules every term. One commenter expressed its desire to see an ONRR rule that is fair and equitable for both sides.

ONRR Response: ONRR agrees that rule changes should not be based solely on a change in administration. However, duly promulgated rule changes can reduce confusion by eliminating ambiguities, addressing new industry practices and technology, or otherwise improving the regulations. In addition, ONRR must update and modernize its regulations when necessary and appropriate. In doing so, ONRR strives to promulgate fair and equitable regulations compliant with governing law. Consistent with this, ONRR is withdrawing the 2020 Rule. See Sections II and III.

B. Reliance on E.O.s Now Revoked

Public Comment: A few commenters referenced E.O.s that ONRR cited during the promulgation of the 2020 Rule that have since been revoked. Specifically, the commenters cite E.O. 13783 (Promoting Energy Independence and Economic Growth) and E.O. 13795 (Implementing an America-First Offshore Energy Strategy). Commenters also cite E.O.s now in effect, including E.O. 13990 (Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis, 86 FR 7037 (Jan. 25, 2021)).

ONRR Response: ONRR acknowledges that E.O.s 13783 and 13795 were revoked after the publication of the 2020 Rule but before its effective date. ONRR likewise acknowledges the E.O. 13990 directs agencies to consider certain matters such as science and climate change. ONRR's statutory directives pertain to the collection of royalties based on the fair market value. ONRR has no statutory framework within which to consider climate change as part of its rulemakings. ONRR addressed similar comments in the Proposed Withdrawal Rule. See 86 FR 31205.

C. Royalty Impacts to States

Public Comment: A commenter stated that the 2020 Rule failed to consider certain reasons for promulgating the 2016 Valuation Rule, such as ensuring the accurate calculation of royalties, which may be subsequently disbursed to States sharing in royalty revenues.

ONRR Response: ONRR distributes the royalties that it collects under Federal oil and gas leases as directed by the relevant disbursement statutes. See 30 U.S.C. 191(a) and 43 U.S.C. 1337(g)(2) and (7); see also 30 CFR part 1219. The Proposed 2020 Rule, the 2020 Rule, the Proposed Withdrawal Rule and this final rule estimate the impact of the amendments to States that share in royalty revenues in the respective sections entitled Economic Analysis. See 85 FR 62069-62070 and 86 FR 4649, 31214-31215.

D. Comments on the Merits of the Revenue-Neutral Amendments

Public Comment: ONRR received comments supporting and opposing withdrawal of some of the revenue-neutral amendments.

ONRR Response: ONRR is withdrawing the 2020 Rule for the reasons set forth above. As stated above, ONRR plans to publish proposed rules on some or all of the topics covered by the now withdrawn amendments.

V. Economic Analysis

ONRR's economic analysis of withdrawal of the 2020 Rule remains unchanged following publication of the Proposed Withdrawal Rule, except for the one-time administrative cost associated with the optional use of the index-based valuation method. The economic analysis is set forth in the Proposed Withdrawal Rule (86 FR 31208-31215) and summarized again below.

ONRR recognizes that estimated changes to royalty obligations and regulatory costs in the 2020 Rule impact many groups, including the Federal Government, State and local governments, and industry. These potential changes to royalty obligations can have broader impacts beyond the amount of royalties. Royalty collections are used by these governments in a variety of ways that include funding projects, developing infrastructure, and fueling economic growth.

Further, changes to royalties are transfers that are distinguishable from regulatory costs or cost savings. The estimated changes in royalties would affect 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 withdrawal of the 2020 Rule is an estimated $64.6 million annual increase in royalty collections over what would have been realized if the 2020 Rule went into effect.

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.

Estimated Changes to Royalty Collections Resulting From Withdrawal of the 2020 Rule

[Annual]

Rule provision	Net change in royalties paid by lessees
Index-Based Valuation Method Extended to Arm's-Length Gas Sales	$6,800,000
Index-Based Valuation Method Extended to Arm's-Length NGL Sales	660,000
Highest to Average Bidweek Price for Non-Arm's-Length Gas Sales	5,062,000
Transportation Deduction Non-Arm's-Length Index-Based Valuation Method	8,033,000
Extraordinary Processing Allowances	11,131,000
Allowances for Certain OCS Gathering Costs	32,900,000
Total	64,600,000

ONRR also estimated that the oil and gas industry would face increased annual administrative costs of $2.8 million under the 2020 Rule. As discussed below, this is the net impact of various cost increasing and cost saving measures. Withdrawal of the 2020 Rule will result in an estimated net cost savings for industry.

Summary of Annual Administrative Impacts to Industry From Withdrawal of the 2020 Rule

Rule provision	Cost (cost savings)
Administrative Cost for Index-Based Valuation Method for Gas & NGLs	$1,077,000
Administrative Cost Savings for Allowances for Certain OCS Gathering	(3,931,000)
Total	(2,850,000)

Following the publication of the delay rules and after consideration of comments received in response to the First Delay Rule, ONRR assessed which parts of the previous economic analysis warranted revision. To provide a more complete analysis, this final rule presents the estimated royalty impacts of the withdrawal of the 2020 Rule using the updated analyses. Changes are measured relative to a baseline that includes the royalty changes finalized in the 2020 Rule.

As shown in the tables, an updated analysis of the impact to royalty under the 2020 Rule results in a total decrease in royalties of $64.6 million per year, which translates to an increase of $64.6 million per year under this withdrawal. This amount stands in contrast to the annual decrease of $28.9 million per year in royalties previously estimated in the 2020 Rule and further justifies withdrawal of the 2020 Rule. The change in amounts is largely attributable to the new assumption and method used to estimate the impact from extending the index-based valuation method to arm's-length natural gas and NGL sales. A more detailed explanation of the new method is described below. All impacts to royalties other than those related to the index-based valuation option remain unchanged from those published in the 2020 Rule.

The administrative costs and potential administrative cost savings attributable to the 2020 Rule have also been updated using the new assumptions for the extension of index-based valuation method to arm's-length sales. The administrative cost to industry for deepwater gathering allowances would remain unchanged from the value published in the 2020 Rule.

ONRR updated the estimated one-time administrative cost associated with the optional use of the index-based valuation method. These costs are only incurred by a lessee once to distinguish allowed and disallowed costs in reported processing and transportation allowances. In many situations, industry has already performed these calculations to comply with previous reporting requirements. ONRR reduced the total one-time administrative cost published in the Proposed Withdrawal Rule to be more reflective of only newer gas processing plants that would require the additional administrative cost. Unless there is a significant change in processing and transportation costs, the ratio of allowed to disallowed costs should not substantially change from year to year.

One-Time Administrative Impacts to Industry From Withdrawal of 2020 Rule

Rule provision	Cost
Administrative Cost of Unbundling Related to Index-Based Valuation Method for Gas & NGLs	$243,000

Withdrawal of the 2020 Rule will increase administrative costs when compared to the current status quo, which is the 2020 Rule. While that rule has not yet gone into effect due to the First and Second Delay Rules, it would have gone into effect absent this withdrawal rule, and therefore is the appropriate point of comparison for the measurement of costs, benefits, and transfers.

ONRR used the same base dataset for this proposed rule's economic analysis as it used in the 2020 Rule for consistency and comparability. The description of the data was provided in the Economic Analysis of the 2020 Rule and is repeated here. ONRR reviewed royalty data for Federal oil, condensate, residue gas, unprocessed gas, fuel gas, gas lost (flared or vented), carbon dioxide (“CO₂ ”), 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 five calendar years, 2014-2018. ONRR used five calendar years of royalty data to reduce volatility caused by fluctuations in commodity pricing and volume swings. 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. A lessee reports 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

ONRR analyzed this provision similarly to the 2020 Rule, assuming that half of lessees would elect to use the index-based valuation method. ONRR received many comments stating that this assumption was flawed, because a lessee will typically act in a manner that maximizes, not harms, financial benefits to the lessee. ONRR stated in the 2020 Rule that the assumption that half of lessees would elect to use the index-based valuation option was an attempt to simplify the royalty impact estimation. Due to the delay rules, ONRR was able to apply a more sophisticated set of assumptions to estimate the lessees that would likely benefit from the 2020 Rule's amendments to the index-based valuation option and those that would not. ONRR began the analysis with a similar rationale on the same data that it used in the 2020 Rule's calculation. ONRR reviewed the reported royalty data for all Federal gas sales except for non-arm's-length transactions (discussed below), future valuation agreements, and percentage of proceeds (“POP”) contracts. ONRR also adjusted the POOL sales down to 90 percent (as described above), which were spread across ten major geographic areas with active index prices. The ten areas account for over 95 percent of all Federal gas produced. ONRR assumed the remaining five percent of lessees producing Federal gas 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 ten geographic areas are:

1. Offshore Gulf of Mexico

2. Big Horn Basin

3. Green River Basin

4. Permian Basin

5. Piceance Basin

6. Powder River Basin

7. San Juan Basin

8. Uinta Basin

9. Williston Basin

10. Wind River Basin

To calculate the estimated royalty impact, ONRR:

(1) Identified the monthly bidweek price index, published by Platts Inside FERC, for each applicable 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. ONRR determined the applicability of a price index based on proximity to the producing area and the frequency with which ONRR's audit and compliance staff verify these index prices in sales contracts;

(2) subtracted the appropriate transportation deduction as described in the 2020 Rule from the midpoint index price identified in step (1);

(3) compared the reported monthly price for each lease inclusive of any reported transportation allowances to the applicable index price for the lease calculated in step (2) for all months in the first year of reported royalty data in the dataset;

(4) identified all leases in step (3) where the reported price exceeded the price calculated in step (2) for seven or more months in the time period;

(5) used the lease list created in step (4) as the base universe of properties that would elect to use the index-based valuation method available;

(6) compared the actual reported price for each month for each lease in the universe identified in step (5), inclusive of transportation allowances reported, to the calculated price in step (2) to identify the difference between what was reported as actual royalties and what would have been reported as royalties under the terms of the index-based valuation method;

(7) performed this calculation and comparison for the next two sets of two-year time periods in the remaining four years of royalty reporting in the dataset; and

(8) calculated the total difference in the four years between the original reported royalty prices and royalties of the identified lease universe that elected the index-based valuation method, then divided that total by four to get an annual estimated royalty impact.

This new method of identification of the lease universe that would elect the index-based valuation method if given the opportunity is the basis for the differences between the estimated royalty impact published in the 2020 Rule and the estimated royalty impact included in this final rule. Also, this identification of the leases that stand to benefit is similar to how a lessee will make its decisions and is a better method to estimate the royalty impact. ONRR compared the monthly prices reported to it in the first year of the data period, inclusive of transportation allowances, to the index prices for the appropriate producing areas, inclusive of transportation deductions. ONRR then identified the leases with reported prices higher than the index price in seven or more months of the year. For these leases with prices higher than index for more than half of the year, ONRR assumes the lessee would elect to use the index-based valuation method. For arm's-length natural gas sales, this equates to 39.8 percent of the entire list of leases and represents a percentage that is lower than the 50 percent assumption made by ONRR in the 2020 Rule's estimated impacts on royalty collections of this same provision. This new percentage incorporates a more logical identification of the leases taking into account a lessee's potential financial benefit.

ONRR estimates the index-based valuation method in the 2020 Rule would have decreased royalty payments on arm's-length natural gas by approximately $6.8 million per year when compared to ONRR regulations in effect prior to the 2020 Rule.

Annual Change in Royalties Paid Using Index-Based Method for Arm's-Length Gas Sales From Withdrawal of the 2020 Rule

	Gulf of Mexico	Other areas	Total
Annualized Reported Royalties from Identified Lease Universe	$51,720,000	$168,850,000	$220,570,000
Royalties Estimated using Index-Based Valuation Method for Lease Universe	53,940,000	159,790,000	213,730,000
Difference	(2,220,000)	9,060,000	6,840,000

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

ONRR used similar changes to the assumptions when calculating the royalty impact from extending the index-based valuation option to arm's-length sales of NGLs. As in the previous section, ONRR's goal was to identify a universe of leases that would benefit financially from electing the index-based valuation method. In the 2020 Rule, ONRR assumed that half of the lessees would elect the method without regard to financial benefit or harm.

ONRR used the same dataset for this analysis that was used in the 2020 Rule. It included all NGL sales except for non-arm's-length transactions and future valuation agreements. ONRR also adjusted the POOL sales down to 90 percent (as described above). These sales were spread across the same ten major geographic areas with active index prices for this analysis. To calculate the estimated royalty impact of the index-based valuation method on NGLs from Federal leases, 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 NGL basket prices (weighted average prices to group the individual NGL components), 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	Percent	OPIS Mont Belvieu basket	Percent
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 ONRR regulations without amendment by the 2020 Rule ( see 30 CFR 1206.142(d)(2)(ii)), 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) compared the reported monthly price for each lease inclusive of any reported transportation or processing allowances to the applicable index price for the lease calculated in step (3) for all months in the first year of reported royalty data in the dataset;

(5) identified all leases in step (4) where the reported price exceeded the price calculated in step (3) for seven or more months in the time period;

(6) used the lease list created in step (5) as the base universe of leases that would elect to use the index-based valuation method if available;

(7) compared the actual reported price for each month for each lease in the universe identified in step (6), inclusive of transportation and processing allowances reported, to the calculated price in step (3) to identify the difference between what was reported as actual royalties and what would have been reported as royalties under the terms of the index-based valuation method;

(8) performed this calculation and comparison for the next two sets of two-year time periods in the remaining four years of royalty reporting in the dataset; and

(9) calculated the total difference in the four years between the original reported royalty prices and the royalties if the identified lease universe elected the index-based valuation method, then divided that total by four to get an annual estimated royalty impact.

This new method of identification of the lease universe that would elect the index-based valuation method is the basis for the difference between the estimated royalty impact published in the 2020 Rule and the estimated royalty impact included in this final rule.

ONRR estimates the index-based valuation method in the 2020 Rule would have decreased royalty payments on arm's-length NGLs by approximately $660,000 per year, and that withdrawing the 2020 Rule will increase royalty payments by $660,000 annually.

Annual Change in Royalties Paid Using Index-Based Valuation Method for Arm's-Length NGL Sales From Withdrawal of the 2020 Rule

	Gulf of Mexico	New Mexico	Other areas	Total
Annualized Reported Royalties from Identified Lease Universe	$4,990,000	$350,000	$9,100,000	$14,440,000
Royalties Estimated Using Index-Based Valuation Method for Lease Universe	3,470,000	290,000	10,020,000	13,780,000
Annual Net Change in Royalties Paid Using Index-Based Valuation Method for NGLs	1,520,000	60,000	(920,000)	660,000

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

In the 2020 Rule, ONRR amended the index-based valuation method to use the average bidweek price, rather than the highest bidweek price, for the appropriate index-pricing point. ONRR accounted for the impacts to royalty collections attributable to arm's-length natural gas transactions in the earlier section. This section will focus on the impact to royalty collections only attributable to non-arm's-length natural gas transactions.

The method for calculation in this final rule is similar to the method used in the 2020 Rule, with adjustments made related to the universe of leases that would elect the index-based valuation method. ONRR compared the monthly prices reported to it in the first year of the data period, inclusive of transportation allowances, to the index prices for the appropriate producing areas, inclusive of transportation deductions. ONRR then identified the leases with reported prices higher than the index price in seven or more months of the year. For these leases with prices higher than index for more than half of the year, ONRR assumes the lessee would elect to use the index-based valuation method. For non-arm's-length natural gas sales, this equates to 56.4 percent of the entire list of leases and represents a percentage that is higher than the 50 percent assumption made by ONRR in the 2020 Rule's estimated impacts on royalty collections of this same provision. This new percentage incorporates a more logical identification of the leases taking into account a lessee's potential financial benefit.

ONRR used reported royalty data for non-arm's-length (“NARM”) sales and ten percent of the POOL sales type codes based on the assumption above in the same ten 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); and

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

Because ONRR identified that 56.4 percent of leases fall in the universe of leases that would elect the index-based valuation method, ONRR reduced the total estimate by 43.6 percent in the following table. ONRR estimated that the result of this change is that the 2020 Rule, if it went into effect, would result in a decrease in annual royalty payments of approximately $5 million, and a withdrawal of that rule would result in an increase in annual royalty payments by a like amount, as reflected in the table below.

Estimated Impact to Royalty Collections Due To Withdrawal of 2020 Rule's 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
56.4% of applicable leases			5,062,000

Change in Royalties 4: Modifying the Index-Based Valuation Method To Account for Transportation in Valuing Non-Arm's-Length Federal Unprocessed Gas, Residue Gas, and Coalbed Methane

The 2020 Rule increased the reductions to index price to account for transportation of production valued under the non-arm's-length index-based valuation method first adopted in the 2016 Valuation Rule. ONRR used the new method described previously in this Economic Analysis to identify the likely lease universe of non-arm's-length natural gas sales. ONRR identified the same 56.4 percent of non-arm's-length natural gas leases as the universe that would elect the method.

To estimate the royalty impact of the change in amount intended to account for transportation, ONRR used reported royalty data using NARM and ten percent of the POOL sales type codes from the same ten 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-related adjustment as published in the current regulations and the adjustment 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 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); and

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

Because ONRR identified the universe of 56.4 percent of lessees that will likely elect this method, ONRR reduced the total estimated impact to royalty collections by 43.6 percent. ONRR estimated the change would result in a decrease in royalty collections of approximately $8 million per year if the 2020 Rule went into effect, and an increase in royalty collections of like amount if the 2020 Rule is withdrawn, as reflected in the table below.

Annual Royalty Impact Due to Transportation Deduction Modification for Non-Arm's-Length Sales of Natural Gas From Withdrawal of the 2020 Rule

	Gulf of Mexico	Other areas	Total
Current Regulations Transport Deduction	($5,387,000)	($16,375,000)	($21,762,000)
Estimate using 2020 Rule Transport Deduction	(10,346,000	(25,659,000)	(36,005,000)
Change	4,959,000	9,284,000	14,243,000
56.4% universe of leases			8,033,000

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

The 2020 Rule allows a lessee to request an extraordinary processing cost allowance. Below, ONRR uses the same calculation method for these royalty impacts as it did in the 2020 Rule. 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 reviewed 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 66 2/3 percent limit and found that only two years exceeded the 66 2/3 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 from those same leases for residue gas.

Based on these calculations, ONRR previously estimated the royalty impact of the 2020 Rule's reinstatement of extraordinary processing allowances as decreasing royalties by $11.1 million per year, and ONRR now estimates the royalty impact of withdrawing this provision of the 2020 Rule at an increase in royalties of $11.1 million per year. However, ONRR recognizes that these estimates of decrease from the 2020 Rule and increase from this final rule likely undervalue actual impacts for the reasons discussed in Section III.D., above— i.e., hard caps rather than soft caps on processing allowances may result in more lessees applying for extraordinary processing allowances than did when they could apply to exceed soft caps instead. As a result, there could be an increase in the number of requests submitted to ONRR for extraordinary processing allowances under the 2020 Rule and a larger-than-quantified impact upon withdrawal of the 2020 rule. But there is little data available to identify the number or magnitude of incremental requests possible under the 2020 Rule, and there is not enough information to determine how many of these requests would be approved or denied by ONRR. For these reasons, ONRR is unable to more precisely estimate the royalty impact of reinstating extraordinary processing allowances under the 2020 Rule or withdrawing those allowances under this final rule.

Estimated Annual Change in Royalty Collections From Withdrawal of the 2020 Rule

Annual Average Sulfur Allowances in Excess of 66 2/3 %	$348,000
Annual Average Residue Gas Allowance	10,783,000
Estimated Annual Impact on Royalties	11,131,000

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

In the 2020 Rule, ONRR adopted regulatory changes that would allow an OCS lessee to take certain gathering costs as part of its transportation allowance. ONRR adjusted its method for calculating this royalty impact in response to comments received on the Proposed 2020 Rule and published a corrected method in the 2020 Rule. ONRR will continue to use the adjusted method here to estimate the royalty impact of the 2020 Rule, whether it goes into effect or is withdrawn.

As previously discussed, the Deepwater Policy was in effect from 1999 through December 31, 2016. Under the Deepwater Policy, ONRR allowed a lessee to treat certain costs for subsea gathering as transportation expenses and to deduct those costs in calculating its royalty obligations. The 2016 Valuation Rule rescinded the Deepwater Policy, but the 2020 Rule codified a deepwater gathering allowance similar to the Deepwater Policy. To analyze the impact to industry of the 2020 Rule's deepwater gathering allowance, ONRR used data from BSEE's Technical Information Management System database to identify 113 subsea pipeline segments, and 169 potentially eligible leases, which might qualify for a deepwater gathering allowance. 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 active and supporting producing leases. 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 estimated 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. Then, 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 the return on investment using the average BBB Bond rate for January 2018 (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). 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 must be excluded from any calculation of a permissible deduction. ONRR chose these two percentages based on knowledge and information gathered during audits of leases located in the Gulf of Mexico. Finally, ONRR used an average royalty rate of 14 percent, which is the volume-weighted-average royalty rate for the non-Section 6 leases in the Gulf of Mexico. See 43 U.S.C. 1335(a)(9). Based on these calculations, the average annual allowance per pipeline segment during the period that ONRR collected data from 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 represented the estimated amount per lease for gathering that ONRR would allow a lessee to take as a transportation allowance based on the 2020 Rule's deepwater gathering allowance. 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 potentially 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, are estimated to qualify for a deduction under the 2020 Rule's deepwater gathering allowance. 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, which limits the value of a deepwater gathering allowance. ONRR chose to use an estimate of half of the leases for consistency, and it decreased the low, mid, and high annual cost-to-industry estimates by 20 percent. The table below shows the estimated royalty impact of withdrawing this provision of the 2020 Rule.

Annual Estimated Impact to Royalty Collections From Withdrawal of the 2020 Rule

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

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

The 2020 Rule, by authorizing transportation allowances for certain OCS gathering, would result in an administrative cost to industry because it requires a qualified lessee to monitor its costs and perform additional calculations if it is to claim the allowance. ONRR identified no need to adjust or change the analysis performed in the 2020 Rule to estimate this cost to industry. The cost to perform these calculations is significant because industry often hires additional labor or outside consultants to calculate subsea pipeline movement costs. ONRR estimates that each lessee with leases eligible for transportation allowances for deepwater gathering systems will allocate one full-time employee annually (or incur the equivalent cost for an outside consultant) 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. Using this fully burdened labor cost per hour, ONRR estimated that the annual administrative cost savings to industry if the 2020 Rule is withdrawn would be approximately $3.9 million.

Annual Administrative Cost Savings to Industry To Calculate Certain OCS Gathering Costs From Withdrawal of the 2020 Rule

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

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

In the 2020 Rule, ONRR assumed that half of the lessees would elect to use the index-based valuation method to value their arm's-length natural gas and NGL transactions. As described earlier in this Economic Analysis, ONRR identified that 39.8 percent of leases with arm's-length sales would elect this option. This is more accurate than the 2020 Rule's assumptions, and ONRR will use it to estimate the potential administrative cost savings for industry.

ONRR estimated the index-based valuation method would have shortened the time burden per line reported on the ONRR-2014 royalty reporting form by 50 percent (to 1.5 minutes per electronic line submission and 3.5 minutes per manual line submission). As with Cost Savings 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 to industry will be approximately $1.1 million if the 2020 Rule is withdrawn.

Annual Administrative Costs to Industry From Withdrawal of the 2020 Rule

	Time burden per line reported (minutes)	Estimated lines reported using index option (50%)	Annual burden hours
Electronic Reporting (99%)	1.5	710,525	17,763
Manual Reporting (1%)	3.5	7,177	419
Industry Labor Cost/hour			$59.26
Total Costs			1,077,000

Cost 2: Administrative Cost of Using Index-Based Valuation Method To Value Residue Gas and NGLs Because of Simplified Processing and Transportation Cost Calculations

In the 2020 Rule, ONRR calculated the potential one-time administrative cost savings for industry if a lessee elects to use the index-based valuation method. 86 FR 4641. ONRR slightly modified this calculation and method as described further below. Use of the index-based valuation method eliminates the need to segregate deductible costs of transportation and processing from non-deductible costs of placing production in marketable condition. This segregation or allocation of costs is often referred to as “unbundling.” Industry would unbundle transportation systems and processing plants one time under the current regulatory scheme ( i.e., in absence of the 2020 Rule), and then use those unbundled cost allocations for subsequent royalty calculations.

While industry is responsible for calculating these costs, ONRR has published and calculated several unbundling cost allocations. It takes approximately 100 hours of labor per gas plant. ONRR calculated the average number of gas plants reported per lessee to be 3.4, across a total of 448 lessees reporting residue gas and NGLs, between 2014-2018. Using the BLS labor cost per hour of $59.26 (described above) and the assumption that 50 percent of lessees will choose the index-based valuation method, ONRR believed the 2020 Rule would have resulted in a one-time cost savings to industry of $4.5 million dollars. See 86 FR 4641 and 4648.

ONRR updated its analysis for this administrative cost. Given that the 2020 Rule has not gone into effect yet, industry has been unbundling its processing and transportation costs already for gas plants and transportation systems used under the current regulations. Because of this, new unbundling efforts would only occur on newly created gas plants or for gas plants that undergo major technological changes. ONRR looked at all the gas plants reported for Federal gas production since the start of 2020. ONRR also identified the number of new gas plants companies requested be added to ONRR's system for reporting since the start of 2020. The newly added gas plants represented 5.4 percent of all gas plants reported to ONRR for Federal production. This group represents those plants that would require lessees to perform a new unbundling analysis. ONRR applied this percentage to the total one-time cost savings in the 2020 Rule and now estimates that the withdrawal of the 2020 Rule will result in lessees incurring this one-time administrative cost of $243,000.

State and Local Governments

ONRR estimated that, because of the 2020 Rule, States and certain local governments would have received an overall decrease in royalty disbursements based on the category that leases fall under, including OCSLA section 8(g) leases. See 43 U.S.C. 1337(g), Gulf of Mexico Energy Security Act (“GOMESA”), 43 U.S.C. 1331, et seq., and onshore Federal lands. ONRR disburses royalties based on where the royalty-bearing oil and gas was produced.

Except for production from Federal leases in Alaska (where Alaska receives 90 percent of the distribution), for 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%

More information on ONRR's disbursements to any specific State or local government can be found at https://revenuedata.doi.gov/​explore/​#federal-disbursements.

Indian Lessors

The provisions in the 2020 Rule and this withdrawal are not expected to affect Indian lessors.

Federal Government

The impact of the 2020 Rule to the Federal Government will be a decrease in royalty collections. ONRR estimates the impact of the 2020 Rule to the Federal Government (detailed in the next table of this section) would be a reduction in royalties of $49.7 million per year. The estimated impact to royalty collections of the withdrawal of the 2020 Rule would be an increase in royalties of $49.7 million per year.

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

The table below shows the updated net change in royalties expected under this withdrawal. The table breaks out the impacts to Federal and State disbursements based on the typical distributions noted in the table above and the appropriate product weightings and the location of the affected leases.

Withdrawal of the 2020 Rule: Annual Impact to Royaly Collections, the Federal Government, and States

Rule provision	Impact to royalty collections	Federal portion	State portion
Index-Based Valuation Method Extended to Arm's-Length Gas Sales	$6,800,000	$4,180,000	$2,620,000
Index-Based Valuation Method Extended to Arm's-Length NGL Sales	660,000	430,000	230,000
High to Midpoint Index Price for Non-Arm's-Length Gas Sales	5,060,000	3,110,000	1,950,000
Transportation Deduction Non-Arm's-Length Index-Based Valuation Method	8,030,000	4,930,000	3,100,000
Extraordinary Processing Allowance	11,130,000	5,680,000	5,450,000
Allowance for Certain OCS Gathering Costs	32,900,000	31,320,000	1,580,000
Total	64,600,000	49,700,000	14,900,000
Note: Totals may not add due to rounding.

Federal Oil and Gas Amendments With No Estimated Change to Royalty or Regulatory Costs

Change 1: Default Provision Applicable to Federal Oil and Gas

The 2016 Valuation Rule added the default provision to ONRR regulations. The 2020 Rule removed the default provision from ONRR regulations. In instances of misconduct, breach of a lessee's duty to market, or other situations where royalty value cannot be determined under ONRR's valuation rules, ONRR can use the Secretary's statutory authority and the authority granted to the Secretary under the terms of the applicable leases to determine Federal oil and gas royalty value, as ONRR would have done prior to adoption of the 2016 Valuation Rule. ONRR has never found an impact to royalty collections on account of the default provision.

Federal and Indian Coal

In the 2020 Rule, ONRR estimated there will be no change to royalty collections for the Federal Government, Indian Tribes, individual Indian mineral owners, States, or industry for Federal and Indian coal. ONRR has not changed or adjusted this estimate in this final rule. There is no impact to royalty collections on account of the coal provisions due to this final rule's withdrawals.

VI. 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 OMB will review all significant rulemakings. OMB has determined that this final rule is a significant regulatory action under E.O. 12866. The primary effect of this final rule is on royalty payments. ONRR expects that this final rule will largely result in transfers, which are described in the table below. ONRR also anticipates that this final rule will result in annual administrative cost savings of $2.85 million and a one-time administrative cost of $243,000.

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.

Summary of Estimated Changes to Royalty Collections From the Withdrawal of the 2020 Rule

[Annual]

Rule provision	Net change in royalties paid by lessees
Index-Based Valuation Method Extended to Arm's-Length Gas Sales	$6,800,000
Index-Based Valuation Method Extended to Arm's-Length NGL Sales	660,000
High to Midpoint Index Price for Non-Arm's-Length Gas Sales	5,062,000
Transportation Deduction Non-Arm's-Length Index-Based Valuation Method	8,033,000
Extraordinary Processing Allowances	11,131,000
Allowances for Certain OCS Gathering Costs	32,900,000
Total	64,600,000

To estimate the present value of potential administrative costs/savings to industry, ONRR looked at two 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 to industry in the first year and incursion of administrative cost savings each year thereafter.

Summary of Annual Administrative Impacts to Industry From the Withdrawal of 2020 Rule

Rule provision	Cost (cost savings)
Administrative Cost Savings for Index-Based Valuation Method for Arm's-Length Gas & NGL Sales	$1,077,000
Administrative Cost for Allowances for Certain OCS Gathering	(3,931,000)
Total	(2,850,000)

Summary of One-Time Administrative Impacts to Industry From the Withdrawal of 2020 Rule

Rule provision	Cost
Administrative Cost-Savings in lieu of Unbundling related to Index-Based Valuation Method for Arm's-Length Gas & NGLs	$243,000

Net Present Value of Administrative Impacts to Industry From the Withdrawal of 2020 Rule

Time horizon	3% discount rate	7% discount rate
Administrative Costs over 10 years	−$24,800,000	−$21,200,000
Administrative Costs over 20 years	−43,400,000	−32,100,000

Annualized Costs of Administrative Impacts to Industry From the Withdrawal of 2020 Rule

Time horizon	3% discount rate	7% discount rate
Annualized Administrative Costs over 10 years	−$2,820,000	−$2,820,000
Annualized Administrative Cost over 20 years	−$2,830,000	−$2,830,000

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 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 further emphasizes 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 final 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 APA 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 final rule would affect lessees of Federal oil and gas leases. For the changes to 30 CFR part 1241, this final rule could affect alleged and actual 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 2111, Oil and Gas Extraction; and
• Code 21211, Coal Mining.

Under NAICS code classifications, a small company is one with fewer than 500 employees. ONRR estimates that there are approximately 1,208 different lessees that submit royalty reports for Federal oil and gas leases and other Federal mineral leases to ONRR each month. Of these lessees, approximately 106 are not considered small businesses because they exceed the employee count threshold for small businesses. ONRR estimates that the remaining 1,102 lessees have fewer than 500 employees and are therefore considered small businesses.

As stated in the Summary of Royalty Impacts and Costs Table, shown above, this final rule would impact industry through an increase in royalties of approximately $64.6 million per year if the 2020 Rule had gone into effect. This rule causes no financial impact on industry because it is consistent with the 2016 Valuation Rule which is currently operative. Small businesses account for approximately eight percent of those royalties. Applying that percentage, ONRR estimates that this final rule would increase royalty payments made by small-business lessees by approximately $5.2 million per year, or $4,690 per small business, on average. The extent of any royalty impact would vary between lessees due to, for example, differences in the revenues generated by a small business that is subject to royalties.

Also stated above, this final rule would impact industry through a decrease in administrative costs of approximately $2.9 million per year and a first-year increase of $243,000, relative to a baseline in which the 2020 Rule goes into effect. Applying the eight percent small-business share, ONRR estimates that this final rule would decrease administrative costs to small business lessees by approximately $207 per year and by $189 in the first year.

In 2020, ONRR collected $6.3 billion in royalties from Federal oil and gas leases. Applying the eight-percent share, ONRR estimates that small-business lessees paid $504 million in royalties in 2020. Most Federal oil and gas leases have a 12.5 percent royalty rate, resulting in an estimated $4 billion in total small-business lessee revenue from the production and sale of Federal oil and gas ($504 million divided by .125). Thus, on average, ONRR estimates that small-business lessees earn $3.6 million in revenue per year from the production and sale of Federal oil and gas ($4 billion divided by 1,102).

The estimated increase in royalties ($4,690) and decrease in administrative burden ($207) net to an increase in overall cost to 1,102 small businesses of $4,402 per year. As a percentage of average small-business revenue, this final rule would increase costs to those entities by 0.12 percent ($4,402 divided by $3.6 million).

According to the U.S. Census Bureau's 2017 Economic Census data, oil and gas lessees with 20 employees or less collected $2.1 million per year per entity. Taking the $4,402 discussed above, divided by $2.1 million equals an estimated maximum impact of 0.2 percent of total revenue per year. Further, ONRR anticipates that the smallest entities would realize less of an increase in royalties because, for example, the changes to deepwater gathering and extraordinary processing allowances are capital-intensive operations in which small entities typically do not participate.

In accordance with 5 U.S.C. 605, the head of the agency certifies that this final rule would have an impact on a substantial number of small entities, but the economic impact on those small entities would not be significant 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

The 2020 Rule was not a major rule under Subtitle E of the Small Business Regulatory Enforcement Fairness Act of 1996. See 5 U.S.C. 804(2). Therefore, this final rule is also not a major rule under 5 U.S.C. 804(2). Like the 2020 Rule, ONRR anticipates that this final rule:

(1) Will not have an annual effect on the economy of $100 million or more. ONRR estimates that, if the 2020 Rule had gone into effect, the cumulative effect on all of industry would have been a reduction in private cost of nearly $61.45 million per year, which is the sum of $64.6 million in decreased royalty payments and $2.85 million in additional costs due to increased administrative burdens. This net change in royalty payments would have been a transfer rather than a cost or cost savings. The Summary of Royalty Impacts and Costs Table, as shown above, demonstrates that this final rule's cumulative economic impact on industry, State and local governments, and the Federal Government is well below the $100 million threshold that the Federal Government uses to define a rule as having a significant impact on the economy;

(2) 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. 12866 and E.O. 13563) at Section VI.A.; and

(3) would 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. ONRR estimates no significant adverse impacts to small business.

D. Unfunded Mandates Reform Act

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

E. Takings (E.O. 12630)

Under the criteria in section 2 of E.O. 12630, this final rule does not have any significant takings implications. This final rule does not impose conditions or limitations on the use of any private property because it applies to the valuation of Federal oil and gas and Federal and Indian coal and to ONRR's civil penalty process. This final rule does not require a takings implication assessment.

F. Federalism (E.O. 13132)

Under the criteria in section 1 of E.O. 13132, this 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 in accordance with the relevant disbursement statutes. This final rule would not impose administrative costs on States or local governments or substantially and directly affect the relationship between the Federal and State governments. Thus, a Federalism summary impact statement is not required.

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

This final rule complies with the requirements of E.O. 12988. Specifically, the final rule:

(1) Meets the criteria of Section 3(a), which requires that ONRR review all regulations to eliminate errors and ambiguity to minimize litigation; and

(2) 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)

ONRR 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 the criteria in E.O. 13175 and determined that it does not have substantial direct effects on Federally-recognized Indian Tribes. Thus, consultation under ONRR'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 not have a substantial impact on any of the represented Tribes. With the exception of the Kayenta Mine located on the lands belonging to the 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 and the 2020 Rule, ONRR's review of the royalty impact to Tribes from this final rule demonstrates that this final rule will not substantially impact any of the three Tribes. Further, the rule is not estimated to impact 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 or modify any existing information collections that are subject to OMB's approval. Thus, ONRR did not submit any new information collection requests to OMB related to this final rule.

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

J. National Environmental Policy Act of 1970

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 NEPA because this action is categorically excluded under 43 CFR 46.210(c) and (i), as well as the Departmental Manual, part 516, section 15.4.D, which covers: “(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.” This final rule does not involve any of the extraordinary circumstances listed in 43 CFR 46.215 which 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 it as a significant energy action. Therefore, a Statement of Energy Effects pursuant to E.O. 13211 is not required.

L. Clarity of This Regulation

E.O. 12866 (section 1(b)(12)), 12988 (section 3(b)(1)(B)), E.O. 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:

(1) Logical organization.

(2) Active voice to address readers directly.

(3) Clear language rather than jargon.

(4) Short sections and sentences.

(5) 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 have been 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.

This action is taken pursuant to delegated authority.

Rachael S. Taylor,

Principal Deputy Assistant Secretary—Policy, Management and Budget.