ONRR 2020 Valuation Reform and Civil Penalty Rule: Notification of Proposed Withdrawal

AGENCY:

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

ACTION:

Proposed rule; request for comments.

SUMMARY:

ONRR is proposing to withdraw the final rule entitled “ONRR 2020 Valuation Reform and Civil Penalty Rule” (“2020 Rule”). This action opens a 60-day comment period to allow interested parties to comment on ONRR's proposed withdrawal of the 2020 Rule.

DATES:

The final rule published on January 15, 2021, at 86 FR 4612, which was delayed at 86 FR 9286 on February 12, 2021, and 86 FR 20032 on April 16, 2021, is proposed to be withdrawn. To be assured consideration, comments must be received at one of the addresses provided below by 11:59 p.m. EST on August 10, 2021.

ADDRESSES:

You may submit comments to ONRR using one of the following two methods. Please reference the Regulation Identifier Number (“RIN”) for this action, “RIN 1012-AA27,” in your comment:

• Electronically via the Federal eRulemaking Portal: Please visit https://www.regulations.gov . In the Search Box, enter Docket ID “ONRR-2020-0001” and click “search” to view the publications associated with the docket folder. Locate the document with an open comment period and then click “Comment.” Follow the instructions to submit your public comments prior to the close of the comment period.
• Email Submissions: Please submit your comments via email at ONRR_RegulationsMailbox@onrr.gov with “RIN 1012-AA27” listed in the subject line of your message. Email submissions must be postmarked on or before the close of the comment period.

Instructions: All comments must include the agency name and docket number or RIN for this rulemaking. All comments, including any personal identifying information or confidential business information contained in a comment, will be posted without change to https://www.regulations.gov .

Docket: For access to the docket to read background documents or comments received, go to https://www.regulations.gov and locate the docket folder by searching the Docket ID (ONRR-2020-0001) or RIN number (RIN 1012-AA27).

FOR FURTHER INFORMATION CONTACT:

For questions, contact Luis Aguilar, Regulatory Specialist, at (303) 231-3418 or by email at ONRR_RegulationsMailbox@onrr.gov.

SUPPLEMENTARY INFORMATION:

I. Introduction

A. Statutory Authority

Through the enactment of various mineral leasing laws, Congress authorized the Secretary to issue and administer leases to allow for the exploration, development, and production of mineral resources from Federal and Indian lands and the OCS. These laws include, for onshore lands, the MLA, for offshore lands, the OCSLA, and for Indian and allotted lands, 25 U.S.C. 396, et seq. The Secretary has delegated the statutory authority to lease, permit, and inspect mineral extraction activities on those lands to several bureaus and offices.

The Secretary is also responsible for collecting, accounting for, and disbursing royalties and other financial obligations related to the leasing, production, and sale of minerals from Federal and Indian lands. Mineral leasing laws, regulations, and lease terms establish royalty rates and other obligations that a lessee must pay to the United States or Indian lessor. Relevant to this rulemaking, see, e.g., 25 U.S.C. 396a-g, 400a; 30 U.S.C. 207(a), 226(b)(1) (MLA); 43 U.S.C. 1337(a)(1) (OCSLA); 25 CFR 211.43; 43 CFR 3103.3-1, 43 CFR 3473.3-2.

Congress enacted FOGRMA to further clarify and establish the Secretary's responsibilities with respect to royalty management. Through FOGRMA, Congress directed the Secretary “to improve methods of accounting for such royalties and payments” and required “the development of enforcement practices that ensure the prompt and proper collection and disbursement of oil and gas revenues owed to the United States and Indian lessors and those inuring to the benefit of States.” 30 U.S.C. 1701(a)(3) and (b)(3).

Over the years, royalty management responsibilities have been transferred within DOI and in 2010, following the reorganization of MMS, ONRR was created. The Secretary delegated authority to ONRR to carry out its responsibilities specific to “royalty and revenue collection, distribution, auditing and compliance, investigation and enforcement, and asset management for both onshore and offshore activities.” S.O. 3299, Sec. 5 (August 29, 2011); see also S.O. 3306 (September 30, 2010). Pursuant to FOGRMA, the mineral leasing acts, and the authority delegated by the Secretary, ONRR has adopted regulations specifying the methods to be used to determine the value of Federal and Indian mineral production for royalty purposes.

ONRR's responsibilities are distinct from other DOI offices and bureaus and pertain specifically to the collection, verification, and disbursement of royalty revenue realized from production of natural resources on Federal and Indian lands and the OCS. See 30 CFR 1201.100.

FOGRMA and the mineral leasing laws grant the Secretary broad rulemaking authority to carry out and accomplish the purposes set forth in the governing statutes. See 30 U.S.C. 189 (MLA); 30 U.S.C. 1751 (FOGRMA); and 43 U.S.C. 1334 (OCSLA). In turn, the Secretary delegated rulemaking authority specific to ONRR's portfolio of responsibilities to ONRR. See S.O. 3299, sec. 5 and S.O. 3306, sec. 3-4.

B. Rulemaking History

1. The 2020 Proposed Rule

On October 1, 2020, ONRR published the Proposed 2020 Rule. The Proposed 2020 Rule proposed to amend certain regulations that inform the manner in which ONRR values oil and gas produced from Federal leases for royalty purposes; values coal produced from Federal and Indian leases for royalty purposes; and assesses civil penalties for violations of certain statutes, regulations, lease terms, and orders associated with mineral leases. The Proposed 2020 Rule stated its purposes were to: Align the 2016 Valuation Rule with certain E.O.s issued after the 2016 Valuation Rule's publication date; address some of the amendments in the 2016 Valuation Rule asserted to be controversial and problematic; simplify processes and provide early clarity regarding royalties owed; better explain ONRR's civil penalty practices; and return certain provisions to the framework that had existed for decades prior to the 2016 Valuation Rule and 2016 Civil Penalties Rule.

The 60-day comment period for the Proposed 2020 Rule closed on November 30, 2020. ONRR received comments from numerous industry members, trade associations, public interest groups, members of Congress, members of the public, and State and local entities. ONRR received 36 unique comment submissions totaling to 40,456 pages of comment materials, of which 38,150 pages were a one-page form comment.

2. The 2020 Rule

On January 15, 2021, 46 days after the close of the comment period, ONRR published the 2020 Rule. The 2020 Rule adopted amendments on 15 topics, generally summarized as:

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

2. Extraordinary processing allowances—allowing a lessee 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. Default provision—removed the default provision and references thereto from the Federal oil and gas and Federal and Indian coal regulations. The default provision established criteria limiting how ONRR will exercise the Secretary's authority to establish royalty value when typical valuation methods are unavailable, unreliable, or unworkable.

4. Misconduct—removed the misconduct definition from 30 CFR 1206.20.

5. Signed contracts—removed the requirement that a lessee have contracts signed by all parties.

6. Citation to legal precedent—eliminated the requirement for a lessee to cite legal precedent when seeking a valuation determination.

7. Arm's-length valuation option—adopted an index-based valuation option for arm's-length Federal gas sales.

8. Change in indices to be used in index-based valuation options—changed from the high index price to the average index price.

9. Standard deduction for transportation allowance—amended the standard deduction included in the index-based valuation method to reflect more recent average transportation cost data.

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

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

12. Facts considered in penalizing payment violations—modified ONRR's civil penalty regulations to specify that ONRR considers unpaid, underpaid, or late payment amounts in the severity analysis for payment violations only.

13. Consideration of aggravating and mitigating circumstances—modified ONRR's civil penalty regulations to specify that ONRR may consider aggravating and mitigating circumstances when calculating the amount of a civil penalty.

14. Conforming civil penalty regulations to court decision—removed a provision permitting an ALJ to vacate a previously-granted stay of an accrual of penalties if the ALJ later determines that a violator's defense to a notice of noncompliance was frivolous.

15. Non-substantive corrections—amended various regulations by making non-substantive corrections.

The 2020 Rule did not adopt amendments on three topics discussed in the Proposed 2020 Rule:

1. Regulatory caps on transportation allowances for Federal oil and gas. See 86 FR 4613.

2. Regulatory caps on processing allowances for Federal gas. See 86 FR 4614.

3. Shallow water gathering. See 86 FR 4614.

The effective date of the 2020 Rule was originally February 16, 2021. For amendments to 30 CFR part 1206 only, the 2020 Rule established a compliance date of May 1, 2021.

3. The First Delay Rule

On January 20, 2021, the Assistant to the President and Chief of Staff issued a memorandum entitled “Regulatory Freeze Pending Review” which, along with the Office of Management and Budget (“OMB”) January 20, 2021, Memorandum M-21-14, 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, January 28, 2021).

On February 12, 2021, ONRR published the First Delay Rule which initially delayed by 60 days the effective date of the 2020 Rule, 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. In response, ONRR received 13 comment submissions totaling to 1,339 pages of comment materials, many of which were submitted by the same organizations that had commented on the Proposed 2020 Rule.

4. The Second Delay Rule

After the close of the First Delay Rule's comment period, ONRR determined that an additional 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 (the “Second Delay Rule”).

The Second Delay Rule listed 15 potential defects or shortcomings identified by ONRR in its initial reexamination of the 2020 Rule and in comments received in response to the First Delay Rule. 86 FR 20032. It also addressed public comments received on the impacts of delay of the effective date of the 2020 Rule.

II. Basis for Proposed Action

ONRR is proposing to withdraw the 2020 Rule because the process used for its adoption arguably was without observance of procedure required by law, as well as in excess of ONRR's statutory authority. See 5 U.S.C. 706(2)(C), (D). While a complete withdrawal of the 2020 Rule may be warranted, ONRR requests public comment on potential alternatives in Section IV of this rule. For example, alternative outcomes following this proposed rule's notice could include: Allowing the 2020 Rule to go into effect, a withdrawal limited to some or all of the 2020 Rule's amendments to 30 CFR part 1206, a withdrawal limited to some or all of the 2020 Rule's revenue-impacting amendments, a withdrawal limited to some or all of the 2020 Rule's amendments to part 1241, or some combination thereof. ONRR acknowledges the importance of public participation as part of the rulemaking process. As such, this rule explains potential deficiencies in the 2020 Rule and invites public comment on the proposed withdrawal and new findings considered as part of this reevaluation. Following the close of this rule's comment period, ONRR will consider all relevant information submitted through public comment and determine the appropriate course of action.

A. APA Defects That Go to the Entirety of the 2020 Rule

The 2020 Rule may be deficient under the APA for the following reasons.

1. Adequacy of the Comment Period

Though the 2016 Valuation Rule included a public comment period of 120 days, the 2020 Rule included a public comment period of just 60 days. In litigation construing ONRR's reversal of major policies adopted in the 2016 Valuation Rule, the District Court found that ONRR failed to provide meaningful opportunity for comment when it enacted the reversal without a comment period of commensurate length. 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 2016 Valuation Rule—approximately 120 days. Here, though ONRR did allow for more than 30 days of comment on the 2020 Rule, as with the repeal of the 2016 Valuation Rule, ONRR may still have deprived the public of an adequate period within which to comment.

2. Consideration of Alternatives

The Proposed 2020 Rule does not demonstrate that ONRR considered alternatives to the repeal of select regulations adopted in the 2016 Valuation Rule and, to a lesser extent, its 2016 Civil Penalty Rule. For example, the 2020 Rule did not discuss alternatives to the repeal of the definition of misconduct or the requirement of signed contracts, among other less controversial changes. This again resembles ONRR's 2017 attempt to repeal the 2016 Valuation Rule, where the District Court 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.

3. Lack of “Reasoned Explanation” for Proposed Rule Denies the Public an Opportunity To Comment

In the Proposed 2020 Rule, ONRR may not have fully explained why it was proposing certain substantive amendments. The District 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.

Specifically, ONRR's Proposed 2020 Rule may not have fully described the reasons why it was proposing to return to some of the “historical practices” or adopting other changes, including: (1) When production is completed offshore in waters 200 meters and deeper, allowing a lessee to report and claim certain gathering costs in its transportation allowances; (2) extension of index-based valuation to arm's-length sales of Federal gas; and (3) lowering of the index, from the highest bidweek price to an average bidweek price, for valuation of non-arm's-length sales of Federal gas. 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 could have more fully discussed why the changes were being proposed. 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 may not have provided sufficient notice of the reasons for the substantive proposed changes to be adopted through the 2020 Rule such that the public was not provided with a meaningful opportunity to comment.

4. Failure to Adequately Justify Change in Recently Adopted Policy

At the time the Proposed 2020 Rule was published, the 2016 Valuation Rule had been in force for only seventeen months (from March 29, 2019 when the repeal of the 2016 Valuation Rule was overturned to October 1, 2020) and full compliance with that rule had been 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. In addition, ONRR should have explained the inconsistencies between the 2016 Valuation Rule and the amendments described in the Proposed 2020 Rule and, in addition, 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.

In considering ONRR's 2017 attempt to repeal its 2016 Valuation Rule, the District Court similarly concluded that ONRR did not provide “a reasoned explanation . . . for disregarding facts and circumstances that underlay or were engendered by the prior policy.” Here too, the APA may have been violated by ONRR's failure to offer a reasoned explanation for the proposed amendments and its failure to describe why it was disregarding the findings in the 2016 Valuation Rule in favor of reverting to prior policy after only a brief period of time operating under the 2016 Valuation Rule.

Moreover, the justification offered in the 2020 Rule, in some instances, could be interpreted as relying on matters outside of ONRR's primary area of expertise—matters that were not signaled in the proposed rule. Since the explanation for its action was offered only in the 2020 Rule, and not in the Proposed 2020 Rule, members of the public may have been deprived of an opportunity to comment, as they were unlikely to anticipate that ONRR would cite external justification for the 2020 Rule.

B. APA and Other Defects That Go to Portions of the 2020 Rule

Part A above explains four potential defects in the 2020 Rule. In addition to these defects, ONRR also believes it may have promulgated certain amendments in excess of the authority delegated to it, as explained below. The sum of these defects may warrant withdrawal of the entire 2020 Rule.

Because ONRR is considering alternatives to complete withdrawal of the 2020 Rule, this section provides information regarding additional, amendment-specific problems which may warrant the withdrawal of some but not all of the 2020 Rule. The amendments covered in this Part B are: (1) Deepwater gathering allowances; (2) extraordinary processing allowances; (3) index-based valuation for arm's-length sales; (4) modification of the index price used in index-based valuation; and (5) increasing the reduction to the index price used in index-based valuation to account for transportation expenses. Collectively, these five are referred to as the revenue-impacting provisions of the 2020 Rule.

1. ONRR's Role in Incentivizing Production

Since the 2020 Rule adopted each of these five revenue-impacting amendments to, in part, incentivize production by reducing royalties an oil and gas lessee would otherwise owe the United States, this section begins by discussing incentivization of production before turning to matters specific to individual revenue-impacting amendments.

a. Secretarial Authorities Delegated to ONRR Do Not Include Incentivizing Production

In response to the Proposed 2020 Rule, some commenters noted that ONRR based the proposed rule on incentivizing or increasing Federal production despite the fact that ONRR has no explicit mandate to increase production. In the 2020 Rule, ONRR disagreed with the commenter and responded by stating that it shared in DOI's goal of managing Federal resources on the OCS. See 86 FR 4623. It is true that Congress has established official policy that “the Outer Continental Shelf is a vital national resource reserve held by the Federal Government for the public, which should be made available for expeditious and orderly development, subject to environmental safeguards, in a manner which is consistent with the maintenance of competition and other national needs.” 43 U.S.C. 1332(3). This broad directive, framed primarily by the overarching requirement that DOI conduct leasing activities “to assure receipt of fair market value for the lands leased and the rights conveyed by the Federal Government,” 43 U.S.C. 1344(a)(4), provides the Secretary with broad discretion to emphasize varying components of OCLSA's objectives. Similarly, with respect to the royalty management program specifically, the Secretary has the authority to “prescribe such rules and regulations as he deems reasonably necessary to carry out this chapter” under FOGRMA, 30 U.S.C. 1751(a).

Notably, however, ONRR has reconsidered its responsibilities and determined that they are much narrower than the 2020 Rule suggested. ONRR was established, together with BOEM and BSEE, to purposefully separate and reassign the responsibilities of the former MMS in order to improve management, oversight, and accountability of activities on the OCS, ensure a fair return to the public from royalty and revenue collection and disbursement activities, and provide independent safety and environmental oversight and enforcement of offshore activities. See S.O. 3299 (May 19, 2010) and S.O. 3306 (Sept. 30, 2010). Under these S.O.s, ONRR is specifically responsible for managing royalty and revenue collection, distribution, auditing and compliance, investigation and enforcement, and asset management for both onshore and offshore activities. Id. Consistent with the S.O.s, ONRR is primarily responsible for carrying out the Secretary's duty to “establish a comprehensive inspection, collection and fiscal and production accounting and auditing system to provide the capability to accurately determine oil and gas royalties, interest, fines, penalties, fees, deposits, and other payments owed, and to collect and account for such amounts in a timely manner” under 30 U.S.C. 1711(a). Unlike most agencies within DOI, ONRR has no organic statute and the role of ONRR under S.O. 3299 and S.O. 3306 is narrowly focused on the accounting and auditing activities that form the bedrock of ONRR's responsibilities. Thus, questions exist regarding the scope of ONRR's authority and the range of activities that have been assigned or delegated to it.

The need to separate the auditing and accounting responsibilities from the planning and leasing activities was one of the primary stated purposes for the dissolution of the former MMS and the creation of BOEM, BSEE, and ONRR. MMS was divided into the three separate bureaus and offices to separate conflicting missions. See https://www.doi.gov/news/pressreleases/Salazar-Divides-MMSs-Three-Conflicting-Missions . Among other things, the establishment of ONRR in the Office of the Assistant Secretary for Policy Management and Budget, “centralize[d] the collection and management of revenues from energy development on our public lands and oceans, which strengthens the ability of employees to independently and rigorously carry out their revenue management responsibilities, and ensures better protection of American taxpayer interests.” See July 15, 2011 Statement of the Director of the Office of Natural Resources Revenue, to the Committee on Natural Resources, House of Representatives, doi.gov/ocl/hearings/112/OffshoreEnergyAgenciesGould_071511. Tasking ONRR with incentivizing energy production would seem to be inconsistent with the current delegation of responsibilities between BOEM, BSEE, and ONRR.

Finally, it should be remembered that ONRR's primary functions include ensuring fair return (i.e., fair value) for the public from royalty and revenue collection and disbursement activities. As a result, any decision by ONRR to incentivize or disincentivize production that compromises the attainment of a fair return for the United States would be outside ONRR's primary function.

b. The 2020 Rule Failed To Show How It Incentivized Production

In response to the First Delay Rule, one commenter wrote that ONRR revealed for the first time in the 2020 Rule that it evaluated the issue of production impacts using its economic models. The commenter referred to the following language: The “margin of error for estimating this rule's negligible or marginal impact on actual production is beyond the capability of the Department's existing models, and the Department does not know of other economic models that are sufficiently sensitive to accurately measure these changes.” 86 FR 4616. The commenter described this language as convoluted.

The commenter interpreted this statement to mean that, using the estimating models available to it, ONRR ultimately determined that the rule would have a “negligible or marginal impact on production” within the margin of error of its models. According to the commenter, ONRR's statement means the premise for adopting the 2020 Rule—that it would increase production—was false. The commenter also stated that ONRR failed to provide this finding to the public in the Proposed 2020 Rule to allow the public the opportunity to comment on this new information. The commenter asserted that ONRR instead proceeded to adopt the 2020 Rule despite knowing the premise for its rulemaking had been withheld and, moreover, was materially false. The commenter claimed that on this basis alone, the 2020 Rule should be withdrawn.

ONRR rejects the commenter's assertions that information was withheld in the Proposed 2020 Rule to undermine the public's opportunity to comment. Agencies routinely add, expand, and revise explanations between proposed and final rules based on public comments and their own continued analysis and search for information. However, ONRR agrees with the commenter that the 2020 Rule ultimately failed to explain or substantiate how it accomplished its stated purpose to incentivize production—regardless of whether, as discussed above, it is within ONRR's authority to adopt rules for that purpose.

c. The 2020 Rule Failed To Consider Existing Methods DOI Uses To Incentivize Production

ONRR's sister bureaus have regulations in place to incentivize production through royalty relief in certain situations. This section briefly describes some of these bureaus' royalty-relief programs, which ONRR failed to consider when adopting the 2020 Rule. Immediately below we discuss BSEE's offshore royalty relief programs, and then BLM's onshore royalty relief programs.

DOI's statutory authority allows it to reduce or eliminate a lessee's OCS royalty obligation in order to promote development, increase production, or encourage production of marginal resources. See 43 U.S.C. 1337(a)(3). BSEE's royalty relief regulations, including those found at 30 CFR part 203, may provide a more appropriate incentive than the 2020 Rule's revenue-impacting amendments, including the deepwater gathering allowance, which is limited to the OCS.

The Secretary implements 43 U.S.C. 1337(a)(3)(A)-(C) by offering royalty relief under two general categories, “automatic” and “discretionary.” “Automatic” refers to deepwater and deep gas royalty relief that is specified in an OCS lease issued by BOEM. See 30 CFR 560.220. “Discretionary” refers to royalty relief that a lessee may apply for under certain scenarios and includes end-of-life and special case royalty relief. See 30 CFR 203.50 through 203.56 and 203.80, respectively. For more information, see https://www.boem.gov/oil-gas-energy/energy-economics/royalty-relief .

In order to receive discretionary royalty relief, a lessee must demonstrate and BSEE must verify that a project would be uneconomic without royalty relief and would become economic with royalty relief. See 30 CFR 203.2. The lessee must submit an application to BSEE outlining the estimated economics of the project, which BSEE then reviews. See id. (stating that for different types of royalty relief, the applicant must propose and demonstrate that their project or further development is uneconomic without relief); see also https://www.boem.gov/oil-gas-energy/energy-economics/deepwater-royalty-relief-economic-model . BSEE employs this process to balance the promotion of production with other considerations, including protection of royalty revenue. In contrast, some of the 2020 Rule's revenue-impacting amendments, including the deepwater gathering allowance and amendments related to the index-based valuation option, may be claimed by all lessees producing from deepwater and are in no manner targeted to incentivize operations that otherwise would be uneconomic. Instead, these revenue-impacting amendments are an across-the-board benefit for any lessee that meets the criteria set out in the amendment—regardless of economic need.

Specific to the deepwater gathering allowance, experience gained in numerous audits and other compliance activities has shown that many lessees commissioned deepwater projects without knowledge of the Deepwater Policy. Rather than having made investment decisions based on the Deepwater Policy, these lessees began to calculate allowances under that policy long after learning of the Deepwater Policy and, typically, long after a project began producing. Some companies, prior to the 2016 Valuation Rule's rescission of the Deepwater Policy, applied the Deepwater Policy retroactively after selling the assets. Moreover, for production between 1999 and 2016, ONRR found that many lessees misapplied the Deepwater Policy (for example, claiming disallowed costs or claiming gathering in situations that did not meet the Deepwater Policy's criteria). While the Deepwater Policy (between 1999 and 2016) reduced royalty value, ONRR has seen no evidence that the Deepwater Policy impacted a lessee's decision-making to invest or not in a deepwater project.

BSEE's royalty relief practices include safeguards for the public, including the application and approval process, volume thresholds, pricing thresholds, time limits, capital expenditure thresholds, and periodic reviews of approved royalty relief. 30 CFR 203.4 (discretionary end-of-life and deep-water relief programs) and 30 CFR 203.47 (deep gas relief program); see also https://www.bsee.gov/sites/bsee.gov/files/special-case-royalty-relief-overview-1.pdf (describing the special case relief program's application process). Each application for discretionary royalty relief is reviewed by BSEE, allowing BSEE to grant relief only where needed and appropriate while still protecting public interests. 30 CFR 203.1 and 203.2 (providing that BSEE may grant a “royalty suspension for a minimum production volume plus any additional volume needed to make your project economic”).

In contrast, four of the five revenue-impacting amendments adopted in the 2020 Rule do not include an economic needs test or an application and approval process. There was and is no safeguard to prevent a lessee with a highly lucrative operation from taking advantage of these revenue-impacting amendments.

Because the 2020 Rule did not consider existing BSEE regulations and practices which provide more targeted, structured methods to incentivize new or continuing OCS operations, it appears ONRR's 2020 rulemaking process was inadequate to support adoption of its revenue-impacting amendments, including, on the basis of incentivizing production.

See also the “Memorandum of Understanding between BOEM, BSEE, and ONRR for the Collaboration on Processes, Policies and Systems Relating to the Management of [OCS] Energy and Marine Mineral Development,” signed in March of 2014 (“2014 MOU”), which outlines BOEM, BSEE, and ONRR's respective duties for and involvement in various aspects of OCS production. ONRR's role, with respect to these programs, is limited to the maintenance of royalty information in ONRR's royalty management system. See 2014 MOU, Attachment A, Information Sharing and Bureau Responsibilities; Offshore Federal Oil, Gas, Sulphur and Marine Minerals at page A-21 to A-22 (noting BSEE and BOEM duties to track production and assess price forecasting, among other tasks, with ONRR's responsibility with respect to royalty relief limited to ensuring volume and royalty data remain up-to-date, and ensuring the collection of any royalty payments). 2014 MOU located at https://www.boem.gov/sites/default/files/documents//MOU%20BOEM-BSEE-ONRR%20Collaboration%202014-04-16.pdf .

Onshore, BLM may reduce the royalty on a lease “to encourage the greatest ultimate recovery of the resource and in the interest of conservation of natural resources.” See 43 CFR 3103.4-1(a). Prior to reducing a royalty rate, BLM must conduct an analysis to determine that the royalty reduction “is necessary to promote development of the lease or the BLM determines that the lease cannot be successfully operated under [the royalty rate agreed to in] the terms of the lease.” 43 CFR 3133.3(a)(2). The regulations also specify the process by which companies must apply for a royalty reduction and the required contents of an application. See 43 CFR 3103.4-1(b)(1)-(3).

ONRR invites public comment on whether the targeted royalty-relief authorities delegated to and administered by BSEE and BLM serve as more appropriate mechanisms to evaluate a lessee's economic or production hardship and to appropriately respond thereto than do the 2020 Rule's revenue-impacting provisions.

2. Deepwater Gathering Allowances (§§ 1206.110(a) and 1206.152(a))

a. The Regulation Text Adopted in the 2020 Rule Was Not in the Proposed 2020 Rule

Following the Proposed 2020 Rule's publication, ONRR discovered that some of the regulatory text intended for §§ 1206.110(a) and 1206.152(a) was missing. In the 2020 Rule, at 86 FR 4622, ONRR explained that the proposed regulatory text failed to include certain requirements that a lessee must meet to be eligible for a deepwater gathering allowance, as several commenters had noted. ONRR corrected for its prior error and revised the regulatory text in the 2020 Rule. It made the oil and gas sections consistent, and added language in both §§ 1206.110 and 1206.152 to incorporate the two previously missing components from the Deepwater Policy—the adjacency limitation and requirement for a lessee to identify a central accumulation point at or near the subsea wellhead. See also 86 FR 4654, 4656 (amendatory instructions for §§ 1206.110 and 1206.152 in the 2020 Rule). While the preamble included in the Proposed 2020 Rule had explained ONRR's intention to adopt a deepwater gathering allowance consistent with the former Deepwater Policy, the revisions to regulation text made with publication of the 2020 Rule, which incorporated key aspects of the former Deepwater Policy into §§ 1206.110 and 1206.152, can be seen as substantive changes that should have triggered a reopening of the comment period.

With respect to §§ 1206.110 and 1206.152, the public was not adequately apprised of and afforded an opportunity to read and comment on the proposed amendments to regulation text as those changes first appeared in the final rule. Accordingly, commenters focused on the Proposed 2020 Rule's regulation text would have been misled as to the availability of and criteria for a deepwater gathering allowance. ONRR believes that its failure to provide an opportunity for meaningful public comment on the regulation text of §§ 1206.110 and 1206.152 may constitute a procedural defect under 5 U.S.C. 553(b) and justify withdrawal of the deepwater gathering allowance provisions.

b. Deepwater Gathering Allowances Lack Statutory and Policy Support

A Federal oil and gas lessee must pay a royalty of not less than 12.5 percent in amount or value of the production removed or sold from the lease. See 43 U.S.C. 1337(a). Notwithstanding this statutory requirement, the 2020 Rule adopted the deepwater gathering allowance because doing so “may reduce a lessee's total royalty burden resulting in a lower total cost to operate on the OCS, and thereby potentially encouraging continued production and conservation of a resource.” 86 FR 4622. As its basis for incentivizing offshore production, the 2020 Rule stated that “Recent Executive and Secretarial Orders call on Federal agencies to appropriately promote and unburden domestic energy production, especially OCS resources.” Id. (citing E.O. 13783, “Promoting Energy Independence and Economic Growth,” E.O. 13795, “Implementing an America-First Offshore Energy Strategy,” and S.O. 3350, which promotes the America-First Offshore Energy Strategy).

The 2020 Rule's stated goal of promoting offshore oil and gas production through deepwater gathering allowances appears to be in conflict with the statutory requirement that royalties be paid based on the “amount or value” of the oil and gas produced. Value for royalty purposes is the value of the oil and gas in marketable condition. See California Co. v. Udall, 296 F.2d 384, 388 (D.C. Cir. 1961). Gathering costs, which include costs to measure and condition oil and gas for market, have long been considered a cost incurred by the lessee to place gas in marketable condition. Thus, gathering costs are the sole responsibility of the lessee. See 30 CFR 1206.20 and 1206.171; 53 FR 1184 at 1190-1191 (January 15, 1988); DCOR, ONRR-17-0074-OCS (FE), 2019 WL 6127405 (Aug. 26, 2019).

Also, the deepwater gathering allowance appears to lack policy support. E.O. 13783 and E.O. 13795 (prior to withdrawal) provided that the E.O.s “shall be implemented consistent with applicable law.” Applicable law requires that royalties be paid based on the “amount or value” of the production. See 43 U.S.C. 1337(a)(1)(A). Thus, it is not clear that these E.O.s authorized DOI to incentivize offshore oil and gas production through reduction of the lessee's royalty burden. Further, even if these E.O.s could be construed to provide such policy support, the E.O.s were revoked within days of the publication of the 2020 Rule and prior to the 2020 Rule's effective date.

c. The 2020 Rule Added Extensive Justification on Which the Public Was Unable To Comment

While the Proposed 2020 Rule provided a lengthy background of the history of the Deepwater Policy, it provided little justification for its codification, citing only that ONRR was “reevaluating its rules in light of E.O. 13783 and E.O. 13795, which call on Federal agencies to promote and unburden domestic energy production, and the Secretarial Orders encouraging robust and responsible exploration and development of [OCS] resources.” 85 FR 62060. In the 2020 Rule, however, ONRR explained its reasoning in far greater detail. See 86 FR 4622-4625. Thus, the Proposed 2020 Rule's lack of a fully-reasoned explanation for codifying a deepwater gathering allowance may have limited the public's opportunity to meaningfully comment on ONRR's intended regulatory change. See Section II.A.3. above and further discussion below.

The 2020 Rule listed several new factors that warranted a deepwater gathering allowance in the GOM. First, it explained that the GOM is now a mature hydrocarbon province—most of the large fields have been discovered and developed and the remaining fields are smaller and more likely to be developed with subsea tiebacks, the costs of which would likely be allowed as a transportation allowance under the deepwater gathering allowance. See 86 FR 4623. Second, the 2020 Rule noted the drop in commodity prices since the development and publication the 2016 Rule, which seemingly makes deepwater investment less economic. See 86 FR 4623-4624. Third, the 2020 Rule compared the decrease in applications for drilling permits in the GOM to an increase in onshore drilling permits. See 86 FR 4624. Fourth, it referenced BOEM's current National Assessment of Undiscovered Oil and Gas Resources of the U.S. OCS, which shows declines in the GOM's economically recoverable oil and gas resources. Id. Finally, it explained the increased risk, cost, and national importance of producing oil and gas from the deepwater OCS. 86 FR 4622-4625. Since this information was not provided in the Proposed 2020 Rule, the public did not have an opportunity to comment on these reasons for adopting a deepwater gathering allowance.

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

a. Extraordinary Processing Allowances Lack Statutory and Policy Support

Please see the discussion above at Section II.B.2.b.

b. Final Rule Included Inconsistent Language on Incentivizing Production

ONRR addressed extraordinary processing allowances and hard caps on transportation and processing allowances in the same section of the Proposed 2020 Rule. 85 FR 62058. ONRR asserted in the Proposed 2020 Rule that reinstating a lessee's ability to request approval to claim an extraordinary processing allowance and removing hard caps on transportation and processing allowances would incentivize production or remove a disincentive to produce. See 86 FR 4615. Those assertions conflict with other statements in the 2020 Rule that indicate the incentives, if any exist, are negligible. See 86 FR 4616-4617. Moreover, the Proposed 2020 Rule and 2020 Rule did not show any measurable connection between extraordinary processing allowances and increased production despite relying on an assertion that reinstating the allowance would incentivize production. The 2020 Rule adopted the amendment on extraordinary processing allowances but, based on a new economic analysis, did not adopt the hard caps on transportation and processing allowances.

The Proposed 2020 Rule stated that allowing a lessee to request approval for an extraordinary processing allowance and to request to exceed the transportation and allowance hard caps would incentivize production. 85 FR 62058. The 2020 Rule referenced various statutes, E.O.s, and S.O.s to “emphasize the importance of reducing regulatory burdens so that energy producers, and particularly oil, natural gas, and coal producers, are incentivized to produce more energy.” 86 FR 4615. However, in response to public comments, the 2020 Rule also provided that it was “not premised on increasing the production of oil, gas, or coal by some measured amount” and was, instead, “meant to 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.

Later, the 2020 Rule presents a conflicting position—that the monetary impact of the rule's amendments is insufficient to incentivize new production or to incentivize a lessee to continue producing from a Federal lease when the lessee otherwise would not. In response to comments that suggest the allowances provide a disincentive for a lessee to reduce their costs for transportation and processing, ONRR generally referred to the Federal Government's royalty share of production, which is typically 12 1/2 or 16 2/3 percent and a lessee's retention of the remaining 87 1/2 or 83 1/3 percent, respectively. The 2020 Rule concluded that the lessee's interest provided a significant incentive in minimizing transportation and processing costs. See 86 FR 4620-4621. Thus, the 2020 Rule assumed the Federal Government benefits from a lessee's motivation to be cost-conscious on its greater share. 86 FR 4646. Accordingly, ONRR stated it did not expect the regulatory limits on transportation and processing allowances on the government's smaller share to affect a lessee's decision making with respect to transportation and processing expenses proportionately applied to the lessee's greater share. See 86 FR 4626.

The 2020 Rule again contradicted earlier statements in that rule in its discussion on helium-bearing gas streams. See 86 FR 4628. Although ONRR acknowledges that helium production from Federal leases is managed by BLM, helium royalties are not affected by the extraordinary processing allowance provision. 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 considered a leasable mineral.”); see also https://www.blm.gov/programs/energy-and-minerals/helium/division-of-helium-resources (noting that the BLM's Division of Helium Resources “adjudicates, collects, and audits monies for helium extracted from Federal lands”). Further, only one of the prior extraordinary processing allowance approvals involved a helium-bearing gas stream. See 86 FR 4628. Yet, the 2020 Rule maintained that reinstating extraordinary processing allowances is necessary because “the U.S. has important economic and national security interests in ensuring the continuation of a reliable supply of helium, including that recovered from unique gas streams requiring costly equipment to remove carbon dioxide and hydrogen sulfide before helium can be extracted.” 86 FR 4628.

c. ONRR's Authority To Incentivize Production

Please see discussion at Section II.B.1., above.

d. The 2020 Rule Included Extensive Justification not Made Available for Public Comment

The reasons stated in the Proposed 2020 Rule for changes to the 2016 Valuation Rule's amendments to allowance limits (removing the regulatory hard caps on transportation and processing allowances and reinstituting extraordinary processing allowances) were premised on promoting domestic production by reducing administrative burdens and incentivizing production by increasing transportation and processing allowances and thereby decreasing the royalties due. See 85 FR 62058.

While the 2020 Rule did not adopt the proposed amendments to remove regulatory hard caps on transportation and processing allowances, it did reinstitute extraordinary processing allowances. In doing so, the 2020 Rule cited additional reasons from commenters that harken back to those submitted by commenters—and rejected by ONRR—during promulgation of the 2016 Valuation Rule. See https://www.onrr.gov/Laws_R_D/FRNotices/AA13.htm. Specifically, the 2020 Rule identified the following reasons in support of reinstituting a lessee's ability to request an extraordinary processing allowance:

(1) The technology to process two Wyoming unique gas streams has not changed, “despite technological advances in processing relevant to many other areas and types of gas streams.” 86 FR 4628.

(2) Extraordinary processing allowances are essential for two major gas processing facilities in Wyoming that treat challenging gas streams, and without an extraordinary processing allowance approval, these two plants are at a competitive disadvantage and may be prematurely retired. 86 FR 4627.

(3) One of Wyoming's unique gas streams, which previously had been approved for an extraordinary processing allowance, contains recoverable quantities of helium, an element that is vital to the Nation's security and economic prosperity. 86 FR 4628.

(4) In instances where a lessee might not otherwise choose to produce a gas stream containing helium, the opportunity to apply for an extraordinary processing allowance approval could incentivize the lessee to either continue producing or to initiate production. 86 FR 4628.

(5) The overall positive economic impact to Wyoming of continuing operation of the Federal leases that historically benefitted from extraordinary processing allowances outweighs any reduction in royalties Wyoming receives. 86 FR 4628.

As discussed above, although the Proposed 2020 Rule's proposed amendment to reinstitute extraordinary processing allowances was premised on incentivizing production, ONRR concluded that in most cases, providing an extraordinary processing allowance is not sufficient to incentivize production. See 86 FR 4627-4629. Apart from an unpersuasive argument about incentivizing production, ONRR relied entirely on reasons submitted by commenters in response to the Proposed 2020 Rule to support reinstating a lessee's ability to request an extraordinary processing allowance. See 86 FR 4627-4629. Therefore, the public did not have a meaningful opportunity to comment on most of the reasons that ONRR relied on in the 2020 Rule to reinstitute extraordinary processing allowances in the final rule.

4. Expansion of the Federal Gas Index Pricing Valuation Option to Federal Gas Sold Under Arm's-Length Contracts (§§ 1206.141(c) and 1206.142(d))

Prior to the 2016 Rule, ONRR regulations did not include an index-based valuation option for Federal gas or natural gas liquids. The 2016 Rule included such an option. It allowed Federal oil and gas lessees a choice of methods in calculating royalties due on gas and on natural gas liquids. One option, which a lessee could elect for a two-year period of time (or longer), was to calculate royalty value for gas using a formula based on the high of certain published index prices, reduced by either 5% for onshore production or 10% for offshore production (subject to certain limits), with the reduction designed to account for a conservative estimate of average transportation costs as adjusted by average, non-deductible costs of placing gas in marketable condition. This option was only available for gas a lessee disposed of in non-arm's-length transactions—transactions which are most frequently between affiliates, and therefore may not be at market value, but rather at prices influenced by the affiliate relationship. Since index prices are published prices derived from reported arm's-length transactions, ONRR considered the index-based valuation formula included in the 2016 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.

a. New Analysis Shows a Decrease in Royalties Collected

Several commenters on the Proposed 2020 Rule expressed concern that ONRR's assumption that 50 percent of lessees would elect the index-based valuation option was flawed and failed to represent logical business decision making processes. As commenters suggested, a lessee might apply an internal, business-driven threshold to decide if the index-based valuation method would be of economic benefit or harm. Within a single lessee's portfolio of properties, the lessee might choose to use the index-based valuation method for some properties but not others.

As described in this Economic Analysis below, ONRR has performed a new analysis to identify a more accurate estimate of the potential annual impact to royalty collections associated with the expansion of the index-based valuation method to arm's-length sales of natural gas and NGLs. This new analysis—based on the assumption that a lessee will act in its own financial best interest when deciding whether to use the index-based valuation option for its arm's-length sales—resulted in a projected net decrease in royalty collections of over $7 million per year as compared to collections made without the use of an index-based valuation option for arm's-length sales (i.e., as would occur under ONRR's regulations prior to the 2020 Rule, which only allow index-based valuation for non-arm's-length dispositions). This estimate sharply contrasts with the estimated $28.9 million per year increase in royalties stated in the 2020 Rule.

b. Arm's-Length Transaction Data Is a Better Measure of Value

Arm's-length contracts are those negotiated between independent parties with opposing economic interests. See 30 CFR 1206.20. ONRR has long concluded that the gross proceeds accruing under an arm's-length contract is, in most cases, the best indicator of fair market value. See, e.g., 53 FR 1186 (Jan. 15, 1988); 81 FR 43338 (July 1, 2016).

The 2020 Rule amended the 2016 Valuation Rule to introduce an index-based valuation option for Federal gas sold in arm's-length sales. The Economic Analysis in the 2020 Rule explained that, due to those amendments, royalty payments were expected to increase. ONRR relied on that analysis to deviate from its long-held position of relying exclusively on gross proceeds valuation (or a proxy where gross proceeds could not be reliably determined) to value arm's-length sales of Federal gas for royalty purposes. ONRR found that it had protected the Federal lessor's interest based on the conclusion that royalties were expected to meet or exceed values based on gross proceeds. But as explained in the Economic Analysis of this rule, the analysis in the 2020 Rule was flawed because it did not consider that economic factors will influence a lessee's decision to elect to use the index-based valuation method. ONRR has now reviewed historical data and can now show that electing the index-based valuation option would likely result in collecting less royalties for arm's-length sales.

5. Change of Index-Based Value to the Published Average Bidweek Price

The 2020 Rule amended regulations at §§ 1206.141(c)(1)(i) and (ii) and 1206.142(d)(1)(i) and (ii) to change references to the “highest monthly bidweek price” for the index pricing points to which a lessee's gas could flow, to the “highest of the monthly bidweek average prices” for the index pricing points to which a lessee's gas could flow. The use of average index prices was considered during the 2016 valuation rulemaking process and rejected. However, the 2020 Rule sought to reverse ONRR's earlier decision on that point so as to incentivize production. But, as discussed above, ONRR's authority to amend its valuation regulations to incentivize production is questionable; its 2020 Rule did not prove that it would incentivize production; and the same rule was internally inconsistent on whether it would, in fact, incentivize production.

6. Further Reduction to Index in Index-Based Valuation To Account for Transportation

The 2020 Rule amended regulations at §§ 1206.141(c)(1)(iv) and 1206.142(d)(1)(iv) to increase the amount of a reduction to index to account for the average costs of deductible transportation, after adjustment for the non-deductible costs of placing gas into marketable condition. This amendment was justified, in part, on an economic analysis of more recent royalty data, which showed higher average transportation costs than ONRR had relied on in adopting the 2016 Valuation Rule. However, the amendment also was justified on an intent to incentivize production. But, as discussed above, ONRR's authority to amend its valuation regulations to incentivize production is questionable; its 2020 Rule did not prove that it would incentivize production; and the same rule was internally inconsistent on whether it would, in fact, incentivize production.

C. Comments in Response to the First Delay Rule

ONRR received numerous comments in response to the First Delay Rule. Most commenters stated that a complete withdrawal of the 2020 Rule is warranted. Several commenters presented material and arguments that were distinguishable from earlier comments. The new materials provided by commenters, along with ONRR's most recent findings and updated economic analysis, led ONRR to change its position with respect to several considerations that were thought to support the 2020 Rule. ONRR addresses below many of the public comments that ONRR received in response to specific questions posed in the First Delay Rule.

1. Reliance on E.O.s and Scope of Secretarial Authorities Delegated to ONRR

ONRR relied on E.O.s in effect during the time it promulgated the 2020 Proposed Rule and the 2020 Rule. See 86 FR 4612 and 85 FR 62056-62057 (citing E.O. 13783, E.O. 13795, and E.O. 13892).

Public Comment: Multiple commenters opined that the change in policy requires ONRR to reconsider all or certain provisions of the 2020 Rule. Other commenters suggested the opposite, asserting that the prior E.O.s were not the sole justification for the 2020 Rule, and that ONRR provided sufficient detail in the 2020 Proposed and Final Rules to justify the amendments independent of the E.O.s. The commenters stated that the 2020 Rule sought to improve certainty and accuracy in royalty reporting and accounting consistent with FOGRMA and other mineral leasing laws. Commenters contended that ONRR relied on appropriate legal mandates to promulgate the 2020 Rule and asserted that policy changes cannot outweigh ONRR's governing legal authority under FOGRMA and the mineral leasing laws when it conducts rulemaking. One commenter asserted that changing policy where there is a new Administration or shift in E.O.s would ultimately create regulatory instability with respect to valuation and reporting requirements, thereby directly contradicting 30 U.S.C. 1711(a), which requires ONRR “to establish a comprehensive . . . production accounting and . . . auditing system to provide the capability to accurately determine . . . royalties . . . and other payments owed and to collect and account for such amounts in a timely manner.”

ONRR Response: ONRR proposed the 2020 Rule “because policy directives issued after [the 2016 Valuation Rule's publication] give different weight to the factual findings, and also dictate that a different policy-based outcome be pursued.” 85 FR 62056. The Proposed 2020 Rule also explained that an agency's reconsideration of regulations in light of a new Administration's policy objectives is acceptable and within the agency's discretion. Id. As such, ONRR's discussions for the regulatory changes largely focused on reducing regulatory burden or uncertainty and incentivizing production. See 85 FR 62054, 62056-62057. The Proposed 2020 Rule generally sought to further the objectives of E.O. 13783, E.O. 13795, E.O. 13892, S.O. 3350, and S.O. 3360 in two ways, providing mechanisms that promote new and continued domestic energy production and simplify reporting. See 85 FR 62057. However, ONRR did not (a) articulate how the 2020 Rule's proposed amendments furthered ONRR's delegated revenue management responsibilities, (b) explain the source of the delegation to ONRR to incentivize production, or (c) describe how the amendments would incentivize production or simplify reporting. In part, ONRR proposes to withdraw the 2020 Rule due to the revocation of these E.O.s and the uncertainty as to whether ONRR's authority and responsibilities permit it to adopt valuation rules for the purpose of incentivizing production and whether the amendments adopted would, in fact, incentivize production. Additional discussion of ONRR's reliance on incentivizing production as a rulemaking consideration is addressed in Section II.B.1.

2. Deepwater Gathering Costs

MMS issued the Deepwater Policy on May 20, 1999, authorizing a lessee to include certain deepwater gathering costs in its transportation allowance. Although the Deepwater Policy conflicted with 30 CFR 1206.110(a) and 1206.152(a), neither MMS nor ONRR adopted regulations resolving this conflict. The 2016 Valuation Rule ended the practice that had existed under the Deepwater Policy since 1999. See 30 CFR 1206.110(a) and 1206.152(a) (2019). The 2020 Rule sought to return to the practice permitted by the Deepwater Policy by codifying the policy in ONRR's regulations. See 86 FR 4612. The justification for the deepwater gathering amendments was based, in part, on declining oil and gas production in and revenues from the Gulf of Mexico. See 86 FR 4623-4624.

Public Comment: Some commenters stated that the deepwater gathering allowance is not consistent with the current law and policy of the United States. Some commenters emphasized that the deepwater gathering allowance evidenced that ONRR was prioritizing increased oil and gas production over other considerations, including proper management of royalty revenues and protecting the public interest. One commenter emphasized that the deepwater gathering allowance reduces Federal royalties without adequate justification. This commenter also noted that, while DOI must make the OCS available for development, OCSLA does not require ONRR to incentivize production for a lessee's benefit. A commenter asserted that ONRR provided no support for the assertion that a deepwater gathering allowance would incentivize production.

Some commenters supported the deepwater gathering allowance and emphasized that industry relied on the Deepwater Policy between 1999 and 2016 when making financial investments and leasing and development decisions. These commenters suggest that retroactively eliminating such allowances 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. Commenters described the deepwater production environment as very different from typical onshore or shallow water environments. Another commenter disagreed with the premise of the question posed in the First Delay Rule because, according to the commenter, subsea movement of oil and gas is not gathering. That commenter asserted that ONRR has not construed the subsea movement of oil and gas as gathering for many years. A commenter that supported the 2020 Rule's deepwater gathering allowance explained that the Deepwater Policy was originally created and implemented in 1999 and that the elimination of the Deepwater Policy in 2016 violated contract law and the APA.

ONRR Response: Reliance on the Deepwater Policy as part of long-term decision making is questionable since that guidance was, from the time of its issuance in 1999 up to its rescission in the 2016 Valuation Rule (see 81 FR 43340, 43343, and 43352), not in conformity with the express language of MMS' regulations that governed gathering and transportation allowances. See 30 CFR 1206.20 (defining gathering and transportation); 30 CFR 1206.110 (governing oil transportation allowance); 30 CFR 1206.152 (governing gas transportation allowance); see also Federal Crop Ins. Corp. v. Merrill, 332 U.S. 380, 386 (1947) (holding that reliance on an agency's advice that Federal crop insurance would cover a loss was unwarranted where such advice conflicted with a Federal regulation, noting that “not even the temptations of a hard case can elude the clear meaning of the regulation”).

Additionally, ONRR acknowledges that the 2020 Rule may have contained inconsistent language on incentivizing production and may not have demonstrated how and to what extent the amendments would impact production. In Sections II.A. II.B.1., and II.B.2., this proposed rule discusses these possible deficiencies in the 2020 Rule's justifications and other possible procedural errors specific to deepwater gathering costs.

3. Extraordinary Processing Allowances

Public Comment: Some commenters asserted that ONRR failed to provide a reasoned or detailed justification in the 2020 Rule for its decision to reinstate extraordinary processing allowances. Some commenters said reinstatement of the allowances would not incentivize production, opining that, instead, producers will produce when they are likely to receive enough proceeds to conduct economic operations. Other commenters generally characterized the allowances as a benefit extended to industry at cost borne by the public in the form of environmental harms and loss of royalty revenue.

A few commenters were in favor of reinstating extraordinary processing allowances, emphasizing that the allowances incentivize ongoing investment, as well as mutually beneficial development and production in atypical areas. These commenters noted that, due to the application and approval process, these allowances exist in limited circumstances. Commenters stated that industry relied on the allowances when making investment decisions and argued that the allowance is one of the tools that can be used to extend the life of existing wells and maximize the value of the associated leases.

ONRR Response: ONRR acknowledges that the 2020 Rule contained inconsistent language on incentivizing production. See discussion in Section II.B.1., infra.

4. Considering the Impacts of Climate Change

Public Comment: Multiple commenters urged ONRR to consider science on the source and impacts of climate change in setting royalty and revenue management policy. One commenter stated that ONRR should incorporate climate damages when setting royalties from fossil fuel extraction on public lands and waters, and the best way to do that is to include a carbon adder in the royalty rate that reflects the social cost of carbon and social cost of methane.

Other commenters disagreed. One commenter explained that this topic falls outside the scope of the 2020 Rule because ONRR's role within DOI is the collection and disbursement of Federal and Indian royalties owed on leases that have already been issued, which constitute binding contracts. This commenter further stated that the matters relating to the issuance of new leases and potential impacts on climate change arising from leasing activity fall outside of the authority delegated to ONRR and, accordingly, are irrelevant to an evaluation of the 2020 Rule.

Another commenter stated that, for purposes of determining the value for royalty purposes of coal production from Federal leases, consideration of climate change factors is unlawful as it contravenes DOI's statutory mandate under the MLA.

One commenter stated that ONRR appropriately addressed climate change in the 2020 Rule. See 86 FR 4612, 4617. This commenter urged that further environmental review of leases in the context of ONRR's royalty valuation rulemaking is inappropriate.

ONRR Response: Addressing climate change is a priority to the Federal Government. See, e.g., E.O. 13990, “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” and E.O. 14008, “Tackling the Climate Crisis at Home and Abroad.” However, as described in Section I.A., ONRR is to collect, verify, and then disburse the revenues associated with the production of natural resources on Federal and Indian lands and the OCS. 30 U.S.C. 1711; 30 CFR 1201.100. Moreover, the evaluation of environmental impacts is typically addressed by bureaus and agencies performing leasing and permitting functions. 86 FR 4612, 4617.

5. Assumptions Regarding the Index-Based Valuation Option

In the 2020 Rule, ONRR assumed that 50 percent of reported royalties would come from eligible lessees that elected to use the index-based valuation option, while the remaining 50 percent would not (86 FR 4643-4645) and, as a result, the lessees that elected the index-based valuation option were estimated to pay an additional $28.9 million per year in royalties while saving $1.35 million in administrative costs. 86 FR 4648-4650. ONRR posited these assumptions even though the result is that a lessee would pay additional royalties far in excess of the administrative cost savings they would realize. In the First Delay Rule, ONRR requested public comment on whether the assumption was flawed, and whether the resulting conclusion is appropriate and supported by current law and policy. See 86 FR 9288.

Public Comment: Multiple commenters disagreed with the assumption that 50 percent of lessees would elect to use the index-based valuation option. One commenter described the assumption as baseless and urged ONRR to refrain from making conclusions based on the assumption. One commenter concluded that a lessee will value gas by the option that minimizes the royalty burden, explaining, for example, if the royalty payment resulting from a first arm's-length sale is less than the royalty payment that would be due using an index-based valuation methodology, then the lessee will elect to use the first arm's-length sale.

A few commenters agreed the estimate was appropriate, noting that industry values early certainty and may elect to use the index-based valuation option even if the price is slightly higher than gross proceeds to avoid audits and other compliance reviews that lead to the issuance of an order directing payment of additional royalties and late payment interest. One commenter suggested that ONRR designed the index-based valuation option solely to collect a greater royalty payment than what a lessee historically paid. The commenter opined that ONRR correctly assumed that some companies would elect to use the index-based valuation method for the certainty alone.

ONRR Response: ONRR recently revised the method of its economic analysis (provided in the Section III) to more accurately value the potential annual impact to royalty collections resulting from the expansion of the index-based valuation method to arm's-length sales of Federal gas and NGLs. The new analysis estimates that this provision of the 2020 Rule would decrease royalty collections by $7 million per year, rather than the $28.9 million per year increase previously estimated. Please refer to Sections II.B.4. through II.B.6. for further discussion of the amendments to the index-based valuation method.

6. Transparency in Royalty Administration in Index-Based Valuation

Public Comment: A commenter stated that the index-based option provides clarity and early certainty for the producer but not for the public, asserting there is insufficient transparency in royalty administration for the public.

ONRR Response: ONRR appreciates the public's interest in bringing greater clarity, certainty, and transparency to royalty valuation in a manner that fits the needs of all stakeholders. The scope of this rulemaking is limited to the methods used to determine value for royalty purposes and does not consider topics related to how ONRR shares royalty information with the public. For additional information on production, collection, and disbursement activities, please visit https://revenuedata.doi.gov/

7. Substitution of Index-Based Value for Arm's-Length Sales

Public Comment: A commenter stated that it was premature for ONRR to extend the index-based valuation option to arm's-length gas sales without evaluating the impact of the index-based option on non-arm's-length gas dispositions.

Another commenter reiterated that royalty payments are not expected to be reduced under the index-based option. The commenter added that ONRR retains the ability to access sales information from a lessee that elects an index-based valuation methodology and concluded that ONRR will be able to use the sales information to monitor the royalty implications of the index-based method and, if appropriate, revisit the index-based valuation options.

Another commenter stated that, while they agree that arm's-length negotiated contracts are the best indicator of value, the index-based valuation option may better serve both ONRR and lessees because of the estimated $28.9 million per year increase in royalty payments while permitting a lessee to avoid the complex reporting required by a gross proceeds valuation method. The commenter added that the two-year election period will prevent a lessee from manipulating reporting based on what method might be more economically beneficial each month. One commenter explained that industry values early certainty and assurance it will not face a burdensome audit years after the initial royalty payment.

ONRR Response: ONRR, and previously MMS, has long viewed the gross proceeds received under an arm's-length contract between independent persons who are not affiliates and who have opposing economic interests to be the best indicator of value in most circumstances. See 53 FR 1186 (Jan. 15, 1988); 81 FR 43338 (July 1, 2016). A lessee that sells gas for a price higher than the index-based price will have a financial incentive to use the index-based price because valuation based on gross proceeds will result in the payment of more royalties. A lessee that sells the gas for a price lower than the index-based price has a financial incentive to use its gross proceeds for valuation. A lessee knows its gross proceeds and lessees have long used this amount to report and pay royalties for arm's-length sales. An index-based option for arm's-length sales may provide minimal value to industry since they have long used their gross proceeds to report and pay royalties. ONRR is proposing to withdraw the 2020 Rule in part because there are significant questions about whether the index-based option adds to early certainty and whether it will adequately ensure a fair return for the public.

In Section III, this proposed rule provides a revised economic analysis that estimates royalties impacts when a lessee bases its decision regarding whether to use index-based valuation on its financial interest. That analysis shows that this provision of the 2020 Rule would decrease royalty collections by over $7 million per year. Please refer to Sections II.B.4. through II.B.6. and III for further discussion of the amendments to the index-based valuation method and the solicitation of comments on ONRR's revised analysis and assumptions.

8. Procedural Adequacy of the 2020 Rulemaking Process

Public Comment: Several commenters stated the 2020 Rule was procedurally inadequate, asserting that interested parties did not have a fair opportunity to comment. One commenter stated that the 2020 Rule failed to provide a “reasoned explanation” for rescinding key portions of ONRR's 2016 rulemaking. The commenter explained that when an agency rescinds a prior policy, it must provide “a reasoned analysis for the change beyond that which may be required when an agency does not act in the first instance.” Another commenter stated that ONRR failed to respond to several public comments or responded in an incomplete or inaccurate manner. This commenter explained that the proposed rule failed to provide the general public, outside of the oil and gas industry, with sufficient information regarding the impacts of the proposals to enable the public to effectively participate in the rulemaking process. Another commenter noted that during the 2020 rulemaking, ONRR did not have public meetings and evidently accepted only the suggestions it received from industry.

Other commenters disagreed. One commenter stated that the 2020 Rule is sound law based on policy deliberations that span almost a decade of thorough public process properly conducted under the APA. Another commenter concluded that the 2020 Rule appropriately complied with the APA. This commenter explained that a proposed rule was issued that described in detail each change that the agency was considering, interested persons were given an opportunity to comment, and the final rule responds to those comments.

ONRR Response: ONRR agrees that procedural flaws exist in the 2020 Rule. Those flaws are explained in Sections II.A. and II.B. Further, ONRR notes that the 2020 Rule was not part of a rulemaking process that spanned a decade, as implied by the commenter.

III. Economic Analysis

ONRR's delay rules have afforded ONRR more time to reexamine the methods and analyses it used to estimate economic impacts of the 2020 Rule. 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. Based on an updated analysis, the net impact of the withdrawal of the 2020 Rule is an estimated $64.6 million annual increase in royalty collections.

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.

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.

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 warrant revision. To provide a more complete analysis, this rule presents the estimated royalty impacts of the withdrawal of the 2020 Rule using 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 proposed withdrawal. This amount stands in contrast to the annual decrease of $28.9 million per year in royalties previously estimated in 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 amounts 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 should also be 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 also recalculated the estimated one-time administrative cost associated with the optional use of the index-based valuation method. These costs are only calculated by a lessee once to distinguish allowed and disallowed costs in reported processing and transportation allowances. 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.

If the 2020 Rule is withdrawn, there will be an increase in administrative costs when compared to the current status quo.

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, 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 accurately identify 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 10 major geographic areas with active index prices. The 10 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 10 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 GOM. 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 property inclusive of any reported transportation allowances to the applicable index price for the property calculated in step (2) for all months in the first year of reported royalty data in the dataset;

(4) identified all properties 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 property 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 property 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 property 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 property 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 proposed rule. Also, this identification of the properties 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 estimates the index-based valuation method in the 2020 Rule will decrease 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. ONRR requests comments on the assumptions in the method described above.

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 properties 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 10 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 properties, ONRR:

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

(2) calculated an NGL basket prices (weighted average prices to group the individual NGL components), which 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:

(3) subtracted the current processing deductions, as well as fractionation costs and transportation costs referenced in ONRR regulations without amendment by the 2020 Rule and published online at https://www.onrr.gov,, as shown in the table below from the NGL basket price calculated in step (2):

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

(5) identified all properties 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 property list created in step (5) as the base universe of properties that would elect to use the index-based valuation method if available;

(7) compared the actual reported price for each month for each property 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 property 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 property 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 proposed rule.

ONRR estimates the index-based valuation method in the 2020 Rule will decrease royalty payments on arm's-length NGLs by approximately $660,000 per year, and that withdrawing the rule will increase royalty payments by $660,000 annually. ONRR requests comments on the assumptions in the method described above.

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 published bidweek price, rather than the highest published 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 proposed rule is similar to the method used in the 2020 Rule with adjustments made related to the universe of properties 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 properties with reported prices higher than the index price in seven or more months of the year. For non-arm's-length natural gas sales, this equates to 56.4 percent of the entire list of properties, 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 properties taking into account a lessee's potential financial benefit.

ONRR used reported royalty data using non-arm's-length (“NARM”) sales and 10 percent of the POOL sales type codes based on the assumption above in the same 10 major geographic areas with active index-pricing points, also listed above.

To calculate the estimated impact, ONRR:

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

(2) multiplied the royalty volume by the published index prices identified for each region;

(3) totaled the estimated royalties using the published index prices calculated in step (2);

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

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

Because ONRR identified that 56.4 percent of properties fall in the universe of properties 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.

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. 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 properties 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 10 percent of the POOL sales type codes from the same 10 major geographic areas with active index-pricing points listed above.

To calculate the estimated impact, ONRR:

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

(2) calculated the transportation-related adjustment as published in the current regulations and the adjustment outlined in the table below for each area identified in step (1);

(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 will result in a decrease in royalty collections of approximately $8 million per year if the 2020 Rule goes into effect, and an increase in royalty collections of like amount if the 2020 Rule is withdrawn, as reflected in the table below.

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. ONRR adopted 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 carbon dioxide (CO₂) for calendar years 2014-2018. The total processing costs are reported across all three products for these unique situations. For these leases, ONRR retrieved all form ONRR-2014 royalty lines with a processing allowance reported by lessees. For CO₂ and sulfur produced from these leases, ONRR then calculated the annual average processing allowances which exceeded the 662/3 percent limit and found that only two years exceeded the 662/3 percent limit. Under these unique approved exceptions, the processing allowances are also reported against residue gas. To account for this, ONRR added the average annual processing allowances taken from those same leases for residue gas. Based on these calculations, ONRR estimates the royalty impact of withdrawing this provision of the 2020 rule would be an increase in royalties of $11.1 million per year.

ONRR recognizes that there could be an increase in the number of requests submitted to ONRR related to extraordinary cost processing allowances under this provision. There is little data available to identify the magnitude of these requests, and there is not enough information to determine how many of these potential requests would be approved or denied by ONRR. ONRR invites public comment on this issue and solicits any data that would allow the agency to better quantify these impacts.

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

In the 2020 Rule, ONRR proposed regulatory changes that would allow an OCS lessee to take certain gathering costs as transportation. 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 if the 2020 Rule goes into effect.

As previously discussed, the Deepwater Policy was in effect from 1999 until January 1, 2017. 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 would codify a deepwater gathering allowance similar to the Deepwater Policy. To analyze the impact to industry of 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 have qualified for an allowance thereunder. 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 GOM. 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 GOM (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.

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 qualified lessees to monitor their costs and perform additional calculations. 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.

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 properties with arm's-length sales would elect this option. This is more accurate than the 2020 Rule assumption, and ONRR will use it to estimate the potential administrative cost savings for industry.

ONRR estimated the index-based valuation method will shorten the time burden per line reported by 50 percent (to 1.5 minutes per electronic line submission and 3.5 minutes per manual line submission). As with Cost 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.

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 lessees elect to use the index-based valuation method. ONRR believes this calculation and method are still adequate and will use the same information again in this rule. 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 in the 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 payor to be 3.4, across a total of 448 payors reporting residue gas and NGLs, between 2014-2018. Using the BLS labor cost per hour of $59.26 (described above) and adjusting the assumption to half of lessees choosing the index-based valuation method, ONRR believes the 2020 Rule would have resulted in a one-time cost savings to industry of $4.5 million dollars. If the 2020 Rule is withdrawn, lessees will incur this one-time administrative cost.

State and Local Governments

ONRR estimated that, as a result of the 2020 Rule, States and certain local governments would receive an overall decrease in royalty disbursements based on the category that properties fall under, including OCSLA section 8(g) leases (See 43 U.S.C. 1337(g)), GOMESA (See 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), 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:

Please visit https://revenuedata.doi.gov/explore/#federal-disbursements to find more information on ONRR's disbursements to any specific State or local government. More specific details about estimated royalty disbursement impacts can be found below.

Indian Lessors

The provisions in the 2020 Rule and this proposed 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 to the Federal Government (detailed in the next table of this section) would be a reduction in royalties of $49.7 million per year. If the 2020 Rule is withdrawn, this estimated impact to royalty collections relative to 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 withdrawal of the 2020 Rule. 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 properties.

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

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

The 2020 Rule removed the default provision from its regulations. In instances of misconduct, breach of a lessee's duty to market, or other situations where royalty value cannot be determined under the rules, ONRR can use statutory authority to determine Federal oil and gas royalty value under lease terms, FOGRMA, and other authorizing legislation in the same manner—as ONRR would have prior to adoption of the 2016 Valuation Rule. There is no impact to royalty collections on account of the default provision regardless of whether the Final 2020 Rule goes into effect or is withdrawn in whole or part.

Federal and Indian Coal

In the 2020 Rule, ONRR estimated there will be no change to royalty collections for the Federal Government, Tribes, individual Indian mineral owners, States, or industry for Federal and Indian coal. ONRR has not changed or adjusted this estimate in this proposed rule. There is no impact to royalty collections on account of the coal provisions in the 2020 Rule regardless of whether the 2020 Rule goes into effect or is withdrawn in whole or part.

IV. Request for Public Comments

ONRR is proposing to withdraw the 2020 Rule. For ONRR's consideration, before reaching a final decision on this action, ONRR requests comments, without limitation, on this proposed action. ONRR is also requesting any comments pertaining to the substance or merits of the 2020 Rule, and the prior regulatory scheme it replaced. Additionally, ONRR seeks public comment on the following:

1. Should ONRR withdraw only the deepwater gathering allowance, extraordinary processing allowance, and/or index-based valuation provisions of the 2020 Rule, all of which reduce royalties; withdraw all royalty valuation provisions of the 2020 Rule; or allow all royalty valuation provisions 2020 Rule to go into effect?

2. Should ONRR allow some or all of the 2020 Rule's civil penalty amendments, at 30 CFR part 1241, to go into effect? Or should ONRR withdraw those amendments, and, if so, should it initiate a new civil penalty rulemaking on the same or different subjects?

3. What impacts, if any, or other information should ONRR consider if it were to adopt a final rule to either withdraw the deepwater gathering allowance, extraordinary processing allowance, and index-based valuation amendments of the 2020 Rule, or withdraw the 2020 Rule in its entirety, and make the withdrawal effective immediately upon publication under 5 U.S.C. 553(d)(1) or (3)?

4. This proposed rule provides a revised economic analysis of the Final 2020 Rule's amendments to the index-based valuation method. The updated analysis shows the net impact of the amendments is an estimated decrease of $20.6M in royalty collection per year (from table above, $6,800,000 + $660,000 + $5,062,000 + $8,033,000). Because the new analysis is presented for the first time in this rule, the public has not been given an opportunity to comment on the new analysis. ONRR invites public comment on the new information, methods ONRR used to perform its estimates, and whether it justifies withdrawal of some or all of the Final 2020 Rule's amendments to index-based valuation.

V. 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. This proposed rule is a significant regulatory action under E.O. 12866. Because the primary effect is on royalty payments, ONRR expects that withdrawal of the 2020 Rule will largely result in transfers, which are described in the table below. ONRR also anticipates that withdrawal of the 2020 Rule would result in annual administrative cost savings of $2.85 million and a one-time administrative cost of $4.52 million.

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.

To estimate the present value of potential administrative costs/savings to industry from withdrawal of the 2020 Rule, 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 the 2020 Rule is in effect and incursion of administrative cost savings each year thereafter.

E.O. 13563 reaffirms the principles of E.O. 12866, while calling for improvements in the nation's regulatory system to promote predictability, to reduce uncertainty, and to use the 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 rule in a manner consistent with these requirements.

B. Regulatory Flexibility Act

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

For the changes to 30 CFR part 1206, this rule would affect lessees of Federal oil and gas leases. For the changes to 30 CFR part 1241, this rule could affect 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 approximately 1,208 different companies submit royalty reports for Federal oil and gas leases and other Federal mineral leases to ONRR each month. Of these, approximately 106 companies are not considered small businesses because they exceed the employee count threshold for small businesses. ONRR estimated that the remaining 1,102 companies affected by this rule are small businesses. ONRR has not changed the determination it made in the 2020 Rule. See 86 FR 4651.

As stated in the Summary of Royalty Impacts and Costs Table, shown above, withdrawal of the 2020 Rule would impact industry through an increase in royalties of approximately $64.6 million per year. Small businesses account for approximately eight percent of those royalties. Applying that percentage, ONRR estimates that withdrawal of the 2020 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 companies due to, for example, differences in the revenues generated by a small business that is subject to royalties.

Also stated above, withdrawal of the 2020 Rule would impact industry through a decrease in administrative costs of approximately $2.9 million per year and a first-year increase of $4.5 million. Applying the eight percent small-business share, ONRR estimates that withdrawal of the 2020 Rule would decrease administrative costs to small business lessees by approximately $211 per year and separately increase costs by $327 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, which calculates to 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 ($211) net to an increase in overall cost to 1,102 small businesses of $4,479 per year. As a percentage of average small-business revenue, this proposed rule would increase costs to those entities by 0.12 percent ($4,479 divided by $3.6 million).

According to the U.S. Census Bureau's 2017 Economic Census data, oil and gas extractors with 20 employees or less collected $2.1 million per year per entity. Taking the $4,479 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 that small entities typically do not participate in.

In accordance with 5 U.S.C. 605, the head of the agency certifies that this proposed 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). ONRR therefore expects that the withdrawal of the 2020 rule would likewise not be a major rule under that provision. Like the 2020 rule, ONRR anticipates that this rule, if finalized:

(1) Would not have an annual effect on the economy of $100 million or more. ONRR estimates that the cumulative effect on all of industry if the 2020 Rule goes into effect would be 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 be a transfer rather than a cost or cost savings. The Summary of Royalty Impacts and Costs Table, as shown above, demonstrates that the 2020 Rule's cumulative economic impact on industry, State and local governments, and the Federal Government would be well below the $100 million threshold that the Federal Government uses to define a rule as having a significant impact on the economy;

(2) would 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) section above; 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

Neither the 2020 Rule nor its withdrawal would 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 that the Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq.) requires because the 2020 Rule or its withdrawal is an unfunded mandate.

E. Takings (E.O. 12630)

Under the criteria in section 2 of E.O. 12630, neither the 2020 Rule nor its withdrawal have any significant takings implications. Neither rule imposes conditions or limitations on the use of any private property because they apply to the valuation of Federal oil and gas and Federal and Indian coal only. The 2020 Rule only makes minor technical changes to ONRR's civil penalty regulations that have no expected economic impact, and the withdrawal of the 2020 Rule would have no economic impact. Neither rule requires a takings implication assessment.

F. Federalism (E.O. 13132)

Under the criteria in section 1 of E.O. 13132, the 2020 Rule or its withdrawal does not have sufficient federalism implications to warrant the preparation of a federalism summary impact statement. The management of Federal oil and gas is the responsibility of the Secretary, and ONRR distributes all of the royalties that it collects under Federal oil and gas leases as directed by the relevant disbursement statutes. The 2020 Rule or its withdrawal 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)

The proposed withdrawal of the 2020 Rule complies with the requirements of E.O. 12988. Specifically, the proposed withdrawal 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 the 2020 Rule and the proposed withdrawal under the Department's consultation policy and the criteria in E.O. 13175 and determined that neither 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 potentially impacted tribes. With the exception of the Kayenta Mine located in Navajo Nation, which ceased production in 2019, the circumstances relevant to the Indian coal leases have not changed since the prior consultations occurred. As with the 2016 Valuation Rule, ONRR's review of the royalty impact to tribes from the 2020 Rule and its proposed withdrawal concludes that neither would substantially impact the three tribes. Further, neither rule is 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. The 2020 Rule and its proposed withdrawal do not require any new or modify any existing information collections subject to OMB's approval. Thus, ONRR did not submit any new information collection requests to OMB related to the 2020 Rule or its proposed withdrawal.

Both the 2020 Rule and its proposed withdrawal leave intact the information collection requirements that OMB has already approved under OMB Control Numbers 1012-0004, 1012-0005, and 1012-0010.

J. National Environmental Policy Act of 1969

The 2020 Rule and its proposed withdrawal do not constitute a major Federal action significantly affecting the quality of the human environment. ONRR is not required to provide a detailed statement under the NEPA because both rules qualify for a categorical exclusion under 43 CFR 46.210(c) and (i), as well as the Departmental Manual, part 516, section 15.4.D, which covers routine financial transactions including such things as audits, fees, bonds, and royalties and policies, directives, regulations, and guidelines that are of an administrative, financial, legal, technical, or procedural nature. ONRR also determined that both the 2020 Rule and its proposed withdrawal do not involve any of the extraordinary circumstances listed in 43 CFR 46.215 that require further analysis under NEPA.

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

Both the 2020 Rule and its proposed withdrawal are not significant energy actions under the definition in E.O. 13211. Neither 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 either action as a significant energy action. A Statement of Energy Effects pursuant to E.O. 13211, therefore, is not required.

L. Clarity of This Regulation

E.O. 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 ONRR_RegulationsMailbox@onrr.gov. To better help ONRR understand your comments, please make your comments as specific as possible. For example, you should tell ONRR the numbers of the sections or paragraphs that you think were written unclearly, the sections or sentences that you think are too long, and the sections for which you believe lists or tables would be useful.

This action is taken pursuant to delegated authority.

List of Subjects

30 CFR Part 1206

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

30 CFR Part 1241

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