[Federal Register Volume 86, Number 187 (Thursday, September 30, 2021)]
[Rules and Regulations]
[Pages 54045-54070]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2021-20979]


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DEPARTMENT OF THE INTERIOR

Office of Natural Resources Revenue

30 CFR Parts 1206 and 1241

[Docket No. ONRR-2020-0001; DS63644000 DRT000000.CH7000 212D1113RT]
RIN 1012-AA27


ONRR 2020 Valuation Reform and Civil Penalty Rule: Final 
Withdrawal Rule

AGENCY: Office of Natural Resources Revenue (``ONRR''), Interior.

ACTION: Final rule; withdrawal.

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SUMMARY: ONRR is withdrawing the ONRR 2020 Valuation Reform and Civil 
Penalty Rule (``2020 Rule'').

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withdrawn.

FOR FURTHER INFORMATION CONTACT: For questions, contact Luis Aguilar, 
Regulatory Specialist, Appeals & Regulations, ONRR, by email at 
onrr.gov">ONRR_RegulationsMailbox@onrr.gov, or by telephone (303) 231-3418.

SUPPLEMENTARY INFORMATION:

                         Table of Abbreviations and Commonly Used Acronyms in This Rule
----------------------------------------------------------------------------------------------------------------
                     Abbreviation                                            What it means
----------------------------------------------------------------------------------------------------------------
2016 Valuation Rule..................................  Consolidated Federal Oil & Gas and Federal & Indian Coal
                                                        Valuation Reform Rule, 81 FR 43338 (July 1, 2016).
2016 Civil Penalty Rule..............................  Amendments to Civil Penalty Regulations, 81 FR 50306
                                                        (August 1, 2016).
2017 Repeal Rule.....................................  Repeal of Consolidated Federal Oil & Gas and Federal &
                                                        Indian Coal Valuation Reform, 82 FR 36934 (August 7,
                                                        2017).
2020 Rule............................................  ONRR 2020 Valuation Reform and Civil Penalty Rule, 86 FR
                                                        4612 (January 15, 2021).
ALJ..................................................  Administrative Law Judge.
APA..................................................  Administrative Procedure Act of 1946, as amended, 5
                                                        U.S.C. 551, et seq.
BLM..................................................  Bureau of Land Management.
BLS..................................................  Bureau of Labor Statistics.
BOEM.................................................  Bureau of Ocean Energy Management.
BSEE.................................................  Bureau of Safety and Environmental Enforcement.
Deepwater Policy.....................................  MMS' May 20, 1999, memorandum entitled ``Guidance for
                                                        Determining Transportation Allowances for Production
                                                        from Leases in Water Depths Greater Than 200 Meters''.
DOI..................................................  U.S. Department of the Interior.
E.O..................................................  Executive Order.
FERC.................................................  Federal Energy Regulatory Commission.
First Delay Rule.....................................  ONRR 2020 Valuation Reform and Civil Penalty Rule: Delay
                                                        of Effective Date; Request for Public Comment, 86 FR
                                                        9286 (February 12, 2021).
FOGRMA...............................................  Federal Oil and Gas Royalty Management Act of 1982, 30
                                                        U.S.C. 1701, et seq.
MLA..................................................  Mineral Leasing Act of 1920, 30 U.S.C. 181, et seq.
MMS..................................................  Minerals Management Service.
NEPA.................................................  National Environmental Policy Act of 1970, as amended, 42
                                                        U.S.C. 4321, et seq.

[[Page 54046]]

 
NGL..................................................  Natural Gas Liquids.
OCS..................................................  Outer Continental Shelf.
OCSLA................................................  Outer Continental Shelf Lands Act of 1953, 43 U.S.C.
                                                        1331, et seq.
OMB..................................................  Office of Management and Budget.
ONRR.................................................  Office of Natural Resources Revenue.
Proposed 2020 Rule...................................  ONRR 2020 Valuation Reform and Civil Penalty Rule (a
                                                        proposed rule), 85 FR 62054 (October 1, 2020).
Proposed Withdrawal Rule.............................  ONRR 2020 Valuation Reform and Civil Penalty Rule:
                                                        Notification of Proposed Withdrawal, 86 FR 31196 (June
                                                        11, 2021).
Second Delay Rule....................................  ONRR 2020 Valuation Reform and Civil Penalty Rule: Delay
                                                        of Effective Date, 86 FR 20032 (April 16, 2021).
Secretary............................................  Secretary of the Department of the Interior.
S.O..................................................  Secretarial Order.
----------------------------------------------------------------------------------------------------------------

I. Introduction

    The 2020 Rule, as published, amends a number of provisions adopted 
by ONRR in the 2016 Valuation Rule and the 2016 Civil Penalty Rule 
relating to the valuation of oil and gas produced from Federal leases 
for royalty purposes; the valuation of coal produced from Federal and 
Indian leases for royalty purposes; and the assessment of civil 
penalties. 86 FR 4612. The 2020 Rule amended the following portions of 
ONRR's valuation regulations that were adopted via the 2016 Valuation 
Rule in the following ways:
    1. Deepwater gathering--codifies the principles of the Deepwater 
Policy to allow certain gathering costs to be deducted as part of a 
lessee's transportation allowance for Federal oil and gas produced on 
the OCS at depths greater than 200 meters.
    2. Extraordinary processing allowances--reinstates a lessee's 
ability to apply for approval to claim an extraordinary processing 
allowance for Federal gas in situations where the gas stream, plant 
design, and/or unit costs are extraordinary, unusual, or unconventional 
relative to standard industry conditions and practice.
    3. Index to be used in index-based valuation option--lowers the 
applicable index from the highest bidweek price to the average bidweek 
price.
    4. Percentage deduction allowable for transportation in index-based 
valuation option--increases the percentage reduction to index stated in 
the 2016 Valuation Rule to reflect an average of more recently reported 
transportation cost data.
    5. Arm's-length valuation option--extends the index-based valuation 
option (previously allowed in non-arm's-length sales) to arm's-length 
Federal gas sales.
    6. Default provision--eliminates the default provision and 
references thereto from the Federal oil and gas and Federal and Indian 
coal regulations, which provision established criteria explaining how 
ONRR would exercise the Secretary's authority to establish royalty 
value when typical valuation methods are unavailable, unreliable, or 
unworkable.
    7. Misconduct--eliminates the definition of ``misconduct.''
    8. Signed contracts--eliminates the requirement that a lessee have 
contracts signed by all parties.
    9. Citation to legal precedent--eliminates the requirement to cite 
legal precedent when seeking a valuation determination.
    10. Valuation of coal based on electricity sales--eliminates the 
requirement to value certain Federal and Indian coal based on the sales 
price of electricity.
    11. Coal cooperative--removes the definition of ``coal 
cooperative'' and the method to value sales between members of a ``coal 
cooperative'' for Federal and Indian coal.
    12. Non-substantive corrections--amends various regulations by 
making non-substantive corrections.
    The 2020 Rule amended the following provisions of ONRR's civil 
penalty regulations that were adopted in the 2016 Civil Penalty Rule in 
the following ways:
    1. Facts considered in assessing penalties for payment violations--
specifies that ONRR considers unpaid, underpaid, or late payment 
amounts in the severity analysis for payment violations.
    2. Consideration of aggravating and mitigating circumstances--
specifies that ONRR may consider aggravating and mitigating 
circumstances when calculating the amount of a civil penalty.
    3. Conforming civil penalty regulations to a court decision--
eliminates 30 CFR 1241.11(b)(5), which permitted an ALJ to vacate a 
previously-granted stay of an accrual of penalties if the ALJ later 
determined that a violator's defense to a notice of noncompliance or 
assessment of civil penalties was frivolous.
    The 2020 Rule has not, however, gone into effect. See 86 FR 9286 
and 86 FR 20032.
    The Proposed Withdrawal Rule described the procedural history of 
ONRR's publication of the Proposed 2020 Rule, the 2020 Rule, the First 
Delay Rule, and the Second Delay Rule. See 86 FR 31197-31198. ONRR 
published the Proposed 2020 Rule on October 1, 2020. On January 15, 
2021, ONRR published the 2020 Rule. The effective date of the 2020 Rule 
was originally February 16, 2021.
    On January 20, 2021, two memoranda were issued, one by the 
Assistant to the President and Chief of Staff and one by OMB, which 
directed agencies to consider a delay of the effective date of rules 
published in the Federal Register that had not yet become effective and 
to invite public comment on issues of fact, law, and policy raised by 
those rules. 86 FR 7424.
    On February 12, 2021, ONRR published the First Delay Rule which 
delayed the effective date of the 2020 Rule by 60 days and opened a 30-
day comment period on the facts, law, and policy underpinning the 2020 
Rule as well as on the impact of a delay in the effective date of the 
2020 Rule. After the close of the First Delay Rule's comment period, 
ONRR determined that a second delay of the 2020 Rule's effective date 
was needed. Thus, on April 16, 2021, ONRR published a second final rule 
which further delayed the effective date until November 1, 2021.
    ONRR published the Proposed Withdrawal Rule on June 11, 2021. The 
Proposed Withdrawal Rule invited comment on a complete withdrawal of 
the 2020 Rule as well as potential alternatives. See 86 FR 31215. The 
Proposed Withdrawal Rule also requested comments pertaining to the 
substance or merits of the 2020 Rule and the regulatory scheme it 
replaced. Id.
    In response to the Proposed Withdrawal Rule, ONRR received ten 
comment submissions and 151 pages of new comment materials from oil, 
gas,

[[Page 54047]]

and coal trade associations and representatives, public interest 
groups, and State entities. After consideration of the public comment 
and further analysis by the agency, ONRR publishes this final rule 
pursuant to the authority delegated to it. See 30 U.S.C. 189 (MLA); 30 
U.S.C. 1751 (FOGRMA); 43 U.S.C. 1334 (OCSLA); See S.O. 3299, sec. 5; 
and S.O. 3306, sec. 3-4.

II. Rationale for Withdrawal of the 2020 Rule

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

A. Inadequate Comment Period

    Several years ago, ONRR amended the 30 CFR part 1206 regulations 
when it adopted the 2016 Valuation Rule. See 81 FR 43338. Though the 
2016 Valuation Rule followed a public comment period of 120 days, the 
2020 Rule followed a 60-day public comment period. In litigation 
construing ONRR's adoption of the 2017 Repeal Rule, the United States 
District Court for the Northern District of California found that ONRR 
did not provide meaningful opportunity for comment when it repealed the 
2016 Valuation Rule without a comment period of commensurate length to 
the 2016 Valuation Rule's public comment period. California v. U.S. 
Dep't of the Interior, 381 F. Supp. 3d 1153, 1177-78 (N.D. Cal. 2019). 
Specifically, the District Court found that the 30-day comment period 
used for the 2017 repeal of the 2016 Valuation Rule was too brief when 
ONRR had a much longer comment period for the adoption of the 2016 
Valuation Rule--approximately 120 days. Id.
    While California is a decision by a tribunal of inferior 
jurisdiction and not binding on litigants who did not appear in that 
case, ONRR was a party to the case. Because ONRR did not appeal the 
California case, it is bound by the decision in a manner not applicable 
to other Federal agencies and bureaus. Here, though ONRR allowed for 
more than 30 days of comment on the 2020 Rule, ONRR provided a 60-day 
comment period on the Proposed 2020 Rule when the 2016 Valuation Rule 
was adopted after a 120-day comment period. ONRR needed to provide the 
public with more than a 60-day comment period for review and comment on 
the 2020 Rule even though some of the amendments may be less complex or 
controversial than others because the public needed time to consider 
the lengthy rulemaking history dating back to the 2016 Valuation Rule 
and how the amendments interrelate. ONRR's decision to combine various 
oil, gas, and coal valuation amendments with civil penalty amendments 
into one rulemaking, when previously it had addressed many of these 
topics in separate rulemakings in the 2016 Valuation Rule and 2016 
Civil Penalty Rule, further added to the necessary review and comment 
time. Thus, ONRR must withdraw the 2020 Rule.
    Public Comment: A commenter stated that the 2020 Rule did not 
rescind the entire 2016 Valuation Rule or fully reinstate the prior 
regulations.
    ONRR Response: The 2020 Rule, while not fully repealing the 2016 
Valuation Rule, repealed nearly all the revenue-impacting provisions 
adopted in the 2016 Valuation Rule. Thus, the 2020 Rule is fairly 
considered a targeted repeal of many of the substantive, revenue-
impacting provisions of the 2016 Valuation Rule. Because ONRR is 
uniquely bound by California and most of the amendments have a lengthy, 
complex rulemaking history, ONRR should have provided the public with a 
comment period of commensurate length with respect to its targeted 
repeal of the substantive provisions of the 2016 Valuation Rule as was 
employed when those provisions were adopted in the 2016 Valuation Rule. 
This is especially the case since ONRR combined valuation and civil 
penalty amendments together in the 2020 Rule.
    Public Comment: Multiple commenters stated that the public had 
sufficient notice and opportunity to comment on the 2020 Rule. The 
commenters stated that the Proposed Withdrawal Rule failed to 
acknowledge that the Proposed 2020 Rule was available on ONRR's website 
for almost two months prior to its publication in the Federal Register. 
The commenters stated that, with the additional time factored in, the 
public had approximately 115 days to comment on the 2020 Rule, similar 
to the 120-day comment period provided for the 2016 Valuation Rule.
    ONRR Response: There is no legal authority supporting a conclusion 
that publication on ONRR's website can be substituted, in whole or in 
part, for the notice required under the APA. See 5 U.S.C. 553(b) 
(stating that, with only limited exceptions not applicable here, 
``notice of proposed rulemaking shall be published in the Federal 
Register''). Moreover, there is no demonstration that the general 
public was perusing ONRR's website for advance notice of a proposed 
rule instead of relying on the traditional and statutorily-authorized 
method of notice in the Federal Register. In addition, the public was 
unable to submit comments for ONRR's review during the 55 days the 
draft was available only on ONRR's website. The comment period for the 
2020 Rule did not open until its publication in the Federal Register 
and was only open for a 60-day period. Therefore, the commenters' 
assertions do not adequately consider the notice and comment 
requirements under the APA. See 5 U.S.C. 553(b); see also California, 
381 F. Supp. at 1177 (finding legal deficiencies in a comment period 
for ONRR's withdrawal rule that was substantially shorter than the 
comment period employed when ONRR adopted the rule).

B. No Discussion of Alternatives

    The Proposed 2020 Rule did not demonstrate that ONRR considered 
alternatives to the repeal of the provisions adopted via the 2016 
Valuation Rule or the provisions adopted via the 2016 Civil Penalty 
Rule. Although the Proposed 2020 Rule solicited comment on 
alternatives, that alone was not sufficient since ONRR had to comply 
with the requirements of the California case. According to California, 
ONRR needed to discuss alternatives when adopting the 2020 Rule 
because, as discussed herein, ONRR was attempting, through the 2020 
Rule, to repeal most of the substantive provisions adopted in 2016. 
California, 381 F. Supp. 3d at 1168-69. The 2020 Rule should have 
discussed alternatives. For example, ONRR should have discussed 
alternatives to the substantive, revenue impacting provisions instead 
of simply reversing course and reinstating a deepwater

[[Page 54048]]

gathering policy (which had been overturned by the 2016 Valuation 
Rule), reinstating extraordinary processing allowances (which had been 
repealed by the 2016 Valuation Rule), and making changes to the index-
based pricing options (which had been discussed but rejected in the 
2016 Valuation Rule). Likewise, instead of merely repealing the default 
provision, the definition of misconduct, the requirement for signatures 
on contracts, and the requirement to cite legal precedent in requests 
for valuation determinations, ONRR should have discussed other 
alternatives which could have included further amendment of the 
existing provisions or amendments to related provisions.
    These shortcomings resemble ONRR's 2017 attempt to repeal the 2016 
Valuation Rule, where the United States District Court for the Northern 
District of California found that ONRR did not discuss alternatives to 
a full repeal of the 2016 Valuation Rule and explained that an agency 
must discuss alternatives even if the agency is repealing less than an 
entire rulemaking. See California, 381 F. Supp. 3d at 1168-69; Yakima 
Valley Cablevision, Inc. v. F.C.C., 794 F.2d 737, 746 n. 36 (D.C. Cir. 
1986).
    With respect to the repeal of the two coal provisions, ONRR notes 
that the position taken in the 2020 Rule is consistent with, but not 
identical to, the position taken by the Federal defendants in the Cloud 
Peak case, specifically that the coal cooperative provisions and the 
provisions providing for valuation of certain coal sales based on 
electricity are defective. See Cloud Peak Energy Inc. v. U.S. Dep't of 
the Interior, 415 F. Supp. 3d 1034 (D. Wyo. 2019). However, on 
September 8, 2021, the United States District Court for the District of 
Wyoming issued a ruling on the merits of the Cloud Peak petitions, 
which ruling renders moot the portions of the 2020 Rule applicable to 
Federal and Indian coal.
    Public Comment: A commenter stated that ONRR's Proposed Withdrawal 
Rule fails to cite any legal support for its assertion that the APA 
requires an analysis of the alternatives to a repeal of regulations. 
The commenter also stated that ONRR failed to quantify the amount of 
discussion required to meet this standard. The commenter asserted that 
ONRR's reliance on California is unhelpful to its position because, 
according to the commenter, the case is currently under appeal at the 
U.S. Court of Appeals for the Ninth Circuit. The commenter also argued 
that the case law relied upon by ONRR is inapplicable in this instance. 
More specifically, the commenter stated that the California case 
primarily focused on rule repeals. The commenter further stated that 
the 2020 Rule did not repeal the entire 2016 Valuation Rule, but 
instead modified only some of the regulations promulgated through the 
2016 Valuation Rule.
    Another commenter noted appreciation for the alternatives provided 
in the Proposed Withdrawal Rule. However, this commenter stated that a 
full withdrawal of the 2020 Rule is necessary due to the legal and 
procedural deficiencies underpinning the 2020 Rule.
    ONRR Response: As shown in the Proposed 2020 Rule, ONRR cited 
authority, including California, 381 F. Supp. 3d at 1168-69, that 
supports the requirement that ONRR must discuss alternatives due to the 
unique factual circumstances of this rule, its attempted repeal of the 
2016 Valuation Rule, and the California decision. See also DHS v. 
Regents of the Univ. of Cal., 140 S. Ct. 1891, 1913-15 (2020) 
(discussing the requirement to consider alternatives). In addition, the 
commenter's statement regarding the status of the California litigation 
is incorrect. California is a final decision, binding on ONRR, because 
no party to that case appealed any of the District Court's decisions, 
including the final merits decision (dated March 29, 2019).

C. Lack of Reasoned Explanation

    The Proposed 2020 Rule did not fully explain why the amendments 
were being proposed. ONRR needed to provide a reasoned explanation for 
repealing most of the substantive provisions adopted in 2016 Valuation 
Rule. The California Court noted a similar flaw in ONRR's 2017 proposal 
to repeal the 2016 Valuation Rule, finding that ONRR did not identify 
the reasons supporting its proposed repeal. 381 F. Supp. 3d at 1173-74 
(``The Court concludes that, by failing to provide the requisite 
information to adequately apprise the public regarding the reasons the 
ONRR was seeking to repeal the Valuation Rule in favor of the former 
regulations it had just replaced, the ONRR effectively precluded 
interested parties from meaningfully commenting on the proposed repeal. 
The Court therefore concludes that Federal Defendants violated the APA 
by failing to comply with the notice and comment requirement.'') 
(citations omitted). Specifically, ONRR's Proposed 2020 Rule lacked the 
full statement of the reasons why ONRR was both proposing to return to 
some of the ``historical practices'' and suggesting other changes that 
were eventually adopted by the 2020 Rule, most of which targeted the 
changes adopted in the 2016 Valuation Rule and 2016 Civil Penalty Rule. 
While the Proposed 2020 Rule identified the proposed changes, discussed 
the anticipated economic impact of the changes, and set forth the 
language of the proposed amendments, ONRR did not fully discuss why it 
was repealing most of the substantive provisions adopted in 2016 
Valuation Rule. Cf. 85 FR 62056-62062 with 86 FR 4617-4640. ONRR needed 
to provide such an explanation in light of the California case, the 
lengthy and complex rulemaking history, and the repeal of most of the 
substantive provisions adopted in 2016 Valuation Rule. Moreover, for 
the changes that were reverting to ``historical practices'' (i.e., 
those existing before the 2016 Valuation Rule was adopted), ONRR did 
not fully explain why it was reverting to practices it had rejected in 
its last substantive rulemaking. Thus, the Proposed 2020 Rule did not 
provide sufficient notice of the reasons for the 2020 Rule. As such, 
the public was deprived of a meaningful opportunity to comment.
    Public Comment: A commenter stated that frequent rule changes 
create confusion and unnecessary cost within the regulated community.
    ONRR Response: While ONRR understands there may be confusion caused 
by the recent change in requirements due to the successive adoption of 
the 2016 Valuation Rule, publication of the 2020 Rule, and now this 
withdrawal, ONRR notes that the 2020 Rule has never gone into effect 
and no company has ever been required to report thereunder. ONRR also 
notes that the 2016 Valuation Rule has been in effect for a relatively 
short period of time. Withdrawing the 2020 Rule will avoid additional 
rule changes until such time as the public has had adequate opportunity 
to review and comment on any proposed amendments and ONRR has 
considered the associated costs of any changes to the regulated 
community.
    Public Comment: Some commenters agreed with ONRR's analysis in the 
Proposed Withdrawal Rule, agreeing that the 2020 Rule lacked 
evidentiary support and a reasoned justification for the rulemaking.
    ONRR Response: ONRR agrees. For the reasons stated in the Proposed 
Withdrawal Rule and herein, the withdrawal of the 2020 Rule is 
appropriate.

D. Inadequate Justification for Change in Recently Adopted Policy

    At the time the Proposed 2020 Rule was published, the 2016 
Valuation Rule was in force only from March 29, 2019,

[[Page 54049]]

when the repeal of the 2016 Valuation Rule was overturned, to October 
1, 2020, and full compliance with the 2016 Valuation Rule was delayed 
by the series of Dear Reporter letters to October 1, 2020. Given that 
the Proposed 2020 Rule was, in many instances, an attempt to return to 
the valuation rules that existed prior to the 2016 Valuation Rule, ONRR 
should have included justifications for the proposed changes in the 
Proposed 2020 Rule to allow for public comment thereon. In addition, 
ONRR should have explained the inconsistencies between the 2016 
Valuation Rule and the amendments described in the Proposed 2020 Rule 
and adequately explained its potential rejection of the position under 
which the agency and the regulated public had been operating for only a 
brief period of time. California, 381 F. Supp. 3d at 1173-74.
    For example, the 2016 Valuation Rule discussed, but rejected, 
extending the index-based valuation option to arm's-length sales of 
gas. 81 FR 43347. The 2020 Rule did not adequately explain its change 
in position to adopt a provision rejected in the 2016 Valuation Rule. 
Similarly, the 2016 Valuation Rule rejected the request to use average 
bidweek prices for the index-based valuation option. Id. When it was 
published, the 2020 Rule took the position that the average bidweek 
price should be used but failed to explain why the change in position 
was warranted after being rejected by the 2016 Valuation Rule. 
Additionally, the 2016 Valuation Rule established that any movement of 
bulk production from the wellhead to a platform offshore is gathering 
and not transportation and effectively rescinded the Deepwater Policy. 
See 81 FR 43340. The 2020 Rule, however, allowed a lessee producing in 
waters deeper than 200 meters to deduct the costs incurred in gathering 
to be deducted as part of its transportation allowance. 86 FR 4613, 
4622-4624. The 2020 Rule did not explain why ONRR was adopting a 
position so recently rejected in the 2016 Valuation Rule.
    Because ONRR failed to explain, in the Proposed 2020 Rule, its 
reasons for changing rules adopted in 2016 and only belatedly did so in 
the 2020 Rule, the 2020 Rule is defective under the APA. See 
California, 381 F. Supp. 3d at 1166-68.

E. The 2020 Rule's Economic Analysis Is Flawed

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

F. Comments Regarding the Support Needed for a Full Withdrawal

    Public Comment: Multiple commenters stated that the Proposed 
Withdrawal Rule does not justify a full withdrawal of the 2020 Rule. 
According to the commenters, the Proposed Withdrawal Rule did not 
provide ONRR's rationale for the withdrawal of the 2020 Rule's revenue-
neutral amendments, such as the default provision, coal valuation, and 
civil penalties amendments. One commenter suggested that ONRR provide 
another opportunity for notice and comment before proceeding with a 
full withdrawal.
    ONRR Response: ONRR has considered the commenters' statements and 
disagrees. Upon careful review, the defects of the 2020 Rule, including 
the lack of adequate comment period (Section II.A), the inadequate 
discussion of alternatives (Section II.B), the lack of reasoned 
explanation (Section II.C), and the inadequate justification for change 
in recently adopted policy (Section II.D) necessitate the withdrawal of 
the rule. As stated above, ONRR has the present intention to open a new 
rulemaking process with respect to some provisions that were adopted in 
the 2020 Rule.

III. Additional Reasons for the Withdrawal of Certain Amendments

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

A. Unwarranted and Overbroad Attempt To Incentivize Production

    ONRR was formed when the Secretary reorganized the former MMS into 
BOEM, BSEE, and ONRR. See S.O. 3299 (Aug. 29, 2011). This 
reorganization was to ``improve the management, oversight, and 
accountability of activities on the [OCS]; ensure a fair return to the 
taxpayer from royalty and revenue collection and disbursement 
activities; and provide independent safety and environmental oversight 
and enforcement of offshore activities.'' Id. at Sec. 1. As part of 
this reorganization, ONRR assumed the royalty and revenue management 
functions of MMS, ``including, but not limited to, royalty and revenue 
collection, distribution, auditing and compliance, investigation and 
enforcement, and asset management for both onshore and offshore 
activities . . . .'' Id. at Sec. 5. Consistent with these 
responsibilities, ONRR promulgated detailed regulations governing 
mineral royalty reporting, valuation, auditing, collection, and 
disbursement. See 30 CFR Chapter XII.
    BLM, BOEM, and BSEE, on the other hand, are primarily responsible 
for mineral leasing functions, such as awarding leases, setting royalty 
rates, and granting royalty relief when appropriate. 86 FR 31201. This 
royalty relief authority originates in the MLA and OCSLA. For onshore 
leases, the MLA authorizes the Secretary to ``reduce the royalty on an 
entire leasehold . . . whenever in his judgment it is necessary to do 
so in order to promote development, or . . . the leases cannot be 
successfully operated under the terms provided therein.'' 30 U.S.C. 
209. For offshore leases, OCSLA authorizes the Secretary to ``reduce or 
eliminate any royalty'' to ``promote increased production on the lease 
area.'' 43 U.S.C. 1337(a)(3). To implement the Secretary's royalty 
relief authority, BLM and BSEE promulgated regulations requiring 
detailed technical and economic information for each lease or lease 
area for which royalty relief is sought. See 30 CFR part 203; 76 FR 
64432, 64435 (Oct. 18, 2011) (for offshore leases, stating that ``BSEE 
is responsible for the regulatory oversight of need-based royalty 
relief awarded after lease issuance and the tracking of all royalty-
free production.''); 43 CFR 3103.4-1(b)(1) (for onshore leases, 
requiring that an operator file a relief application with the 
appropriate BLM office for BLM's consideration).
    ONRR departed from its traditional role in the DOI in seeking to 
incentivize other oil and gas development and production through the 
revenue-impacting amendments. See 86 FR 31200. This was unwarranted 
because BLM, BOEM, and BSEE have primary authority, experience, and 
expertise to determine when royalty relief is needed for individual 
leases or lease areas to promote development or increase

[[Page 54050]]

production. Id. at 31201. These entities review and consider royalty 
relief applications and can grant targeted royalty relief where needed. 
See, e.g., Special Case Royalty Relief, https://www.bsee.gov/what-we-do/conservation/gulf-of-mexico-deepwater-province/special-case-royalty-relief-overview. The 2020 Rule's revenue-impacting amendments, in 
contrast, are overbroad because those amendments apply to all leases, 
including highly profitable leases and lease areas that are being 
produced or will be developed and produced even without the incentives 
contained in the 2020 Rule. Id. This global reduction of royalties on 
profitable oil and gas production for the purpose of incentivizing 
other development and production undermines and conflicts with the 
royalty rate setting and royalty relief functions of BLM, BSEE, and 
BOEM and exceeds ONRR's expertise and area of delegated authorities.
    Although the 2020 Rule cited certain E.O.s and S.O.s as a basis for 
incentivizing production, these E.O.s and S.O.s, before they were 
revoked, expressly required that they be implemented consistent with 
applicable law. See, e.g., E.O. 13783, Sec. 8(b). As discussed above, 
the MLA and OCSLA, and BOEM and BSEE's regulations, authorize targeted 
royalty relief for a lease or lease area. The revenue-impacting 
amendments are inconsistent with this targeted royalty relief because 
these amendments apply to all production, including production in 
highly profitable areas. Further, the E.O.s and S.O.s upon which the 
2020 Rule was premised were revoked prior to the effective date of the 
2020 Rule. See E.O. 13990, Protecting Public Health and the Environment 
and Restoring Science to Tackle the Climate Crisis, Sec. 7 (Jan. 20, 
2021) (revoking E.O.s 13783 and 13795); E.O. 13992, Revocation of 
Certain Executive Orders Concerning Federal Regulation, Sec. 2 (Jan. 
20, 2021) (revoking E.O. 13892); and S.O. 3398, Sec. 4 (Apr. 16, 2021) 
(revoking S.O.s 3350 and 3360). Thus, the global incentivization of 
production exceeded ONRR's delegated authority and should not have been 
cited as a basis for the 2020 Rule. 86 FR 31200.
    Further, regardless of whether ONRR has a role to play in the DOI 
in incentivizing oil and gas production, ONRR still would withdraw the 
amendments because there is insufficient basis to conclude that the 
amendments would maintain or incentivize oil and gas production in the 
United States above levels that would occur in their absence. 86 FR 
31201. Many factors, such as oil and gas prices, national and 
international supply, market forecasts, alternative energy sources, 
credit markets, and competition, play a role in decisions on oil and 
gas development and production. The 2020 Rule fails to cite an economic 
study or contain an economic analysis demonstrating that the amendments 
would incentivize higher levels of oil and gas production from Federal 
lands. Nor does the 2020 Rule demonstrate that the royalties paid on 
any additional oil and gas production will offset the reduction in 
royalties attributable to the deepwater gathering allowance, 
extraordinary processing allowance, and amendments to the index-based 
valuation option contained in the 2020 Rule.
    Public Comment: A commenter stated that ONRR departed from its 
primary accounting and auditing role in seeking to incentivize 
development and production. This commenter pointed to the long-held 
policy that gathering costs are considered costs of placing gas into 
marketable condition. This commenter supports withdrawal of the 
allowance to restore taxpayer protections, uphold valuation standards, 
and prevent the loss of hundreds of millions of dollars in royalty 
revenue over the next decade.
    ONRR Response: ONRR acted outside of its traditional accounting and 
auditing role in seeking to incentivize oil and gas development and 
production.
    Public Comment: A commenter stated that 2020 Rule was premised in 
part on a drop in commodity prices, that commodity prices have since 
recovered, and that commodity prices cannot be a basis for consistent 
Federal policy.
    ONRR Response: In general, it is not advisable for ONRR to amend 
royalty valuation regulations based on temporary fluctuations in 
commodity prices. FOGRMA directs the Secretary to maintain a 
comprehensive inspection, collection, and fiscal and production 
accounting and auditing system that: (1) Accurately determines mineral 
royalties, interest, and other payments owed, (2) collects and accounts 
for such amounts in a timely manner, and (3) disburses the funds 
collected. See 30 U.S.C. 1701 and 1711. ONRR performs these mineral 
revenue management responsibilities for the Secretary. See S.O. 3299. 
Under its delegated authority, ONRR's function is to ensure fair return 
(i.e., fair value) for the taxpayer from royalty and revenue collection 
and disbursement activities. Id. It has no statutory mandate or 
delegated authority to change its valuation regulations to account for 
fluctuations in commodity prices. The valuation regulations already 
account for changes in commodity prices because valuation often is 
based on the prices received for the mineral production, and in 
instances when the price received is lower, the dollar amount of the 
royalty obligation is lower. BLM, BOEM, and BSEE have authority to and 
are better positioned to address temporary drops in commodity prices 
when needed to incentive oil and gas development or production.

B. Deepwater Gathering Allowance

    The 2020 Rule adopted a deepwater gathering allowance for the 
stated purpose of incentivizing deepwater oil and gas development and 
production. See 86 FR 4654. The allowance mirrors the Deepwater Policy 
that was expressly overturned by the 2016 Valuation Rule. ONRR is 
withdrawing the deepwater gathering allowance for the reasons stated in 
Sections II and III.A, and the additional reasons below.
1. Unwarranted Allowance for Bulk Oil and Gas Production Not Treated or 
Measured for Royalty Purposes
    ONRR is withdrawing the deepwater gathering allowance for the 
additional reason that the DOI has long required that oil and gas ``be 
placed into marketable condition at no cost to the Federal lessor'' and 
``gathering has consistently been held to be a part of that process.'' 
See, e.g., Nexen Petroleum U.S.A., Inc. v. Norton, No. 02-3543, 2004 WL 
722435, at *9 (E.D. La. Mar. 31, 2004). Consistent with the marketable 
condition requirement, ONRR's regulations define gathering as 
``movement of lease production to a central accumulation or treatment 
point on the lease, unit, or communitized area, or to a central 
accumulation or treatment point off of the lease, unit, or communitized 
area that BLM or BSEE approves for onshore and offshore leases, 
respectively, including any movement of bulk production from the 
wellhead to a platform offshore.'' 30 CFR 1206.20. ONRR views the 
movement of bulk oil and gas production that has not been separated, 
treated, and measured for royalty purposes as gathering because these 
processes are integral to placing oil and gas into marketable 
condition. See 53 FR 1190-1191, 1193 (Jan. 15, 1988); Devon Energy 
Corp., Acting Asst. Sec. Decision, Valuation Determination for Coalbed 
Methane Production from the Kitty, Spotted Horse, and Rough Draw 
Fields, Powder River Basin, Wyoming, at 2, 18, 21-22, 32-33 (Oct. 9, 
2003) (``Devon Valuation Determination''), aff'd sub nom., Devon Energy 
Corp v. Norton, No. 04-CV-0821 (GK), 2007 WL 2422005 (D.D.C. Aug. 23, 
2007), aff'd

[[Page 54051]]

sub nom., Devon Energy Corp. v. Kempthorne, 551 F.3d 1030 (D.C. Cir. 
2008), cert. denied, 558 U.S. 819 (2009); Nexen, 2004 WL 722435, at *1, 
4-5, 9-12; Marathon Oil Co., MMS-00-0063-OCS (FE), 2005 WL 6733988 
(Oct. 20, 2005); Kerr-McGee Corp., 147 IBLA 277 (1999); CNG Producing 
Co. v. Royalty Valuation & Standards Div., MMS-96-0370-0CS, 1997 WL 
34843496 (Oct. 16, 1997); see also DCOR, LLC, ONRR-17-0074-OCS (FE), 
2019 WL 6127405, at *7-15 (Aug. 26, 2019).
    Public Comment: Some commenters stated that the deepwater gathering 
allowance is needed to incentivize deepwater offshore oil and gas 
production, with one asserting that the deepwater gathering allowance 
should not be withdrawn because it benefits the United States to 
receive royalties and share in the costs of subsea transportation 
rather than forego development altogether. This commenter asserted that 
the development of offshore resources promotes one of ONRR's primary 
functions, i.e., to ensure fair return for the public.
    ONRR Response: These commenters provided no information 
demonstrating that the deepwater gathering allowance would result in 
additional deepwater development or increased production and ONRR has 
no such information in its possession. If appropriate, BSEE could grant 
targeted royalty relief for individual leases and lease areas to 
promote increased development and production when necessary and 
supported by economic analysis.
    Public Comment: While agreeing that gathering is not deductible, 
some commenters opposed withdrawing the deepwater gathering allowance 
because they view all subsea movement of oil and gas to a facility not 
located on a lease or unit adjacent to the lease on which the 
production originates to be transportation even if the production has 
not been separated, treated, or measured for royalty purposes. These 
commenters asserted that ONRR has considered such movement to always be 
transportation since the Deepwater Policy was issued in 1999. 
Consistent with this position, one of these commenters objected to 
referring to the allowance as a ``deepwater gathering allowance'' 
because that commenter considers such movement to always be 
transportation.
    ONRR Response: The commenters' view that subsea movement of bulk 
oil and gas production to a facility off the lease or an adjacent lease 
is always transportation does not comport with ONRR's view that 
gathering is part of placing oil and gas into marketable condition; oil 
and gas that has not been separated, treated, and measured for royalty 
purposes has not been fully gathered and thus is not in marketable 
condition. Moreover, the commenters' position fails to recognize that 
the Deepwater Policy was an exception to the then-existing rules. Thus, 
even the Deepwater Policy acknowledged the movement would traditionally 
be considered gathering but allowed a lessee to claim such movement as 
part of its transportation allowance. Notably, the Deepwater Policy was 
never codified or otherwise made part of ONRR's regulations. It was 
properly set aside by the 2016 Valuation Rule because it was not a 
published rule and because it was inconsistent with published rules. As 
a result, the 2016 Valuation Rule clearly established, consistent with 
the language of the pre-existing regulations, that gathering does not 
end until oil and gas is separated, treated, and measured for royalty 
purposes.
    Public Comment: A commenter supported the deepwater gathering 
allowance and claimed that industry relied on the Deepwater Policy 
between 1999 and 2016 when making financial investments and leasing and 
development decisions. This commenter suggested that retroactively 
eliminating the allowance would present legal vulnerabilities (stating 
that it was unlawful for ONRR to eliminate the deepwater gathering 
allowance considering that a lessee relied on it to make leasing and 
development decisions) and may disincentivize future investment and 
development on the OCS.
    ONRR Response: The United States District Court for the District of 
Wyoming recently upheld ONRR's decision to rescind the deepwater 
gathering policy in litigation filed to challenge the 2016 Valuation 
Rule. See Cloud Peak Energy, Inc. v. Dep't of the Interior, Case No. 
2:19-cv-00120-SWS, Order Upholding In Part And Reversing In Part 2016 
Valuation Rule (D. Wyo. Sept. 8, 2021). Noting that ONRR ``acknowledged 
and considered'' reliance interests, the District Court stated that 
``ONRR considered the relevant information and articulated a rational 
basis based on the relevant information for its decision to vacate the 
Deep Water Policy.'' Id. at 15. The District Court concluded that 
``Petitioners have not established that ONRR acted arbitrarily or 
capriciously, abused its discretion, or exceed[ed] its lawful authority 
by rescinding the Deep Water Policy.'' Id.
    Notably, the referenced reliance comment was general and not 
supported by discussion of specific leases or evidentiary materials. 
The commenter presented no evidence and did not explain how any 
specific investment was, in fact, premised on the future receipt of a 
relatively small allowance for gathering. Such general, 
unsubstantiated, and unquantified reliance interests do not outweigh 
the other interests and policy considerations that support withdrawal 
of the deepwater gathering allowance. 81 FR 43340.
    An agency must comply with the APA to either promulgate new legally 
binding regulations or to substantively amend or modify existing 
regulations. The reasonableness of a lessee's reliance on an informal 
memorandum that directly contradicted the language of properly adopted 
rules is questionable. See, e.g., Glycine & More, Inc., v. United 
States, 880 F.3d 1335 (Fed. Cir. 2018). Even if the Deepwater Policy 
were found to qualify as a legally binding rule, standard OCS lease 
language illustrates that the reasonableness of expecting it to exist 
in perpetuity is also questionable. See Form BOEM-2005, Sec.  1 (Feb. 
2017) (``It is expressly understood that amendments to existing 
statutes and regulations . . . as well as the enactment of new statutes 
and promulgation of new regulations, which do not explicitly conflict 
with an express provision of this lease may be made and that the Lessee 
bears the risk that such may increase or decrease the Lessee's 
obligations under the lease.''). Moreover, to the extent any OCS lease 
contains terms consistent with the Deepwater Policy, those leases will 
continue to control regardless of any conflict with the valuation 
regulations. See 30 CFR 1206.100(d) and 1206.140(c); Form BOEM-2005, 
Sec.  1 (Feb. 2017).
    Public Comment: A commenter supporting the 2020 Rule's deepwater 
gathering allowance asserted that ONRR's elimination of the Deepwater 
Policy in the 2016 Valuation Rule violated both contract law and the 
APA. The commenter pointed to a term in Section 6(c) of the Form BOEM-
2005 (Feb. 2017) OCS lease template. The commenter also cited Kerr-
McGee Corp., 22 IBLA 124 (1975) to suggest that royalties to the 
Federal government should be the same regardless of whether it is paid 
in volume or value.
    ONRR Response: Section 6(c) of the Form BOEM-2005 (Feb. 2017) OCS 
lease template is expressly limited to royalties paid in amount (i.e., 
in kind), not in value: ``When paid in amount, such royalties shall be 
delivered at pipeline connections or in tanks provided by the Lessee. 
Such deliveries

[[Page 54052]]

shall be made at reasonable times and intervals and, at the Lessor's 
option, shall be effected either (i) on or immediately adjacent to the 
leased area, without cost to the Lessor, or (ii) at a more convenient 
point closer to shore or on shore, in which event the Lessee shall be 
entitled to reimbursement for the reasonable cost of transporting the 
royalty production to such delivery point.'' The Secretary phased out 
the DOI's royalty-in-kind program starting in 2009. See 75 FR 15725. 
Moreover, lease terms govern if the lease terms are inconsistent with 
any of the valuation regulations. See 30 CFR 1206.100(d) and 
1206.140(c). Thus, withdrawal of the deepwater gathering allowance 
would have no impact on the referenced lease term in the unique 
situation suggested by the commenter.
    In addition, the commenter's reliance on Kerr-McGee Corp., 22 IBLA 
124 (1975) is misplaced. Kerr-McGee was decided under the historic 
concept of ``field'' gathering and is devoid of any traditional 
contract law analysis. When the concept of ``field'' gathering was 
replaced in 1988 by the adoption of regulations containing a definition 
of gathering, that rulemaking also affected previously existing 
precedents that discussed the concept of ``field'' gathering. 53 FR 
1184, 1193 (Jan. 15, 1988) (rejecting recommendations to ``limit 
gathering to the lease or unit area so a transportation allowance may 
be obtained for all off-lease movement''); 53 FR 1230, 1240 (Jan. 15, 
1988) (same); Devon Valuation Determination, at 18 (explaining how the 
regulatory definitions of gathering may impact precedents applying the 
historic concept of ``field'' gathering). As a result, the line between 
gathering and transportation may not be the same for royalties paid in 
amount and royalties paid in value. Compare Form BOEM-2005, Sec.  6 
(Feb. 2017) and 30 CFR 1206.20, 1206.110, and 1206.152.
    Additionally, the commenter's statement that the elimination of the 
Deepwater Policy violated the APA is not supported by explanation or 
analysis. MMS' royalty and revenue management functions were 
transferred to ONRR in 2010. See 76 FR 64432 (Oct. 18, 2011). At that 
time, ONRR became responsible for MMS' regulations governing gathering 
and transportation. ONRR subsequently determined that the Deepwater 
Policy was inconsistent with the regulatory definitions of gathering 
and Departmental decisions interpreting that term. See 85 FR 62054, 
62059 (Oct. 1, 2020); 80 FR 608, 624 (Jan. 6, 2015). Consequently, it 
rescinded the Deepwater Policy in the 2016 Valuation Rule. See id. This 
final rule affects the 2020 Rule, not any provision of the 2016 
Valuation Rule.
2. Missing Regulatory Text
    While the Proposed 2020 Rule's preamble explained ONRR's intention 
to adopt a deepwater gathering allowance in 30 CFR 1206.110 (oil) and 
1206.152 (gas), consistent with the former Deepwater Policy, key 
components and criteria for a deepwater gathering allowance were 
omitted from the proposed regulation text. For oil, the Proposed 2020 
Rule omitted language later added by the 2020 Rule that expanded the 
proposed allowance from oil produced in waters deeper than 200 meters 
to oil produced from a lease or unit any part of which lies in waters 
deeper than 200 meters. Cf. 85 FR 62080 with 86 FR 4654. The Proposed 
2020 Rule further omitted other key requirements of the Deepwater 
Policy, including that the movement is not to a facility that is 
located on a lease or unit adjacent to the lease or unit on which the 
production originates, that the movement is beyond a central 
accumulation point, defined to include a single well, a subsea 
manifold, the last well in a group of wells connected in a series, or a 
platform extending above the surface of the water, and that the 
gathering costs are only those allocable to the royalty-bearing oil. 
Id. For gas, the Proposed 2020 Rule completely omitted the deepwater 
gathering allowance in the proposed regulation text for Sec.  1206.152. 
See 85 FR 4656.
    Because ONRR made significant, substantive additions to the 
Sec. Sec.  1206.110(a) and 1206.152(a) without reopening the comment 
period, the public had inadequate opportunity to review and comment on 
the substantially revised regulatory text prior to publication of the 
2020 Rule. Accordingly, the adoption of a deepwater gathering allowance 
in the 2020 Rule was defective because ONRR did not give the public 
adequate notice of the intended regulatory language and the scope of 
the allowance.
    Public Comment: A commenter stated that ONRR revealed, in the 
preamble to the Proposed 2020 Rule, an intention to revert back to the 
Deepwater Policy and that any prospective commenter could review the 
Deepwater Policy. This commenter noted that several commenters pointed 
out the error in the text language in response to the Proposed 2020 
Rule, suggesting that interested entities had access to information 
sufficient to formulate meaningful comments.
    ONRR Response: ONRR disagrees. The Deepwater Policy was not adopted 
through any recognized form of rulemaking. The proposed regulation text 
was not included in the Proposed 2020 Rule, despite a general 
discussion appearing in the Proposed 2020 Rule's preamble. Moreover, 
the absence of the regulation text created a high likelihood of 
confusion regarding the precise parameters of the allowance being 
proposed. Moreover, because the meaning of unambiguous regulatory text 
is not changed by conflicting preamble language, some commenters may 
have reviewed and commented on the proposed regulatory text without 
reading the preamble and its general discussion. Because much of the 
intended regulatory text was missing from the Proposed 2020 Rule, 
including key provisions relating to deepwater allowances, the public 
was not provided with adequate notice and an opportunity to comment.
3. Procedural Defects Specific to the Deepwater Gathering Provision
    Prior to adopting the deepwater gathering allowance, ONRR was 
required to offer a rationale for the adoption of the amendment in 
order to allow interested parties a meaningful opportunity to comment. 
See Sections II.C and II.D. As its basis for the deepwater gathering 
allowance, the Proposed 2020 Rule stated that a lessee may be unable 
(without great costs, impaired engineering efficiency, or both) to 
satisfy ONRR's gathering definition before production reaches the 
platform due to unique environmental and operational factors in 
deepwater. 85 FR 62060. While this may be true for some deepwater 
leases, the 2020 Rule does not explain why these unique factors justify 
a deepwater gathering allowance that is applicable to all deepwater 
leases. Many locations, both onshore and offshore, have unique 
environmental and operational factors. The burdens placed on a lessee 
by the environment in which it operates are matters considered at the 
time the lease is issued, and reflected in the amount of bonus bids 
and, in some cases, the royalty rate. See 53 FR 1205 (Jan. 15, 1988). 
Thus, environmental and operational factors alone are inadequate 
justifications for a deepwater gathering allowance.
    The 2020 Rule added new rationale for the deepwater gathering 
allowance. For example, the 2020 Rule stated that the Gulf of Mexico is 
currently viewed as a mature hydrocarbon province; that most of the 
acreage available for leasing has received multiple seismic surveys, 
has been offered for lease a number of times, or is under lease; that 
many of the remaining reserves are located in smaller fields that do 
not warrant stand-

[[Page 54053]]

alone development and are unlikely to be developed absent subsea 
completions with tiebacks to existing platforms; that companies will 
consider not only the oil and gas potential of an area, but also the 
expected costs of development, as compared to alternative investments; 
and that the expected profitability of specific projects will be 
affected by a company's determinations of geologic and economic risk. 
86 FR 4623.
    However, the 2020 Rule cited no economic studies or research 
supporting this new rationale. It also did not explain why these facts, 
if true, justify a deepwater gathering allowance on all deepwater 
leases. Where gathering ends and transportation begins should not, for 
example, depend on whether a hydrocarbon reserve is mature. The 
maturity of a hydrocarbon reserve may be a factor that BLM, BSEE, or 
BOEM takes into consideration in setting royalty rates or granting 
royalty relief, but it is not a factor relevant to the determination as 
to where gathering ends. Finally, regardless of whether this new 
rationale might have been a legitimate basis for the deepwater 
gathering allowance, the public did not have a meaningful opportunity 
to comment on it because it was not stated in the 2020 Proposed Rule.

C. Extraordinary Processing Allowance

    ONRR's valuation regulations allow a lessee to deduct the 
reasonable and actual costs incurred in processing gas. 30 CFR 
1206.159(a)(1). A lessee cannot claim the processing allowance against 
the value of the residue gas. 30 CFR 1206.159(c)(1). Instead, it must 
allocate its processing costs among the other gas plant products, with 
NGLs being a single product. 30 CFR 1206.159(b). Additionally, the 
allowance cannot exceed 66\2/3\ percent of the value of the gas plant 
product against which the allowance is taken. 30 CFR 1206.159(c)(2).
    Prior to the 2016 Valuation Rule, ONRR could, upon request of a 
lessee, authorize a lessee to exceed the 66\2/3\ percent cap. 53 FR 
1281. Upon request of a lessee, ONRR could also authorize a lessee to 
claim an allowance for extraordinary processing costs actually 
incurred. Id. To qualify for an extraordinary processing allowance, a 
lessee's request had to demonstrate that the costs were, by reference 
to standard industry conditions and practice, extraordinary, unusual, 
or unconventional. Id.
    The 2016 Valuation Rule eliminated ONRR's authority to allow a 
lessee to exceed the 66\2/3\ percent cap and to take an extraordinary 
processing allowance. 81 FR 43353. The 2016 Valuation Rule also 
terminated any extraordinary processing allowances that ONRR previously 
approved. Id. At the time, there were two extraordinary processing 
allowances approved by ONRR for gas processed at two facilities in 
Wyoming. Id.
    The 2020 Rule reinstated a lessee's ability to request to claim an 
extraordinary processing allowance but not its ability to request to 
exceed the 66\2/3\ percent cap. 86 FR 4625-4626. The reinstatement of 
extraordinary processing allowances was justified as a way for ONRR to 
incentivize production or remove a disincentive to production having 
such costs. Id.
    ONRR is withdrawing the extraordinary processing allowance 
amendment for the reasons stated in Sections II and III.A., and for the 
additional reasons below.
1. Unwarranted, Overbroad, and Unsupported Incentivization of 
Production
    As discussed in Section III.A, ONRR's attempt to incentivize 
production through the adoption of the 2020 Rule, including through its 
reinstatement of a lessee's ability to apply for and receive an 
extraordinary processing allowance, is unwarranted. ONRR notes that no 
supporter of the 2020 Rule submitted a report or study demonstrating 
that the reinstatement of the extraordinary processing allowance would 
increase development or production. Moreover, this amendment is 
overbroad because it could potentially apply in areas where production 
is already profitable. Other DOI bureaus have programs in place to 
incentivize development or production where necessary. See Section 
III.A and 86 FR 31201-31202.
    Public Comment: Some commenters asserted that the extraordinary 
processing allowance encourages continued and future production of 
unique hydrocarbon streams and the production of gas in atypical areas. 
Commenters also suggested that a few lessees may have relied on the 
historical extraordinary processing allowance approvals relating to the 
two processing facilities in Wyoming, and made investment decisions 
based on those then-existing approvals. These commenters opined that, 
absent the extraordinary processing allowances, the viability of lease 
operations associated with the two Wyoming facilities is questionable. 
Finally, some commenters stated that the extraordinary processing 
allowances are necessary to maximize hydrocarbon recovery, prevent 
waste due to premature lease abandonment, and provide a mechanism to 
reduce royalty payments when costs exceed profits.
    ONRR Response: Although commenters assert that extraordinary 
processing allowances are needed to incentivize future production and 
ensure the viability of certain lease operations, no commenter provided 
support to show that, without the extraordinary processing allowances, 
a lessee would curtail production, or that ONRR's reinstatement of 
extraordinary processing allowances would increase gas production, 
including from leases serviced at the two Wyoming facilities. Notably, 
the preamble to the 2020 Rule recognized that the production impact of 
the rule's amendments, including the extraordinary processing 
amendment, is ``negligible or marginal.'' 86 FR 4616. Further, the 
historical rarity of submissions and approvals of applications for 
extraordinary processing allowances suggests that extraordinary 
processing allowances do not incentivize production to the degree 
commenters assert. In the almost 30 years an extraordinary processing 
allowance could have been sought, fewer than ten applications were 
submitted and only two were approved, neither of which was approved 
after 1996. To the extent that potential waste, premature lease 
abandonment, or production profitability are legitimate concerns, other 
bureaus within the DOI may have programs designed to address those 
issues.
    Public Comment: A commenter asserted that the extraordinary 
processing allowance is needed to increase helium production because 
helium is critical for national security.
    ONRR Response: ONRR's gas valuation regulations do not apply to 
helium. See Exxon Corp., 118 IBLA 221, 229 n.9 (1991) (noting that MMS 
does not consider helium in valuing a gas stream for royalty purposes 
because ``it is not a leasable mineral''). Rather, helium production 
from Federal lands is administered by BLM and governed by the Helium 
Stewardship Act of 2013, codified at 50 U.S.C. 167-167q, and BLM 
regulations, 43 CFR part 16. See also https://www.blm.gov/programs/energy-and-minerals/helium/division-of-helium-resources (noting that 
BLM's Division of Helium Resources ``adjudicates, collects, and audits 
monies for helium extracted from Federal lands''). Thus, any 
responsibility to incentivize helium production lies with BLM, not 
ONRR.
    The 2020 Rule stated that ``allowing a lessee to apply for an 
extraordinary processing allowance approval for the natural gas portion 
of [its] production stream, may lower natural gas

[[Page 54054]]

production costs and incentivize new or continued production of 
helium.'' 86 FR 4628. But as noted in Section III.A above, ONRR lacks 
evidence to substantiate that an extraordinary processing allowance 
will incentivize gas production, and more particular to this 
discussion, lacks evidence that an extraordinary processing allowance 
is likely to boost helium production. Moreover, of the two prior 
extraordinary processing allowances that ONRR approved, only one 
impacted a helium-bearing gas stream. Likewise, none of the public 
comments contain any support for the proposition that reinstating the 
extraordinary processing allowance will result in additional helium 
production from this stream. Thus, even if the United States has 
``important economic and national security interests in ensuring the 
continuation of a reliable supply of helium''--as noted in the 2020 
Rule and referenced in the public comment--the extraordinary processing 
allowance has not been shown to be an effective means to increase 
helium production. Id.
    Finally, DOI recently implemented other statutory shifts that 
encourage investment in helium production, but which were not mentioned 
in the 2020 Rule or by the commenter. The Dingell Act, Public Law 116-
9, Section 1109, ``Maintenance of Federal Mineral Leases Based on 
Extraction of Helium,'' amended the MLA on March 12, 2019, to allow the 
production of helium to maintain a Federal oil and gas lease beyond its 
primary term. See 30 U.S.C. 181 (``extraction of helium from gas 
produced from such lands shall maintain the lease as if the extracted 
helium were oil and gas''). Prior to this amendment, the initial ten-
year lease term could only be extended if oil or gas, not helium, was 
produced in paying quantities. A consequence of the prior MLA framework 
was that revenue from the sale of helium was not factored into whether 
a well was producing in ``paying quantities'' and thus qualified for an 
extension of the initial lease term beyond ten years. The shift away 
from considering only the production of oil and natural gas as holding 
the lease seems likely to encourage investment in helium production. 
The targeted amendment to the MLA negates any contention that the 
modest relief potentially available through an extraordinary processing 
allowance is effective to encourage helium production.
2. ONRR's Authority To Modify Processing Allowance Regulations
    Public Comment: A commenter suggested that withdrawing ONRR's 
authority to permit extraordinary processing allowances would 
improperly inflate royalties due because a lessee cannot deduct its 
reasonable, actual gas processing costs as allowed under the gas 
valuation rules. The commenter further noted that the Proposed 
Withdrawal Rule does not question whether the previously approved 
extraordinary processing allowances comprised reasonable, actual 
processing costs for qualifying operations.
    ONRR Response: ONRR agrees that the gas valuation rules permit a 
lessee to deduct most reasonable and actual gas processing costs. 30 
CFR 1206.159(a)(1). But gas processing allowances have never been 
without limits. Rather, the mineral leasing statutes recognize ONRR's 
authority to create and subsequently modify regulations, including 
those related to processing allowances. See, e.g., 30 U.S.C. 189 
(authorizing the Secretary, under the MLA, to ``prescribe necessary and 
proper rules and regulations and to do any and all things necessary to 
carry out and accomplish the purposes of this chapter''); 43 U.S.C. 
1334(a) (authorizing the Secretary to ``prescribe such rules and 
regulations as may be necessary to carry out'' the provisions of 
OCSLA); 30 U.S.C. 1751(a) (authorizing the Secretary, under FOGRMA, to 
``prescribe such rules and regulations as he deems reasonably necessary 
to carry out this chapter'').
    The MLA, OCSLA, and FOGRMA do not define ``royalty value.'' None of 
those statutes mention processing costs, let alone mandate adoption of 
regulations allowing a deduction for processing costs. Instead, the 
agency-developed regulations at 30 CFR part 1206 to authorize 
processing allowances. The agency established the deductions by 
regulation and is authorized to change the regulations, as it did here. 
In Cloud Peak Energy Inc. v. U.S. Dep't of the Interior, 415 F. Supp. 
3d 1034, 1046 (D. Wyo. 2019), the United States District Court for the 
District of Wyoming commented on the ``wide latitude of discretion'' 
ONRR has to enact ``rules and regulations enabling [the DOI] to 
complete the tasks it [is] assigned.'' This discretion would 
necessarily include the ability to change allowances adopted by 
regulation. Id. at 17, 24, 29; see also Am. Trucking Ass'ns v. 
Atchison, Topeka, & Santa Fe Ry. Co., 387 U.S. 397, 416 (1967) (stating 
that ``[r]egulatory agencies do not establish rules of conduct to last 
forever''); FCC v. Fox Television Stations, 556 U.S. 502, 515 (2009) 
(recognizing agency authority to change regulatory course).
    Public Comment: A commenter asserted that the extraordinary 
processing allowance prevented receipt of fair market value for 
minerals extracted from Federal land and should be withdrawn.
    ONRR Response: ONRR is withdrawing the extraordinary processing 
allowance for the reasons discussed herein, consistent with the 
comment.
3. Additional Administrative Burden and Reduced Royalties
    The 2020 Rule states that ``ONRR anticipates . . . it will again 
receive very few requests and will rarely grant approval under this 
provision, as was the case when the language was in place between March 
1, 1988, and December 31, 2016.'' 86 FR 4628. Consistent with this, a 
commenter asserts that ONRR will not be impacted if it reinstates its 
authority to approve extraordinary processing allowances because ONRR 
maintains control of the approval process and is not required to grant 
all requests. Notably, however, when ONRR drafted the 2020 Rule, no 
consideration was given to the potential interplay between the 
reinstatement of ONRR's authority to permit extraordinary processing 
allowances and the retention of the hard cap on processing allowances, 
which could impact the number of extraordinary processing allowance 
applications submitted.
    Prior to the adoption of the 2016 Valuation Rule, a lessee could 
apply, under specified circumstances, for an extraordinary processing 
allowance and to exceed the soft cap of 66\2/3\ percent on processing 
allowances. The 2016 Valuation Rule eliminated extraordinary processing 
allowances and changed the soft cap to a hard cap (i.e., a firm limit 
on the processing allowance cap). See 30 CFR 1206.159(c)(2). The 
Proposed 2020 Rule proposed to reinstate both the extraordinary 
processing allowance and soft caps. 85 FR 62058.
    Between the publication of the Proposed 2020 Rule and the 
publication of the 2020 Rule, ONRR performed a new economic analysis. 
Based thereon, the 2020 Rule reinstated ONRR's authority to permit 
extraordinary processing allowances but did not restore a lessee's 
ability to seek to exceed the cap on processing allowances. 86 FR 4625. 
Thus, under the 2020 Rule, an extraordinary processing allowance 
application is the only mechanism by which a lessee can request to 
exceed limits on processing allowances, a circumstance that might cause 
ONRR to receive more applications for approval of an

[[Page 54055]]

extraordinary processing allowance than it did historically. ONRR did 
not consider this possibility or the effect on royalty payments that 
might result if additional extraordinary processing allowance requests 
are submitted and approved.
    Public Comment: Some commenters stated that ONRR will not be 
impacted if it reinstates its authority to approve extraordinary 
processing allowances because ONRR maintains control of the approval 
process and is not required to grant all requests.
    ONRR Response: While the comments regarding the broad discretion of 
the approval process are generally valid, the comments are not 
sufficiently specific for ONRR to act on. Moreover, reinstatement of 
ONRR's authority to permit extraordinary processing allowances may 
create the unintended and unanticipated consequences discussed above. 
ONRR must analyze those circumstances before it could permit the 
extraordinary processing allowance to go into effect.
4. Procedural Defects Specific to the Extraordinary Processing 
Allowances
    The Proposed 2020 Rule failed to provide a reasoned explanation, or 
adequate justification for the change, as required under the APA to 
provide sufficient notice to the public of the reasons for the 
reinstatement of the extraordinary processing allowance. See Sections 
II.C and II.D.
    First, ONRR published the Proposed 2020 Rule on October 1, 2020. At 
that time, the 2016 Valuation Rule was reinstated for only eighteen 
months, but lessees had not yet been required to comply with the rule. 
Thus, ONRR had, at most, a limited opportunity to assess the impact of 
the withdrawal of its authority to permit extraordinary processing 
allowances.
    Second, in the Proposed 2020 Rule, the amendment was premised on 
the notion of incentivizing production. See 85 FR 62058. However, the 
2020 Rule contained inconsistent positions on incentivization. In 
response to public comments, the 2020 Rule stated that it was ``not 
premised on increasing production of oil, gas or coal by some measured 
amount'' and instead was ``meant to incentivize both the conservation 
of natural resources . . . and domestic energy production over foreign 
energy production.'' 86 FR 4616. The 2020 Rule also stated that the 
anticipated impact of the rule's amendments on production would be 
``negligible.'' 86 FR 4626. The 2020 Rule similarly stated that, in 
most cases, allowing a lessee to exceed the processing allowance cap 
would not be sufficient to incentivize production. See 86 FR 4626-4629 
(noting a lessee's greater royalty share of production negates any 
incentive to continue producing from a Federal lease under suboptimal 
circumstances). Further, neither the Proposed 2020 Rule nor the 2020 
Rule explained the purported connection between the extraordinary 
processing allowance and increased production.
    Finally, the public was not provided a meaningful opportunity to 
comment on the rationale that ultimately formed the basis for the 
reinstatement of the extraordinary processing allowance because it was 
not set forth in the Proposed 2020 Rule. Apart from an unpersuasive 
argument about incentivizing production, ONRR relied entirely on 
reasons submitted in response to the Proposed 2020 Rule to support its 
reinstatement of the extraordinary processing allowance. See 86 FR 
31204 (identifying five additional justifications in the 2020 Rule for 
reinstatement of the extraordinary processing allowance, each of which 
was based on comments submitted in response to the Proposed 2020 Rule). 
Therefore, the public did not have an opportunity to comment on most of 
the reasons contained in the 2020 Rule to justify the reinstatement of 
the extraordinary processing allowance.

D. Index Prices

1. Unwarranted Change From Highest Bidweek Price to Average Bidweek 
Price
    For the first time, the 2016 Valuation Rule allowed a lessee to 
calculate the royalty value of its production by using an index-based 
valuation formula for its non-arm's-length sales of Federal gas, 
instead of actual sales prices, transportation costs, and processing 
costs. 30 CFR 1206.141(c) and 1206.142(d). This index-based valuation 
method is required if there is an index pricing point and the lessee 
has no written contract for the sale of the gas or there is no sale of 
the gas, which is the case for approximately 0.3 percent of all Federal 
gas. 30 CFR 1206.141(e) and 1206.142(f). The index-based valuation 
formula is otherwise optional. 30 CFR 1206.141(c) and 1206.142(d).
    Under the 2016 Valuation Rule, a lessee electing to use the index-
based valuation formula must report and pay royalties based on the 
highest bidweek price for the index pricing points to which the gas 
could flow, reduced by an amount intended to account for average 
transportation costs. 30 CFR 1206.141(c)(1) and 1206.142(d)(1). The 
2016 Valuation Rule considered and rejected comments that using the 
highest bidweek price results in an inflated value for royalty 
purposes, which is neither reasonable nor justified. 81 FR 43347. ONRR 
disagreed with those comments, stating that the ``provision protects 
the interests of the Federal lessor, while also simplifying the royalty 
reporting process for industry.'' Id.
    The 2020 Rule amended the index-based valuation formula by 
substituting the average bidweek price for the highest bidweek price. 
86 FR 4619. The 2020 Rule posited that ``[w]hile the bidweek average 
price is lower than the bidweek high price, the bidweek average more 
closely reflects the gross proceeds that a lessee would typically 
receive in an arm's-length transaction, and therefore is more likely to 
actually be used by lessees.'' 86 FR 4619-4620. Using an average, 
however, means that there are transactions where a lessee receives a 
higher price. And because index-based pricing is optional for all but 
0.3 percent of Federal gas, a lessee who generally receives more than 
the average bidweek price could choose to report and pay based on the 
average bidweek price in order to reduce its royalty obligations, as 
could a lessee with lower than average transportation costs.
    Conversely, a lessee who generally receives less than the average 
bidweek price or pays higher than average transportation costs could 
continue to report and pay royalties based on its actual sales and 
transaction data specific to the gas at issue rather than the index-
based valuation formula. Thus, a lessee could avoid higher royalties by 
not using the index-based valuation option. 30 CFR 1206.141(c), 
1206.142(d). In other words, a lessee would have an increased 
opportunity to pay royalties on the lower of two values. As a result, 
changing the formula to reduce the bidweek price used from highest to 
average is expected to reduce total Federal gas royalties due the 
United States by $5,062,000 per year, as detailed in the Economic 
Analysis, below.
    In adopting the 2020 Rule, ONRR was required to explain why it was 
rejecting the position it adopted in the 2016 Valuation Rule that the 
use of the highest bidweek price is necessary to protect the interests 
of the Federal lessor. See California, 381 F. Supp. 3d at 1173-74. Use 
of the highest bidweek price helps ensure that the United States 
receives a fair market value, while allowing a lessee the option of a 
formula if the lessee is motivated to save on administrative costs 
incident to reporting, payment, and potential audit of actual sales 
prices, transportation

[[Page 54056]]

costs, and processing costs, as well as the cost of any ensuing 
disputes. For the reasons described in Section II, which discusses 
various defects in the promulgation of the 2020 Rule, and III.A, which 
describes ONRR's unwarranted and overbroad attempt to incentivize 
production, and because the 2020 Rule did not adequately explain why it 
was shifting to average index prices, ONRR withdraws this provision of 
the 2020 Rule.
    Similarly, the use of the highest bidweek price is consistent with 
frequently-seen royalty schemes--the lessee is required to pay the 
lessor on the higher or highest of multiple measures of royalty value 
to protect against valuation measures that may prove inapplicable or 
otherwise fail in some instances, and to minimize the impact of any 
self-dealing or exercise of poor business judgment. See, e.g., Federal 
and Indian lease and regulation provisions requiring payment based on 
(a) a major portion price if higher (see 30 CFR 1206.54 and 
1206.174(a)(4) and 47 FR 47774 (Oct. 27, 1982)), (b) the value of gas 
as unprocessed gas if higher than the value of gas as processed gas (30 
CFR 1206.176 and 52 FR 1257 (Jan. 15, 1988)), and (c) no less than 
gross proceeds (30 CFR 1206.174(g) and 53 FR 1275 (Jan. 15, 1988)); see 
also, Competitive Oil and Gas Lease, State of Alaska, Department of 
Natural Resources, Sec. 36(a), https://dog.dnr.alaska.gov/Documents/Leasing/SaleDocuments/AKPeninsula/2016/LeaseForm-DOG201503.pdf, which 
requires royalty payments based on the highest of four measures of 
value; and Oil and Gas Lease, State of Wyoming, Sec. 1(d)(iv), https://lands.wyo.gov/trust-land-management/mineral-leasing/oil-gas-leases, 
which requires payment based a value no less than that received by the 
United States for its royalties in the same field.
    Public Comment: Some commenters stated that by requiring the 
highest bidweek price, ONRR is extracting royalties above what it may 
be entitled to receive because the average bidweek price is more 
representative of the gross proceeds that a typical lessee may receive.
    ONRR Response: With very minor exceptions, no lessee is required, 
but rather elects, to use the index-based valuation option for its non-
arm's-length gas sales. 30 CFR 1206.141(c) and 1206.142(d). A lessee 
that concludes that its use of the index-based valuation formula would 
increase its royalty obligation above what it considers due the United 
States does not have to use the formula. Moreover, neither the 
governing statutes nor lease terms cap royalty value at an individual 
lessee's gross proceeds or typical or average gross proceeds. Also, as 
referenced above, lessors frequently require that royalties be paid on 
the highest of multiple measures of royalty value, including measures 
that may exceed a lessee's average gross proceeds.
    Public Comment: Some commenters opposed the withdrawal of the 2020 
Rule, alleging it creates inconsistency between valuation of Federal 
gas, Federal oil, and Federal NGLs. Another commenter stated it creates 
an inconsistency with Indian gas valuation.
    ONRR Response: No statute or lease term requires identical 
treatment for Federal oil, Federal NGLs, Federal gas, and Indian gas, 
and there are many instances where those commodities are treated 
differently. Cf. 30 CFR 1206.153(b)(1) (allowing a transportation 
allowance for Federal gas for the unused portion of an arm's-length 
contract's firm demand fee) with 30 CFR 1206.178 (allowing only the 
used portion of that fee for Indian gas).
    Furthermore, with respect to the difference between Federal residue 
gas and NGLs, index-based valuation is, in most instances, an optional 
reporting methodology. See 30 CFR 1206.141(c) and 1206.142(d). In 
designing an optional reporting methodology, ONRR strives to find a 
path that ensures it receives a fair return. As a result, ONRR 
determined in the 2016 Valuation Rule that a lessee who elects to use 
the index-based valuation option must apply the highest bidweek price 
to value its residue gas. 81 FR 43347. On the other hand, because it is 
optional for all but a small number of lessees, most lessees can eschew 
the option and, instead, use actual sales prices, transportation costs, 
and processing costs.
    Public Comment: Some commenters wrote that using the highest 
bidweek price instead of the average bidweek price will reduce the 
number of lessees that elect to use index-based pricing.
    ONRR Response: ONRR is under no statutory obligation to offer an 
index-based pricing option. If, as reporting under the index-based 
valuation option in 2016 continues, lessees' reporting shows no or 
insignificant use of index-based reporting, ONRR will have data upon 
which to evaluate the further use of index-based reporting, including 
the possible need to amend the price. However, at this time, ONRR 
believes use of the highest bid-week price is necessary to ensure that 
the Federal lessor receives fair market value for its mineral 
resources.
2. Defective Reduction to Index To Account for Transportation
    The 2016 Valuation Rule's index-based valuation method provided for 
a reduction to index prices to account for transportation costs. The 
amount of the reduction was calculated by ONRR based on ONRR's review 
and analysis of lessee-reported transportation costs for production 
years 2007-2010. For those years, the average reported transportation 
cost for the Gulf of Mexico was 4.6 percent of index value, and for all 
other areas, it was 8.6 percent of index value. In the 2016 Valuation 
Rule, the index-based valuation formula included a 5 percent reduction 
to index for the Gulf of Mexico and a 10 percent reduction for all 
other areas. 30 CFR 1206.141(c)(1)(iv) and 1206.142(d)(1)(iv).
    Since the promulgation of the 2016 Valuation Rule, ONRR conducted a 
similar economic analysis for three other time periods. One of those 
time periods predated the Proposed 2020 Rule and ONRR's drafting of the 
final 2020 Rule. That period was used as a basis for the 2020 Rule. For 
production years 2014-2018, ONRR's analysis showed average lessee-
reported transportation costs of 13.7 percent for the Gulf of Mexico 
and 16.8 percent for all other areas. Based on this information, the 
2020 Rule increased the reductions to index from 5 percent to 10 
percent for the Gulf of Mexico and from 10 percent to 15 percent for 
all other areas, again bounded by certain minimum and maximum amounts. 
86 FR 4655.
    Since publication of the 2020 Rule, ONRR conducted two additional 
analyses--one of production years 2016-2020 and the second for 
production years 2007-2020. These analyses showed average lessee-
reported transportation costs of 19.6 percent and 14 percent for the 
Gulf of Mexico and 16.6 percent and 16.9 percent for all other areas, 
respectively.
    In ONRR's experience, lessee-reported transportation costs may 
overstate allowable transportation costs for several reasons. First, 
costs reported at or soon after the time of production are estimates, 
and while, under 30 CFR 1210.30, a lessee must amend its reported 
royalties within 30 days of the discovery of an error, a lessee 
generally has up to six years after its initial royalty reporting is 
due to amend its reported costs. 30 U.S.C. 1721a(a). As a result, 
reported costs for recent time periods can be unreliable.
    Second, a lessee frequently claims transportation costs in excess 
of the amounts allowed. Too often, a lessee

[[Page 54057]]

fails to reduce the charges of an affiliated or third-party pipeline 
service provider to eliminate non-allowable costs such as gathering 
costs and other expenses of placing gas in marketable condition. While 
ONRR audits a lessee's reports to determine if excessive transportation 
allowances have been claimed, ONRR has seven years within which to do 
so. 30 U.S.C. 1724(b)(1). Thus, reported costs for recent time periods 
are potentially unreliable.
    Finally, ONRR does not have sufficient resources to audit or 
conduct other compliance activities on every reported transportation 
allowance. As a result, some overstated allowances will be missed. For 
all these reasons, reported--and particularly recently-reported--
transportation costs may be higher than the reduction to index ONRR 
authorizes to account for transportation in any index-based valuation 
method.
    Further, for the reasons discussed above in evaluating whether to 
use high or average bidweek prices, ONRR should err, if at all, by 
allowing lower rather than higher reductions to index prices to account 
for the lessee's transportation costs in any index-based valuation 
option.
    ONRR is withdrawing the 2020 Rule for the reasons set forth in 
Section II. Nonetheless, the over-time increase in reported 
transportation costs relative to index is notable. Absent the other 
flaws in the 2020 Rule discussed in Sections II and III.A of this final 
rule, ONRR might conclude in a future rulemaking following notice and 
comment that it is appropriate to increase the reduction to index to 
account for transportation in much the same way as it did in the 2020 
Rule. But any such action will take place in a separate rulemaking 
action, and this provision of the 2020 Rule is withdrawn at this time 
due to the deficiencies of the 2020 Rule.
3. Unwarranted Expansion of Index-Based Valuation Option to Arm's-
Length Gas Sales
    The 2016 Valuation Rule introduced the index-based valuation option 
for Federal gas disposed of in non-arm's-length transactions, which 
most often take the form of sales by a lessee to its affiliate. 30 CFR 
1206.141(c) and 1206.142(d). The 2016 Valuation Rule considered and 
rejected comments strongly urging that the index-based valuation option 
also be available for arm's-length transactions, stating that ``[g]ross 
proceeds under valid arm's-length transactions are the best measure of 
value.'' 81 FR 43347.
    The 2020 Rule expanded the index-based valuation option to Federal 
gas sold at arm's-length. 86 FR 4613. For the reasons described in 
Sections II and III.A, and the additional reasons set forth below, ONRR 
is withdrawing its expansion of the index-based valuation option to 
arm's-length sales, subject to the possibility of revisiting the topic 
in future rulemaking.
    ONRR generally considers a lessee's arm's-length sale of gas to be 
the best indicator of value. 86 FR 4618. This position was reiterated 
in the 2020 Rule. Id. This indicator of value, however, is not always 
available when a lessee sells gas to its affiliate or otherwise 
disposes of gas in non-arm's-length transactions. Index prices can be a 
more reliable indicator of value than affiliate and other non-arm's-
length sales prices because they are based on reported arm's-length 
sales. But an index-based valuation formula generally is not as 
reliable a measure of royalty value as is the use of actual sales 
prices, transportation costs, and processing costs obtained or incurred 
in arm's-length transactions. This is because, at a minimum, the 
implicit transportation deduction included in the index-based valuation 
formula is based on an average of all reported transportation costs for 
either the Gulf of Mexico or all other areas of the nation, and 
therefore is most often higher or lower than the transportation costs 
actually incurred for the gas being valued.
    The 2016 Valuation Rule recognized this, reasoning that index 
prices are published prices derived from reported arm's-length 
transactions. ONRR considered the index-based valuation formula 
included in the 2016 Valuation Rule a simpler, acceptable, and 
potentially preferrable method to value gas disposed of in non-arm's-
length (or affiliate) transactions. 81 FR 43338, 43346-43348. In short, 
under the 2016 Valuation Rule, the index-based valuation option allowed 
a lessee to, in effect, use a compilation of arm's-length transaction 
data to value gas not sold at arm's-length.
    ONRR should have offered justification for why the 2020 Rule was 
adopting a provision expressly rejected by the 2016 Valuation Rule-
declining to extend index-based valuation to arm's-length transactions-
but it did not. See Section II.D. Using an index-based valuation 
formula to value arm's-length sales of Federal gas is problematic. For 
arm's-length transactions, the generally best indicator of value is 
typically available, and it is based on actual arm's-length transaction 
data specific to the gas at issue. 30 CFR 1206.141(b) and 1206.142(c). 
Nonetheless, the 2020 Rule extended the index-based option to gas sold 
at arm's-length. 86 FR 4618. The decision to do so was unsupported and 
premature, though ONRR may reexamine the issue in the future, after it 
has sufficient time to review, audit, and compare royalties received 
for index-based valuation of Federal gas sold at non-arm's-length and 
actual transaction data for Federal gas sold at arm's-length received 
after the reinstatement of the 2016 Valuation Rule. At this time, ONRR 
cannot determine whether the index-based valuation option adequately 
protects Federal and State royalty interests in Federal gas sold at 
arm's-length. Therefore, ONRR withdraws this portion of the 2020 Rule.
    Public Comment: A few commenters, including multiple States, 
supported the withdrawal of the extension of the index-based option, 
asserting that ONRR should gain experience in administering an index-
option for non-arm's-length sales before expanding index-based 
reporting into other areas. Similarly, commenters also stated but did 
not explain that extension of the index-based option is premature in 
light of pending Federal court litigation in Cloud Peak Energy Inc. v. 
U.S. Dep't of the Interior, No. 19-cv-120-SWS (D. Wyo.).
    ONRR Response: ONRR agrees that the extension of the index-based 
option to arm's-length gas sales is premature at this time.
    Public Comment: One commenter supported the withdrawal of this 
provision of the 2020 Rule because index prices and the index-based 
valuation option are not sufficiently transparent to the public.
    ONRR Response: ONRR is withdrawing this provision of the 2020 Rule 
for reasons discussed in this final rule. ONRR monitors published index 
points to verify they meet specific liquidity requirements defined on 
onrr.gov. Additionally, index price publication companies have many 
checks in place to ensure the prices reported are transparent and 
representative of the market. They analyze transactions reported to the 
publication and validate any prices outside of a predetermined 
threshold. They also monitor and publish the number of reported trades 
and the total volumes associated with those trades.
    Public Comment: Some commenters asserted that withdrawal of this 
portion of the 2020 Rule will increase administrative burdens; require 
lessees to maintain cross-departmental unbundling teams to analyze and 
continuously update unbundling cost methodologies; require lessees to 
obtain proprietary information from processors or make their best guess 
when the data

[[Page 54058]]

is not provided; and increase the number of unbundling-related 
compliance reviews and audits, as well as the administrative and legal 
costs to respond to such compliance reviews and audits.
    ONRR Response: ONRR acknowledges that a lessee would realize an 
administrative cost savings if the index-based valuation option were 
available for arm's-length sales. In the Economic Analysis below, ONRR 
has estimated the administrative cost savings to lessees to be 
$1,077,000 per year. Further, ONRR has estimated that the 2020 Rule's 
extension of the option to arm's-length sales would reduce lessees' 
royalty payments by $7,460,000 per year otherwise due the United States 
($6,800,000 for gas plus $660,000 for natural gas liquids (``NGLs'')). 
A lessee's cost savings, as outlined in the Economic Analysis, also 
does not change the fact that actual arm's-length sales, 
transportation, and processing data specific to the gas being valued 
are most often better measures of its value than a formula derived from 
reported data relating to indices compiled from data relevant to other 
arm's-length transactions.
    Among the obligations that Congress placed on the Secretary is the 
responsibility to audit lessee's royalties and reporting. 30 U.S.C. 
1711(c). A lessee, operator, or other person directly involved in 
developing, producing, transporting, purchasing, or selling oil or gas 
must establish and maintain any records that the Secretary may require. 
30 U.S.C. 1713(a) and 30 CFR 1212.50-1212.52. ONRR and its predecessor 
agencies, as the Secretary's designees, have historically performed 
audits based on the records the commenters find burdensome to maintain 
or acquire and produce. Further, ONRR's methods have been upheld by 
Federal Courts. Devon Energy Corp. v. Kempthorne, 551 F.3d 1030 (D.C. 
Cir. 2008), aff'g Devon Valuation Determination; Amoco Prod. Co. v. 
Watson, 410 F.3d 722 (D.C. Cir. 2005), aff'd sub nom. BP Am. Prod. Co. 
v. Burton, 549 U.S. 84 (2006); Burlington Res. Oil & Gas Co., 183 IBLA 
333 (Apr. 23, 2013), aff'd 2014 WL 3721210 (N.D. Okla. July 24, 2014). 
When a lessee produces Federal oil and gas, it is foreseeable that it 
may be subject to ONRR compliance activities, including audit, and will 
incur associated administrative costs.
    The commenters also ignore the fact that Federal oil and gas 
lessees have long been subject to the marketable condition rule, which 
is the source of the obligation to unbundle. Lessees are aware of the 
information and accounting that is required to comply with the 
marketable condition rule. Federal oil and gas lessees have long been 
required to calculate their gross proceeds, deduct transportation costs 
and processing costs, and segregate out (or unbundle) any marketable 
condition expenses if they seek to report the lowest allowable royalty 
value for gas. Further, in addition to entering into Federal oil and 
gas leases, lessees voluntarily enter into contracts with third-party 
and affiliate buyers, transporters, and processors. Nothing prevents 
each lessee from requiring its counterpart, by contract or otherwise, 
to provide the information necessary to accurately report royalty 
value, including the costs justifying the lessee's allowances. The 
Federal Government and its State beneficiaries are not obligated to 
save lessees the administrative costs of doing so.
    Finally, even assuming arguendo that E.O.s 13783 and 13795 and 
S.O.s 3350 and 3360 policy objectives can still be relied upon, the 
2020 Rule did not sufficiently support how the index-based option 
promotes its stated objective. The 2020 Rule states that it ``[wa]s not 
premised on increasing the production of oil, gas, or coal by some 
measured amount,'' but rather to generally ``incentivize both the 
conservation of natural resources (by extending the life of current 
operations) and domestic energy production over foreign energy 
production.'' 86 FR 4616. Because this conclusory statement is made 
without any supporting data, ONRR cannot determine, at this time, 
whether the 2020 Rule's extension of the index-based valuation 
provision to arm's-length sales would result in additional production. 
Thus, it was unsupported and must be withdrawn.
    Public Comment: Some commenters opposed the withdrawal of this 
provision of the 2020 Rule because doing so reintroduces uncertainty in 
valuing Federal gas sold under arm's-length contracts.
    ONRR Response: A lessee knows the amount at which it contracts to 
sell, transport, and process its gas. To ensure its compliance with its 
royalty reporting and payment obligations, the lessee can contract with 
the transporter or processor to require sharing of the information 
needed to accurately report royalty value. As long as a lessee 
negotiates contracts in a manner that allows it to meet its royalty 
obligations, its own actions minimize uncertainty. ONRR is not required 
to adopt an index-based valuation option for arm's-length sales simply 
because some lessees failed to secure rights to the data necessary to 
support the lessee's reported allowances.
    Public Comment: One commenter stated that ONRR's revised economic 
analysis is an insufficient justification for a withdrawal of the index 
amendments because the difference between the 2020 Rule estimates as 
compared to the revised index analysis is nominal. According to the 
commenter, ONRR has collected $9 billion in royalties, rents and 
bonuses from oil and gas production per year over the past decade, and 
the 2020 Rule results in a $20.6 million decrease of in royalty 
collections per year, which equates to only a 0.2 percent decrease in 
average annual revenue collected. The commenter concluded that this 
achieves ONRR's objective of promulgating revenue neutral regulations.
    ONRR Response: The 2020 Rule's economic analysis estimated that 
extending the index-based valuation option to arm's-length sales would 
increase royalties paid to the United States by $26,741,000 per year, 
but that the rule as a whole would decrease royalties paid by 
$28,879,000 per year. 86 FR 4641. The Proposed Withdrawal Rule and this 
final rule have improved on the methodology used to estimate economic 
impacts and now quantify the 2020 Rule's effect on royalties as 
follows: Extending the index-based valuation option to arm's-length 
sales would decrease royalties paid to the United States by $7,460,000 
per year, and the 2020 Rule as a whole would decrease royalties paid by 
$64,600,000 per year. Cf. 86 FR 31208 with Economic Analysis, below.
    ONRR does not consider these impacts revenue neutral. Further, 
judging the impact of an optional change in valuation available for 
some but not all Federal gas to the entirety of revenues from Federal 
oil, gas, coal, and other minerals distorts its significance. Finally, 
ONRR is not basing its withdrawal of any one of the five provisions 
discussed in this Section III on whether it incentivizes production or 
impacts revenue alone, but on the entirety of considerations discussed 
in this final rule. ONRR is withdrawing the five provisions for the 
additional reasons set forth in Section II above, and the defects set 
forth in this Section III further support withdrawal of the 2020 Rule.

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

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

[[Page 54059]]

A. Impacts of Frequent Rule Changes on Industry

    Public Comment: Rule changes are costly and time consuming. 
Commenters stated that, if new rules or rule revisions become more 
frequent, confusion increases, and industry will be tempted to not make 
changes because industry may anticipate that those rules will be 
reversed in a few years. Commenters stated that rules should not change 
with each new administration, especially reversing and re-doing the 
rules every term. One commenter expressed its desire to see an ONRR 
rule that is fair and equitable for both sides.
    ONRR Response: ONRR agrees that rule changes should not be based 
solely on a change in administration. However, duly promulgated rule 
changes can reduce confusion by eliminating ambiguities, addressing new 
industry practices and technology, or otherwise improving the 
regulations. In addition, ONRR must update and modernize its 
regulations when necessary and appropriate. In doing so, ONRR strives 
to promulgate fair and equitable regulations compliant with governing 
law. Consistent with this, ONRR is withdrawing the 2020 Rule. See 
Sections II and III.

B. Reliance on E.O.s Now Revoked

    Public Comment: A few commenters referenced E.O.s that ONRR cited 
during the promulgation of the 2020 Rule that have since been revoked. 
Specifically, the commenters cite E.O. 13783 (Promoting Energy 
Independence and Economic Growth) and E.O. 13795 (Implementing an 
America-First Offshore Energy Strategy). Commenters also cite E.O.s now 
in effect, including E.O. 13990 (Protecting Public Health and the 
Environment and Restoring Science to Tackle the Climate Crisis, 86 FR 
7037 (Jan. 25, 2021)).
    ONRR Response: ONRR acknowledges that E.O.s 13783 and 13795 were 
revoked after the publication of the 2020 Rule but before its effective 
date. ONRR likewise acknowledges the E.O. 13990 directs agencies to 
consider certain matters such as science and climate change. ONRR's 
statutory directives pertain to the collection of royalties based on 
the fair market value. ONRR has no statutory framework within which to 
consider climate change as part of its rulemakings. ONRR addressed 
similar comments in the Proposed Withdrawal Rule. See 86 FR 31205.

C. Royalty Impacts to States

    Public Comment: A commenter stated that the 2020 Rule failed to 
consider certain reasons for promulgating the 2016 Valuation Rule, such 
as ensuring the accurate calculation of royalties, which may be 
subsequently disbursed to States sharing in royalty revenues.
    ONRR Response: ONRR distributes the royalties that it collects 
under Federal oil and gas leases as directed by the relevant 
disbursement statutes. See 30 U.S.C. 191(a) and 43 U.S.C. 1337(g)(2) 
and (7); see also 30 CFR part 1219. The Proposed 2020 Rule, the 2020 
Rule, the Proposed Withdrawal Rule and this final rule estimate the 
impact of the amendments to States that share in royalty revenues in 
the respective sections entitled Economic Analysis. See 85 FR 62069-
62070 and 86 FR 4649, 31214-31215.

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

    Public Comment: ONRR received comments supporting and opposing 
withdrawal of some of the revenue-neutral amendments.
    ONRR Response: ONRR is withdrawing the 2020 Rule for the reasons 
set forth above. As stated above, ONRR plans to publish proposed rules 
on some or all of the topics covered by the now withdrawn amendments.

V. Economic Analysis

    ONRR's economic analysis of withdrawal of the 2020 Rule remains 
unchanged following publication of the Proposed Withdrawal Rule, except 
for the one-time administrative cost associated with the optional use 
of the index-based valuation method. The economic analysis is set forth 
in the Proposed Withdrawal Rule (86 FR 31208-31215) and summarized 
again below.
    ONRR recognizes that estimated changes to royalty obligations and 
regulatory costs in the 2020 Rule impact many groups, including the 
Federal Government, State and local governments, and industry. These 
potential changes to royalty obligations can have broader impacts 
beyond the amount of royalties. Royalty collections are used by these 
governments in a variety of ways that include funding projects, 
developing infrastructure, and fueling economic growth.
    Further, changes to royalties are transfers that are 
distinguishable from regulatory costs or cost savings. The estimated 
changes in royalties would affect both the private cost to the lessee 
and the amount of revenue collected by the Federal Government and 
disbursed to State and local governments. The net impact of the 
withdrawal of the 2020 Rule is an estimated $64.6 million annual 
increase in royalty collections over what would have been realized if 
the 2020 Rule went into effect.
    Please note that, unless otherwise indicated, numbers in the tables 
in this section are rounded to the nearest thousand, and that the 
totals may not match due to rounding.

  Estimated Changes to Royalty Collections Resulting From Withdrawal of
                              the 2020 Rule
                                [Annual]
------------------------------------------------------------------------
                                                          Net change in
                    Rule provision                       royalties paid
                                                           by lessees
------------------------------------------------------------------------
Index-Based Valuation Method Extended to Arm's-Length         $6,800,000
 Gas Sales............................................
Index-Based Valuation Method Extended to Arm's-Length            660,000
 NGL Sales............................................
Highest to Average Bidweek Price for Non-Arm's-Length          5,062,000
 Gas Sales............................................
Transportation Deduction Non-Arm's-Length Index-Based          8,033,000
 Valuation Method.....................................
Extraordinary Processing Allowances...................        11,131,000
Allowances for Certain OCS Gathering Costs............        32,900,000
                                                       -----------------
    Total.............................................        64,600,000
------------------------------------------------------------------------

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

[[Page 54060]]



 Summary of Annual Administrative Impacts to Industry From Withdrawal of
                              the 2020 Rule
------------------------------------------------------------------------
                                                           Cost  (cost
                    Rule provision                          savings)
------------------------------------------------------------------------
Administrative Cost for Index-Based Valuation Method          $1,077,000
 for Gas & NGLs.......................................
Administrative Cost Savings for Allowances for Certain       (3,931,000)
 OCS Gathering........................................
                                                       -----------------
    Total.............................................       (2,850,000)
------------------------------------------------------------------------

    Following the publication of the delay rules and after 
consideration of comments received in response to the First Delay Rule, 
ONRR assessed which parts of the previous economic analysis warranted 
revision. To provide a more complete analysis, this final rule presents 
the estimated royalty impacts of the withdrawal of the 2020 Rule using 
the updated analyses. Changes are measured relative to a baseline that 
includes the royalty changes finalized in the 2020 Rule.
    As shown in the tables, an updated analysis of the impact to 
royalty under the 2020 Rule results in a total decrease in royalties of 
$64.6 million per year, which translates to an increase of $64.6 
million per year under this withdrawal. This amount stands in contrast 
to the annual decrease of $28.9 million per year in royalties 
previously estimated in the 2020 Rule and further justifies withdrawal 
of the 2020 Rule. The change in amounts is largely attributable to the 
new assumption and method used to estimate the impact from extending 
the index-based valuation method to arm's-length natural gas and NGL 
sales. A more detailed explanation of the new method is described 
below. All impacts to royalties other than those related to the index-
based valuation option remain unchanged from those published in the 
2020 Rule.
    The administrative costs and potential administrative cost savings 
attributable to the 2020 Rule have also been updated using the new 
assumptions for the extension of index-based valuation method to arm's-
length sales. The administrative cost to industry for deepwater 
gathering allowances would remain unchanged from the value published in 
the 2020 Rule.
    ONRR updated the estimated one-time administrative cost associated 
with the optional use of the index-based valuation method. These costs 
are only incurred by a lessee once to distinguish allowed and 
disallowed costs in reported processing and transportation allowances. 
In many situations, industry has already performed these calculations 
to comply with previous reporting requirements. ONRR reduced the total 
one-time administrative cost published in the Proposed Withdrawal Rule 
to be more reflective of only newer gas processing plants that would 
require the additional administrative cost. Unless there is a 
significant change in processing and transportation costs, the ratio of 
allowed to disallowed costs should not substantially change from year 
to year.

One-Time Administrative Impacts to Industry From Withdrawal of 2020 Rule
------------------------------------------------------------------------
                    Rule provision                            Cost
------------------------------------------------------------------------
Administrative Cost of Unbundling Related to Index-             $243,000
 Based Valuation Method for Gas & NGLs................
------------------------------------------------------------------------

    Withdrawal of the 2020 Rule will increase administrative costs when 
compared to the current status quo, which is the 2020 Rule. While that 
rule has not yet gone into effect due to the First and Second Delay 
Rules, it would have gone into effect absent this withdrawal rule, and 
therefore is the appropriate point of comparison for the measurement of 
costs, benefits, and transfers.
    ONRR used the same base dataset for this proposed rule's economic 
analysis as it used in the 2020 Rule for consistency and comparability. 
The description of the data was provided in the Economic Analysis of 
the 2020 Rule and is repeated here. ONRR reviewed royalty data for 
Federal oil, condensate, residue gas, unprocessed gas, fuel gas, gas 
lost (flared or vented), carbon dioxide (``CO2''), sulfur, 
coalbed methane, and natural gas products (product codes 03, 04, 15, 
16, 17, 19, 39, 07, 01, 02, 61, 62, 63, 64, and 65) from five calendar 
years, 2014-2018. ONRR used five calendar years of royalty data to 
reduce volatility caused by fluctuations in commodity pricing and 
volume swings. ONRR adjusted the historical data in this analysis to 
calendar year 2018 dollars using the Consumer Price Index (all items in 
U.S. city average, all urban consumers) published by the BLS. ONRR 
found that some companies aggregate their natural gas volumes from 
multiple leases into pools and sell that gas under multiple contracts. 
A lessee reports those sales and dispositions using the ``POOL'' sales 
type code. Only a small portion of these gas sales are non-arm's-
length. ONRR used estimates of 10 percent of the POOL volumes in the 
economic analysis of non-arm's-length sales and 90 percent of the POOL 
volumes in the economic analysis of arm's-length sales.
Change in Royalty 1: Using Index-Based Valuation Method to Value Arm's-
Length Federal Unprocessed Gas, Residue Gas, Fuel Gas, and Coalbed 
Methane
    ONRR analyzed this provision similarly to the 2020 Rule, assuming 
that half of lessees would elect to use the index-based valuation 
method. ONRR received many comments stating that this assumption was 
flawed, because a lessee will typically act in a manner that maximizes, 
not harms, financial benefits to the lessee. ONRR stated in the 2020 
Rule that the assumption that half of lessees would elect to use the 
index-based valuation option was an attempt to simplify the royalty 
impact estimation. Due to the delay rules, ONRR was able to apply a 
more sophisticated set of assumptions to estimate the lessees that 
would likely benefit from the 2020 Rule's amendments to the index-based 
valuation option and those that would not. ONRR began the analysis with 
a similar rationale on the same data that

[[Page 54061]]

it used in the 2020 Rule's calculation. ONRR reviewed the reported 
royalty data for all Federal gas sales except for non-arm's-length 
transactions (discussed below), future valuation agreements, and 
percentage of proceeds (``POP'') contracts. ONRR also adjusted the POOL 
sales down to 90 percent (as described above), which were spread across 
ten major geographic areas with active index prices. The ten areas 
account for over 95 percent of all Federal gas produced. ONRR assumed 
the remaining five percent of lessees producing Federal gas will not 
elect the index-based method because areas outside of major producing 
basins may have infrastructure limitations or limited access to index 
pricing. The ten geographic areas are:

1. Offshore Gulf of Mexico
2. Big Horn Basin
3. Green River Basin
4. Permian Basin
5. Piceance Basin
6. Powder River Basin
7. San Juan Basin
8. Uinta Basin
9. Williston Basin
10. Wind River Basin

    To calculate the estimated royalty impact, ONRR:
    (1) Identified the monthly bidweek price index, published by Platts 
Inside FERC, for each applicable area--Northwest Pipeline Rockies for 
Green River, Piceance and Uinta basins; El Paso San Juan for San Juan 
basin; Colorado Interstate Gas for Big Horn, Powder River, Williston, 
and Wind River basins; El Paso Permian for Permian basin; and Henry Hub 
for the Gulf of Mexico. ONRR determined the applicability of a price 
index based on proximity to the producing area and the frequency with 
which ONRR's audit and compliance staff verify these index prices in 
sales contracts;
    (2) subtracted the appropriate transportation deduction as 
described in the 2020 Rule from the midpoint index price identified in 
step (1);
    (3) compared the reported monthly price for each lease inclusive of 
any reported transportation allowances to the applicable index price 
for the lease calculated in step (2) for all months in the first year 
of reported royalty data in the dataset;
    (4) identified all leases in step (3) where the reported price 
exceeded the price calculated in step (2) for seven or more months in 
the time period;
    (5) used the lease list created in step (4) as the base universe of 
properties that would elect to use the index-based valuation method 
available;
    (6) compared the actual reported price for each month for each 
lease in the universe identified in step (5), inclusive of 
transportation allowances reported, to the calculated price in step (2) 
to identify the difference between what was reported as actual 
royalties and what would have been reported as royalties under the 
terms of the index-based valuation method;
    (7) performed this calculation and comparison for the next two sets 
of two-year time periods in the remaining four years of royalty 
reporting in the dataset; and
    (8) calculated the total difference in the four years between the 
original reported royalty prices and royalties of the identified lease 
universe that elected the index-based valuation method, then divided 
that total by four to get an annual estimated royalty impact.
    This new method of identification of the lease universe that would 
elect the index-based valuation method if given the opportunity is the 
basis for the differences between the estimated royalty impact 
published in the 2020 Rule and the estimated royalty impact included in 
this final rule. Also, this identification of the leases that stand to 
benefit is similar to how a lessee will make its decisions and is a 
better method to estimate the royalty impact. ONRR compared the monthly 
prices reported to it in the first year of the data period, inclusive 
of transportation allowances, to the index prices for the appropriate 
producing areas, inclusive of transportation deductions. ONRR then 
identified the leases with reported prices higher than the index price 
in seven or more months of the year. For these leases with prices 
higher than index for more than half of the year, ONRR assumes the 
lessee would elect to use the index-based valuation method. For arm's-
length natural gas sales, this equates to 39.8 percent of the entire 
list of leases and represents a percentage that is lower than the 50 
percent assumption made by ONRR in the 2020 Rule's estimated impacts on 
royalty collections of this same provision. This new percentage 
incorporates a more logical identification of the leases taking into 
account a lessee's potential financial benefit.
    ONRR estimates the index-based valuation method in the 2020 Rule 
would have decreased royalty payments on arm's-length natural gas by 
approximately $6.8 million per year when compared to ONRR regulations 
in effect prior to the 2020 Rule.

 Annual Change in Royalties Paid Using Index-Based Method for Arm's-Length Gas Sales From Withdrawal of the 2020
                                                      Rule
----------------------------------------------------------------------------------------------------------------
                                                             Gulf of Mexico      Other areas          Total
----------------------------------------------------------------------------------------------------------------
Annualized Reported Royalties from Identified Lease              $51,720,000      $168,850,000      $220,570,000
 Universe.................................................
Royalties Estimated using Index-Based Valuation Method for        53,940,000       159,790,000       213,730,000
 Lease Universe...........................................
Difference................................................       (2,220,000)         9,060,000         6,840,000
----------------------------------------------------------------------------------------------------------------

Change in Royalties 2: Using the Index-Based Valuation Method To Value 
Arm's-Length Sales of Federal NGLs
    ONRR used similar changes to the assumptions when calculating the 
royalty impact from extending the index-based valuation option to 
arm's-length sales of NGLs. As in the previous section, ONRR's goal was 
to identify a universe of leases that would benefit financially from 
electing the index-based valuation method. In the 2020 Rule, ONRR 
assumed that half of the lessees would elect the method without regard 
to financial benefit or harm.
    ONRR used the same dataset for this analysis that was used in the 
2020 Rule. It included all NGL sales except for non-arm's-length 
transactions and future valuation agreements. ONRR also adjusted the 
POOL sales down to 90 percent (as described above). These sales were 
spread across the same ten major geographic areas with active index 
prices for this analysis. To calculate the estimated royalty impact of 
the index-based valuation method on NGLs from Federal leases, ONRR:
    (1) Identified the Platts Oilgram Price Report Price Average 
Supplement (Platts Conway) or OPIS LP Gas Spot Prices Monthly (OPIS 
Mont Belvieu) for published monthly midpoint NGL prices per component 
applicable to each area: Platts Conway for Williston and Wind River 
basins; and OPIS Mont

[[Page 54062]]

Belvieu non-TET for the Gulf of Mexico, Big Horn, Green River, Permian, 
Piceance, Powder River, San Juan, and Uinta basins. In ONRR's audit 
experience, OPIS' prices are used to value NGLs in contracts more 
frequently at Mont Belvieu, and Platts' prices are used more frequently 
at Conway;
    (2) calculated NGL basket prices (weighted average prices to group 
the individual NGL components), which were compared to the imputed 
price from the monthly royalty report. The baskets illustrate the 
difference in the gas composition between Conway, Kansas and Mont 
Belvieu, Texas. The NGL basket hydrocarbon allocations are:

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

    (3) subtracted the current processing deductions, as well as 
fractionation costs and transportation costs referenced in ONRR 
regulations without amendment by the 2020 Rule (see 30 CFR 
1206.142(d)(2)(ii)), as shown in the table below from the NGL basket 
price calculated in step (2):

                                                  NGL Deduction
                                                     [$/gal]
----------------------------------------------------------------------------------------------------------------
                                                             Gulf of Mexico      New Mexico        Other areas
----------------------------------------------------------------------------------------------------------------
Processing................................................             $0.10             $0.15             $0.15
Transportation and Fractionation..........................              0.05              0.07              0.12
                                                           -----------------------------------------------------
    Total ($/gal).........................................              0.15              0.22              0.27
----------------------------------------------------------------------------------------------------------------

    (4) compared the reported monthly price for each lease inclusive of 
any reported transportation or processing allowances to the applicable 
index price for the lease calculated in step (3) for all months in the 
first year of reported royalty data in the dataset;
    (5) identified all leases in step (4) where the reported price 
exceeded the price calculated in step (3) for seven or more months in 
the time period;
    (6) used the lease list created in step (5) as the base universe of 
leases that would elect to use the index-based valuation method if 
available;
    (7) compared the actual reported price for each month for each 
lease in the universe identified in step (6), inclusive of 
transportation and processing allowances reported, to the calculated 
price in step (3) to identify the difference between what was reported 
as actual royalties and what would have been reported as royalties 
under the terms of the index-based valuation method;
    (8) performed this calculation and comparison for the next two sets 
of two-year time periods in the remaining four years of royalty 
reporting in the dataset; and
    (9) calculated the total difference in the four years between the 
original reported royalty prices and the royalties if the identified 
lease universe elected the index-based valuation method, then divided 
that total by four to get an annual estimated royalty impact.
    This new method of identification of the lease universe that would 
elect the index-based valuation method is the basis for the difference 
between the estimated royalty impact published in the 2020 Rule and the 
estimated royalty impact included in this final rule.
    ONRR estimates the index-based valuation method in the 2020 Rule 
would have decreased royalty payments on arm's-length NGLs by 
approximately $660,000 per year, and that withdrawing the 2020 Rule 
will increase royalty payments by $660,000 annually.

Annual Change in Royalties Paid Using Index-Based Valuation Method for Arm's-Length NGL Sales From Withdrawal of
                                                  the 2020 Rule
----------------------------------------------------------------------------------------------------------------
                                                  Gulf of Mexico    New Mexico      Other areas        Total
----------------------------------------------------------------------------------------------------------------
Annualized Reported Royalties from Identified         $4,990,000        $350,000      $9,100,000     $14,440,000
 Lease Universe.................................
Royalties Estimated Using Index-Based Valuation        3,470,000         290,000      10,020,000      13,780,000
 Method for Lease Universe......................
Annual Net Change in Royalties Paid Using Index-       1,520,000          60,000       (920,000)         660,000
 Based Valuation Method for NGLs................
----------------------------------------------------------------------------------------------------------------


[[Page 54063]]

Change in Royalties 3: Using the Average Index Price Versus the Highest 
Published Index Price To Value Non-Arm's-Length Federal Unprocessed 
Gas, Residue Gas, Coalbed Methane, and NGLs
    In the 2020 Rule, ONRR amended the index-based valuation method to 
use the average bidweek price, rather than the highest bidweek price, 
for the appropriate index-pricing point. ONRR accounted for the impacts 
to royalty collections attributable to arm's-length natural gas 
transactions in the earlier section. This section will focus on the 
impact to royalty collections only attributable to non-arm's-length 
natural gas transactions.
    The method for calculation in this final rule is similar to the 
method used in the 2020 Rule, with adjustments made related to the 
universe of leases that would elect the index-based valuation method. 
ONRR compared the monthly prices reported to it in the first year of 
the data period, inclusive of transportation allowances, to the index 
prices for the appropriate producing areas, inclusive of transportation 
deductions. ONRR then identified the leases with reported prices higher 
than the index price in seven or more months of the year. For these 
leases with prices higher than index for more than half of the year, 
ONRR assumes the lessee would elect to use the index-based valuation 
method. For non-arm's-length natural gas sales, this equates to 56.4 
percent of the entire list of leases and represents a percentage that 
is higher than the 50 percent assumption made by ONRR in the 2020 
Rule's estimated impacts on royalty collections of this same provision. 
This new percentage incorporates a more logical identification of the 
leases taking into account a lessee's potential financial benefit.
    ONRR used reported royalty data for non-arm's-length (``NARM'') 
sales and ten percent of the POOL sales type codes based on the 
assumption above in the same ten major geographic areas with active 
index-pricing points, also listed above.
    To calculate the estimated impact, ONRR:
    (1) Identified the Platts Inside FERC published monthly midpoint 
and high prices for the index applicable to each area-- Northwest 
Pipeline Rockies for Green River, Piceance and Uinta basins; El Paso 
San Juan for San Juan basin; Colorado Interstate Gas for Big Horn, 
Powder River, Williston, and Wind River basins; El Paso Permian for 
Permian basin; and Henry Hub for the Gulf of Mexico;
    (2) multiplied the royalty volume by the published index prices 
identified for each region;
    (3) totaled the estimated royalties using the published index 
prices calculated in step (2);
    (4) calculated the annual average index-based royalties for both 
the high and volume-weighted-average prices calculated in step (3) by 
dividing by five (number of years in this analysis); and
    (5) subtracted the difference between the totals calculated in step 
(4).
    Because ONRR identified that 56.4 percent of leases fall in the 
universe of leases that would elect the index-based valuation method, 
ONRR reduced the total estimate by 43.6 percent in the following table. 
ONRR estimated that the result of this change is that the 2020 Rule, if 
it went into effect, would result in a decrease in annual royalty 
payments of approximately $5 million, and a withdrawal of that rule 
would result in an increase in annual royalty payments by a like 
amount, as reflected in the table below.

 Estimated Impact to Royalty Collections Due To Withdrawal of 2020 Rule's High to Midpoint Modification for Non-
                      Arm's-Length Sales of Natural Gas Using Index-Based Valuation Method
----------------------------------------------------------------------------------------------------------------
                                                             Gulf of Mexico    Onshore basins         Total
----------------------------------------------------------------------------------------------------------------
Royalties Estimated Using High Index Price................      $107,736,000      $198,170,000      $305,907,000
Royalties Estimated Using Published Average Bidweek Price.       107,448,000       189,483,000       296,931,000
Annual Change in Royalties Paid due to High to Midpoint              288,000         8,687,000         8,975,000
 Change...................................................
56.4% of applicable leases................................  ................  ................         5,062,000
----------------------------------------------------------------------------------------------------------------

Change in Royalties 4: Modifying the Index-Based Valuation Method To 
Account for Transportation in Valuing Non-Arm's-Length Federal 
Unprocessed Gas, Residue Gas, and Coalbed Methane
    The 2020 Rule increased the reductions to index price to account 
for transportation of production valued under the non-arm's-length 
index-based valuation method first adopted in the 2016 Valuation Rule. 
ONRR used the new method described previously in this Economic Analysis 
to identify the likely lease universe of non-arm's-length natural gas 
sales. ONRR identified the same 56.4 percent of non-arm's-length 
natural gas leases as the universe that would elect the method.
    To estimate the royalty impact of the change in amount intended to 
account for transportation, ONRR used reported royalty data using NARM 
and ten percent of the POOL sales type codes from the same ten major 
geographic areas with active index-pricing points listed above.
    To calculate the estimated impact, ONRR:
    (1) Identified appropriate areas using Platts Inside FERC index 
prices (see list above);
    (2) calculated the transportation-related adjustment as published 
in the current regulations and the adjustment outlined in the table 
below for each area identified in step (1);

 Transportation Deduction of Index-Based Valuation Method for Non-Arm's-
                               Length Gas
                                [$/MMBtu]
------------------------------------------------------------------------
                                       2016 Valuation
               Element                      rule            2020 rule
------------------------------------------------------------------------
Gulf of Mexico %....................                5%               10%
Gulf of Mexico Low Limit............             $0.10             $0.10
Gulf of Mexico High Limit...........              0.30              0.40
Other Areas %.......................               10%               15%
Other Areas Low Limit...............              0.10              0.10
Other Areas High Limit..............              0.30              0.50
------------------------------------------------------------------------


[[Page 54064]]

    (3) multiplied the royalty volume by the applicable transportation 
deduction identified for each area calculated in step (2);
    (4) totaled the estimated royalty impact based off both 
transportation deductions calculated in step (3);
    (5) calculated the annual average royalty impact for both methods 
calculated in step (4) by dividing by five (number of years in this 
analysis); and
    (6) subtracted the difference between the totals calculated in step 
(5).
    Because ONRR identified the universe of 56.4 percent of lessees 
that will likely elect this method, ONRR reduced the total estimated 
impact to royalty collections by 43.6 percent. ONRR estimated the 
change would result in a decrease in royalty collections of 
approximately $8 million per year if the 2020 Rule went into effect, 
and an increase in royalty collections of like amount if the 2020 Rule 
is withdrawn, as reflected in the table below.

  Annual Royalty Impact Due to Transportation Deduction Modification for Non-Arm's-Length Sales of Natural Gas
                                        From Withdrawal of the 2020 Rule
----------------------------------------------------------------------------------------------------------------
                                                             Gulf of Mexico      Other areas          Total
----------------------------------------------------------------------------------------------------------------
Current Regulations Transport Deduction...................      ($5,387,000)     ($16,375,000)     ($21,762,000)
Estimate using 2020 Rule Transport Deduction..............       (10,346,000      (25,659,000)      (36,005,000)
Change....................................................         4,959,000         9,284,000        14,243,000
56.4% universe of leases..................................  ................  ................         8,033,000
----------------------------------------------------------------------------------------------------------------

Change in Royalties 5: Extraordinary Gas Processing Cost Allowances for 
Federal Gas
    The 2020 Rule allows a lessee to request an extraordinary 
processing cost allowance. Below, ONRR uses the same calculation method 
for these royalty impacts as it did in the 2020 Rule. Using the 
approvals ONRR granted prior to the 2016 Valuation Rule, ONRR 
identified the 127 leases claiming an extraordinary processing 
allowance for residue gas, sulfur, and CO2 for calendar 
years 2014-2018. The total processing costs are reported across all 
three products for these unique situations. For these leases, ONRR 
reviewed all form ONRR-2014 royalty lines with a processing allowance 
reported by lessees. For CO2 and sulfur produced from these 
leases, ONRR then calculated the annual average processing allowances, 
which exceeded the 66 \2/3\ percent limit and found that only two years 
exceeded the 66 \2/3\ percent limit. Under these unique approved 
exceptions, the processing allowances are also reported against residue 
gas. To account for this, ONRR added the average annual processing 
allowances taken from those same leases for residue gas.
    Based on these calculations, ONRR previously estimated the royalty 
impact of the 2020 Rule's reinstatement of extraordinary processing 
allowances as decreasing royalties by $11.1 million per year, and ONRR 
now estimates the royalty impact of withdrawing this provision of the 
2020 Rule at an increase in royalties of $11.1 million per year. 
However, ONRR recognizes that these estimates of decrease from the 2020 
Rule and increase from this final rule likely undervalue actual impacts 
for the reasons discussed in Section III.D., above--i.e., hard caps 
rather than soft caps on processing allowances may result in more 
lessees applying for extraordinary processing allowances than did when 
they could apply to exceed soft caps instead. As a result, there could 
be an increase in the number of requests submitted to ONRR for 
extraordinary processing allowances under the 2020 Rule and a larger-
than-quantified impact upon withdrawal of the 2020 rule. But there is 
little data available to identify the number or magnitude of 
incremental requests possible under the 2020 Rule, and there is not 
enough information to determine how many of these requests would be 
approved or denied by ONRR. For these reasons, ONRR is unable to more 
precisely estimate the royalty impact of reinstating extraordinary 
processing allowances under the 2020 Rule or withdrawing those 
allowances under this final rule.

  Estimated Annual Change in Royalty Collections From Withdrawal of the
                                2020 Rule
------------------------------------------------------------------------
 
------------------------------------------------------------------------
Annual Average Sulfur Allowances in Excess of 66 \2/           $348,000
 3\%.................................................
Annual Average Residue Gas Allowance.................        10,783,000
Estimated Annual Impact on Royalties.................        11,131,000
------------------------------------------------------------------------

Change in Royalties 6: Transportation Allowances for Certain OCS 
Gathering for Federal Oil and Gas
    In the 2020 Rule, ONRR adopted regulatory changes that would allow 
an OCS lessee to take certain gathering costs as part of its 
transportation allowance. ONRR adjusted its method for calculating this 
royalty impact in response to comments received on the Proposed 2020 
Rule and published a corrected method in the 2020 Rule. ONRR will 
continue to use the adjusted method here to estimate the royalty impact 
of the 2020 Rule, whether it goes into effect or is withdrawn.
    As previously discussed, the Deepwater Policy was in effect from 
1999 through December 31, 2016. Under the Deepwater Policy, ONRR 
allowed a lessee to treat certain costs for subsea gathering as 
transportation expenses and to deduct those costs in calculating its 
royalty obligations. The 2016 Valuation Rule rescinded the Deepwater 
Policy, but the 2020 Rule codified a deepwater gathering allowance 
similar to the Deepwater Policy. To analyze the impact to industry of 
the 2020 Rule's deepwater gathering allowance, ONRR used data from 
BSEE's Technical Information Management System database to identify 113 
subsea pipeline segments, and 169 potentially eligible leases, which 
might qualify for a deepwater gathering allowance. ONRR assumed that 
all segments were similar (in other words, no adjustments were made to 
account for the size, length, or type of pipeline) and considered only 
the pipeline segments that were active and supporting producing leases. 
To determine the range (shown in the tables at the end of this section 
as low, mid, and high estimates) of changes to royalties, ONRR 
estimated a 15 percent error rate in the identification of the 113 
eligible pipeline segments. This resulted in a range of 96 to 130 
eligible pipeline segments. ONRR's audit data is

[[Page 54065]]

available for 13 subsea gathering segments serving 15 leases covering 
time periods from 1999 through 2010. ONRR used the data to determine an 
average initial capital investment in the pipeline segments. Then, ONRR 
used the initial capital investment total to calculate depreciation and 
a return on undepreciated capital investment (also known as the return 
on investment or ``ROI'') for eligible pipeline segments and calculated 
depreciation using a 20-year straight-line depreciation schedule.
    ONRR calculated the return on investment using the average BBB Bond 
rate for January 2018 (the BBB Bond rating is a credit rating used by 
the Standard & Poor's credit agency to signify a certain risk level of 
long-term bonds and other investments). ONRR based the calculations for 
depreciation and ROI on the first year a pipeline was in service. From 
the same audit information, ONRR calculated an average annual operating 
and maintenance (``O&M'') cost. ONRR increased the O&M cost by 12 
percent to account for overhead expenses. ONRR then decreased the total 
annual O&M cost per pipeline segment by nine percent because, on 
average, nine percent of wellhead production volume is water, which 
must be excluded from any calculation of a permissible deduction. ONRR 
chose these two percentages based on knowledge and information gathered 
during audits of leases located in the Gulf of Mexico. Finally, ONRR 
used an average royalty rate of 14 percent, which is the volume-
weighted-average royalty rate for the non-Section 6 leases in the Gulf 
of Mexico. See 43 U.S.C. 1335(a)(9). Based on these calculations, the 
average annual allowance per pipeline segment during the period that 
ONRR collected data from was approximately $233,000. ONRR used this 
value to calculate a per-lease cost based on the number of eligible 
leases during the same period. ONRR then applied this value to the 
current number of eligible leases. This represented the estimated 
amount per lease for gathering that ONRR would allow a lessee to take 
as a transportation allowance based on the 2020 Rule's deepwater 
gathering allowance. To calculate a range for the total cost, ONRR 
multiplied the average annual allowance by the low (96), mid (113), and 
high (130) number of potentially eligible segments. The low, mid, and 
high annual allowance estimates are $35 million, $41.1 million, and 
$47.3 million, respectively.
    Of the eligible leases, 68 of 169, or about 40 percent, are 
estimated to qualify for a deduction under the 2020 Rule's deepwater 
gathering allowance. But due to varying lease terms, multiple royalty 
relief programs, price thresholds, volume thresholds, and other 
factors, ONRR estimated that half of the 68, or 34, leases eligible for 
royalty relief (20 percent of 169) have received royalty relief, which 
limits the value of a deepwater gathering allowance. ONRR chose to use 
an estimate of half of the leases for consistency, and it decreased the 
low, mid, and high annual cost-to-industry estimates by 20 percent. The 
table below shows the estimated royalty impact of withdrawing this 
provision of the 2020 Rule.

                 Annual Estimated Impact to Royalty Collections From Withdrawal of the 2020 Rule
----------------------------------------------------------------------------------------------------------------
                                                                Low                Mid                High
----------------------------------------------------------------------------------------------------------------
Royalty Impact.........................................       $28,000,000        $32,900,000        $37,900,000
----------------------------------------------------------------------------------------------------------------

Cost Savings 1: Transportation Allowances for Certain OCS Gathering 
Costs for Offshore Federal Oil and Gas
    The 2020 Rule, by authorizing transportation allowances for certain 
OCS gathering, would result in an administrative cost to industry 
because it requires a qualified lessee to monitor its costs and perform 
additional calculations if it is to claim the allowance. ONRR 
identified no need to adjust or change the analysis performed in the 
2020 Rule to estimate this cost to industry. The cost to perform these 
calculations is significant because industry often hires additional 
labor or outside consultants to calculate subsea pipeline movement 
costs. ONRR estimates that each lessee with leases eligible for 
transportation allowances for deepwater gathering systems will allocate 
one full-time employee annually (or incur the equivalent cost for an 
outside consultant) to perform the calculation. ONRR used data from the 
BLS to estimate the hourly cost for industry accountants in a 
metropolitan area [$42.33 mean hourly wage] with a multiplier of 1.4 
for industry benefits to equal approximately $59.26 per hour. Using 
this fully burdened labor cost per hour, ONRR estimated that the annual 
administrative cost savings to industry if the 2020 Rule is withdrawn 
would be approximately $3.9 million.

 Annual Administrative Cost Savings to Industry To Calculate Certain OCS Gathering Costs From Withdrawal of the
                                                    2020 Rule
----------------------------------------------------------------------------------------------------------------
                                                                                Companies        Estimated cost
                                        Annual burden      Industry labor       reporting          savings to
                                      hours per company      cost/hour       eligible leases        industry
----------------------------------------------------------------------------------------------------------------
Allowance for Certain OCS Gathering              2,080             $59.26                 32         $3,931,000
 Costs Withdrawn....................
----------------------------------------------------------------------------------------------------------------

Cost 1: Administrative Cost From Using Index-Based Valuation Method To 
Value Arm's-Length Federal Unprocessed Gas, Residue Gas, Fuel Gas, 
Coalbed Methane, and NGLs
    In the 2020 Rule, ONRR assumed that half of the lessees would elect 
to use the index-based valuation method to value their arm's-length 
natural gas and NGL transactions. As described earlier in this Economic 
Analysis, ONRR identified that 39.8 percent of leases with arm's-length 
sales would elect this option. This is more accurate than the 2020 
Rule's assumptions, and ONRR will use it to estimate the potential 
administrative cost savings for industry.
    ONRR estimated the index-based valuation method would have 
shortened the time burden per line reported on the ONRR-2014 royalty 
reporting form by 50 percent (to 1.5 minutes per electronic line 
submission and 3.5 minutes per manual line submission). As with Cost 
Savings 1, ONRR used tables from the BLS to estimate the fully burdened

[[Page 54066]]

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) x 1.4 (including employee benefits)]. Using a labor cost 
factor of $59.26 per hour, ONRR estimates the annual administrative 
cost to industry will be approximately $1.1 million if the 2020 Rule is 
withdrawn.

                    Annual Administrative Costs to Industry From Withdrawal of the 2020 Rule
----------------------------------------------------------------------------------------------------------------
                                                                               Estimated lines
                                                             Time burden per   reported using     Annual burden
                                                              line reported     index option          hours
                                                                (minutes)           (50%)
----------------------------------------------------------------------------------------------------------------
Electronic Reporting (99%)................................               1.5           710,525            17,763
Manual Reporting (1%).....................................               3.5             7,177               419
Industry Labor Cost/hour..................................  ................  ................            $59.26
    Total Costs...........................................  ................  ................         1,077,000
----------------------------------------------------------------------------------------------------------------

Cost 2: Administrative Cost of Using Index-Based Valuation Method To 
Value Residue Gas and NGLs Because of Simplified Processing and 
Transportation Cost Calculations
    In the 2020 Rule, ONRR calculated the potential one-time 
administrative cost savings for industry if a lessee elects to use the 
index-based valuation method. 86 FR 4641. ONRR slightly modified this 
calculation and method as described further below. Use of the index-
based valuation method eliminates the need to segregate deductible 
costs of transportation and processing from non-deductible costs of 
placing production in marketable condition. This segregation or 
allocation of costs is often referred to as ``unbundling.'' Industry 
would unbundle transportation systems and processing plants one time 
under the current regulatory scheme (i.e., in absence of the 2020 
Rule), and then use those unbundled cost allocations for subsequent 
royalty calculations.
    While industry is responsible for calculating these costs, ONRR has 
published and calculated several unbundling cost allocations. It takes 
approximately 100 hours of labor per gas plant. ONRR calculated the 
average number of gas plants reported per lessee to be 3.4, across a 
total of 448 lessees reporting residue gas and NGLs, between 2014-2018. 
Using the BLS labor cost per hour of $59.26 (described above) and the 
assumption that 50 percent of lessees will choose the index-based 
valuation method, ONRR believed the 2020 Rule would have resulted in a 
one-time cost savings to industry of $4.5 million dollars. See 86 FR 
4641 and 4648.
    ONRR updated its analysis for this administrative cost. Given that 
the 2020 Rule has not gone into effect yet, industry has been 
unbundling its processing and transportation costs already for gas 
plants and transportation systems used under the current regulations. 
Because of this, new unbundling efforts would only occur on newly 
created gas plants or for gas plants that undergo major technological 
changes. ONRR looked at all the gas plants reported for Federal gas 
production since the start of 2020. ONRR also identified the number of 
new gas plants companies requested be added to ONRR's system for 
reporting since the start of 2020. The newly added gas plants 
represented 5.4 percent of all gas plants reported to ONRR for Federal 
production. This group represents those plants that would require 
lessees to perform a new unbundling analysis. ONRR applied this 
percentage to the total one-time cost savings in the 2020 Rule and now 
estimates that the withdrawal of the 2020 Rule will result in lessees 
incurring this one-time administrative cost of $243,000.
State and Local Governments
    ONRR estimated that, because of the 2020 Rule, States and certain 
local governments would have received an overall decrease in royalty 
disbursements based on the category that leases fall under, including 
OCSLA section 8(g) leases. See 43 U.S.C. 1337(g), Gulf of Mexico Energy 
Security Act (``GOMESA''), 43 U.S.C. 1331, et seq., and onshore Federal 
lands. ONRR disburses royalties based on where the royalty-bearing oil 
and gas was produced.
    Except for production from Federal leases in Alaska (where Alaska 
receives 90 percent of the distribution), for Section 8(g) leases in 
the OCS, and qualified leases under GOMESA in the OCS (more information 
on distribution percentages at https://revenuedata.doi.gov/how-it-works/gomesa/), the following distribution table generally applies:

                       ONRR Disbursements by Area
------------------------------------------------------------------------
                                           Onshore          Offshore
------------------------------------------------------------------------
Federal.............................               51%             95.2%
State...............................               49%              4.8%
------------------------------------------------------------------------

More information on ONRR's disbursements to any specific State or local 
government can be found at https://revenuedata.doi.gov/explore/#federal-disbursements.
Indian Lessors
    The provisions in the 2020 Rule and this withdrawal are not 
expected to affect Indian lessors.
Federal Government
    The impact of the 2020 Rule to the Federal Government will be a 
decrease in royalty collections. ONRR estimates the impact of the 2020 
Rule to the Federal Government (detailed in the next table of this 
section) would be a reduction in royalties of $49.7 million per year. 
The estimated impact to royalty collections of the withdrawal of the 
2020 Rule would be an increase in royalties of $49.7 million per year.
Summary of Royalty Impacts and Costs to Industry, State and Local 
Governments, Indian Lessors, and the Federal Government
    The table below shows the updated net change in royalties expected 
under

[[Page 54067]]

this withdrawal. The table breaks out the impacts to Federal and State 
disbursements based on the typical distributions noted in the table 
above and the appropriate product weightings and the location of the 
affected leases.

      Withdrawal of the 2020 Rule: Annual Impact to Royaly Collections, the Federal Government, and States
----------------------------------------------------------------------------------------------------------------
                                                                Impact to
                      Rule provision                             royalty       Federal portion    State portion
                                                               collections
----------------------------------------------------------------------------------------------------------------
Index-Based Valuation Method Extended to Arm's-Length Gas         $6,800,000        $4,180,000        $2,620,000
 Sales....................................................
Index-Based Valuation Method Extended to Arm's-Length NGL            660,000           430,000           230,000
 Sales....................................................
High to Midpoint Index Price for Non-Arm's-Length Gas              5,060,000         3,110,000         1,950,000
 Sales....................................................
Transportation Deduction Non-Arm's-Length Index-Based              8,030,000         4,930,000         3,100,000
 Valuation Method.........................................
Extraordinary Processing Allowance........................        11,130,000         5,680,000         5,450,000
Allowance for Certain OCS Gathering Costs.................        32,900,000        31,320,000         1,580,000
                                                           -----------------------------------------------------
    Total.................................................        64,600,000        49,700,000        14,900,000
----------------------------------------------------------------------------------------------------------------
Note: Totals may not add due to rounding.

Federal Oil and Gas Amendments With No Estimated Change to Royalty or 
Regulatory Costs
Change 1: Default Provision Applicable to Federal Oil and Gas
    The 2016 Valuation Rule added the default provision to ONRR 
regulations. The 2020 Rule removed the default provision from ONRR 
regulations. In instances of misconduct, breach of a lessee's duty to 
market, or other situations where royalty value cannot be determined 
under ONRR's valuation rules, ONRR can use the Secretary's statutory 
authority and the authority granted to the Secretary under the terms of 
the applicable leases to determine Federal oil and gas royalty value, 
as ONRR would have done prior to adoption of the 2016 Valuation Rule. 
ONRR has never found an impact to royalty collections on account of the 
default provision.
Federal and Indian Coal
    In the 2020 Rule, ONRR estimated there will be no change to royalty 
collections for the Federal Government, Indian Tribes, individual 
Indian mineral owners, States, or industry for Federal and Indian coal. 
ONRR has not changed or adjusted this estimate in this final rule. 
There is no impact to royalty collections on account of the coal 
provisions due to this final rule's withdrawals.

VI. Procedural Matters

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

    E.O. 12866 provides that the Office of Information and Regulatory 
Affairs (``OIRA'') of OMB will review all significant rulemakings. OMB 
has determined that this final rule is a significant regulatory action 
under E.O. 12866. The primary effect of this final rule is on royalty 
payments. ONRR expects that this final rule will largely result in 
transfers, which are described in the table below. ONRR also 
anticipates that this final rule will result in annual administrative 
cost savings of $2.85 million and a one-time administrative cost of 
$243,000.
    Please note that, unless otherwise indicated, numbers in the tables 
in this section are rounded to the nearest thousand and that the totals 
may not match due to rounding.

 Summary of Estimated Changes to Royalty Collections From the Withdrawal
                            of the 2020 Rule
                                [Annual]
------------------------------------------------------------------------
                                                          Net change in
                    Rule provision                       royalties paid
                                                           by lessees
------------------------------------------------------------------------
Index-Based Valuation Method Extended to Arm's-Length         $6,800,000
 Gas Sales............................................
Index-Based Valuation Method Extended to Arm's-Length            660,000
 NGL Sales............................................
High to Midpoint Index Price for Non-Arm's-Length Gas          5,062,000
 Sales................................................
Transportation Deduction Non-Arm's-Length Index-Based          8,033,000
 Valuation Method.....................................
Extraordinary Processing Allowances...................        11,131,000
Allowances for Certain OCS Gathering Costs............        32,900,000
                                                       -----------------
    Total.............................................        64,600,000
------------------------------------------------------------------------

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

Summary of Annual Administrative Impacts to Industry From the Withdrawal
                              of 2020 Rule
------------------------------------------------------------------------
                                                          Cost  (cost
                    Rule provision                          savings)
------------------------------------------------------------------------
Administrative Cost Savings for Index-Based Valuation        $1,077,000
 Method for Arm's-Length Gas & NGL Sales.............

[[Page 54068]]

 
Administrative Cost for Allowances for Certain OCS          (3,931,000)
 Gathering...........................................
                                                      ------------------
    Total............................................       (2,850,000)
------------------------------------------------------------------------


     Summary of One-Time Administrative Impacts to Industry From the
                         Withdrawal of 2020 Rule
------------------------------------------------------------------------
                    Rule provision                            Cost
------------------------------------------------------------------------
Administrative Cost-Savings in lieu of Unbundling              $243,000
 related to Index-Based Valuation Method for Arm's-
 Length Gas & NGLs...................................
------------------------------------------------------------------------


    Net Present Value of Administrative Impacts to Industry From the
                         Withdrawal of 2020 Rule
------------------------------------------------------------------------
            Time horizon              3% discount rate  7% discount rate
------------------------------------------------------------------------
Administrative Costs over 10 years..      -$24,800,000      -$21,200,000
Administrative Costs over 20 years..       -43,400,000       -32,100,000
------------------------------------------------------------------------


     Annualized Costs of Administrative Impacts to Industry From the
                         Withdrawal of 2020 Rule
------------------------------------------------------------------------
            Time horizon              3% discount rate  7% discount rate
------------------------------------------------------------------------
Annualized Administrative Costs over       -$2,820,000       -$2,820,000
 10 years...........................
Annualized Administrative Cost over        -$2,830,000       -$2,830,000
 20 years...........................
------------------------------------------------------------------------

    E.O. 13563 reaffirms the principles of E.O. 12866, while calling 
for improvements in the nation's regulatory system to promote 
predictability, to reduce uncertainty, and to use the most innovative 
and least burdensome tools for achieving regulatory ends. E.O. 13563 
directs agencies to consider regulatory approaches that reduce burdens 
and maintain flexibility and freedom of choice for the public where 
these approaches are relevant, feasible, and consistent with regulatory 
objectives. E.O. 13563 further emphasizes that regulations must be 
based on the best available science and that the rulemaking process 
must allow for public participation and an open exchange of ideas. ONRR 
developed this final rule in a manner consistent with these 
requirements.

B. Regulatory Flexibility Act

    The Regulatory Flexibility Act, 5 U.S.C. 601, et seq., generally 
requires Federal agencies to prepare a regulatory flexibility analysis 
for rules that are subject to the notice-and-comment rulemaking 
requirements under the APA if the rule would have a significant 
economic impact on a substantial number of small entities. See 5 U.S.C. 
601-612.
    For the changes to 30 CFR part 1206, this final rule would affect 
lessees of Federal oil and gas leases. For the changes to 30 CFR part 
1241, this final rule could affect alleged and actual violators of 
obligations under Federal and Indian mineral leases. Federal and Indian 
mineral lessees are, generally, companies classified under the North 
American Industry Classification System (``NAICS''), as follows:
     Code 2111, Oil and Gas Extraction; and
     Code 21211, Coal Mining.
    Under NAICS code classifications, a small company is one with fewer 
than 500 employees. ONRR estimates that there are approximately 1,208 
different lessees that submit royalty reports for Federal oil and gas 
leases and other Federal mineral leases to ONRR each month. Of these 
lessees, approximately 106 are not considered small businesses because 
they exceed the employee count threshold for small businesses. ONRR 
estimates that the remaining 1,102 lessees have fewer than 500 
employees and are therefore considered small businesses.
    As stated in the Summary of Royalty Impacts and Costs Table, shown 
above, this final rule would impact industry through an increase in 
royalties of approximately $64.6 million per year if the 2020 Rule had 
gone into effect. This rule causes no financial impact on industry 
because it is consistent with the 2016 Valuation Rule which is 
currently operative. Small businesses account for approximately eight 
percent of those royalties. Applying that percentage, ONRR estimates 
that this final rule would increase royalty payments made by small-
business lessees by approximately $5.2 million per year, or $4,690 per 
small business, on average. The extent of any royalty impact would vary 
between lessees due to, for example, differences in the revenues 
generated by a small business that is subject to royalties.
    Also stated above, this final rule would impact industry through a 
decrease in administrative costs of approximately $2.9 million per year 
and a first-year increase of $243,000, relative to a baseline in which 
the 2020 Rule goes into effect. Applying the eight percent small-
business share, ONRR estimates that this final rule would decrease 
administrative costs to small business lessees by approximately $207 
per year and by $189 in the first year.
    In 2020, ONRR collected $6.3 billion in royalties from Federal oil 
and gas leases. Applying the eight-percent share, ONRR estimates that 
small-business lessees paid $504 million in royalties in 2020. Most 
Federal oil and gas leases have a 12.5 percent royalty rate, resulting 
in an estimated $4 billion in total small-business lessee revenue from 
the production and sale of Federal oil and gas ($504 million divided by 
.125). Thus, on average, ONRR estimates that small-business lessees 
earn $3.6 million in revenue per year from the production and sale of 
Federal oil and gas ($4 billion divided by 1,102).
    The estimated increase in royalties ($4,690) and decrease in 
administrative

[[Page 54069]]

burden ($207) net to an increase in overall cost to 1,102 small 
businesses of $4,402 per year. As a percentage of average small-
business revenue, this final rule would increase costs to those 
entities by 0.12 percent ($4,402 divided by $3.6 million).
    According to the U.S. Census Bureau's 2017 Economic Census data, 
oil and gas lessees with 20 employees or less collected $2.1 million 
per year per entity. Taking the $4,402 discussed above, divided by $2.1 
million equals an estimated maximum impact of 0.2 percent of total 
revenue per year. Further, ONRR anticipates that the smallest entities 
would realize less of an increase in royalties because, for example, 
the changes to deepwater gathering and extraordinary processing 
allowances are capital-intensive operations in which small entities 
typically do not participate.
    In accordance with 5 U.S.C. 605, the head of the agency certifies 
that this final rule would have an impact on a substantial number of 
small entities, but the economic impact on those small entities would 
not be significant under the Regulatory Flexibility Act. Thus, ONRR did 
not prepare a Regulatory Flexibility Act Analysis nor is a Small Entity 
Compliance Guide required.

C. Small Business Regulatory Enforcement Fairness Act

    The 2020 Rule was not a major rule under Subtitle E of the Small 
Business Regulatory Enforcement Fairness Act of 1996. See 5 U.S.C. 
804(2). Therefore, this final rule is also not a major rule under 5 
U.S.C. 804(2). Like the 2020 Rule, ONRR anticipates that this final 
rule:
    (1) Will not have an annual effect on the economy of $100 million 
or more. ONRR estimates that, if the 2020 Rule had gone into effect, 
the cumulative effect on all of industry would have been a reduction in 
private cost of nearly $61.45 million per year, which is the sum of 
$64.6 million in decreased royalty payments and $2.85 million in 
additional costs due to increased administrative burdens. This net 
change in royalty payments would have been a transfer rather than a 
cost or cost savings. The Summary of Royalty Impacts and Costs Table, 
as shown above, demonstrates that this final rule's cumulative economic 
impact on industry, State and local governments, and the Federal 
Government is well below the $100 million threshold that the Federal 
Government uses to define a rule as having a significant impact on the 
economy;
    (2) will not cause a major increase in costs or prices for 
consumers, individual industries, Federal, State, or local government 
agencies, or geographic regions. Please see the data tables in the 
Regulatory Planning and Review (E.O. 12866 and E.O. 13563) at Section 
VI.A.; and
    (3) would not have significant adverse effects on competition, 
employment, investment, productivity, innovation, or the ability of 
United States-based enterprises to compete with foreign-based 
enterprises. ONRR estimates no significant adverse impacts to small 
business.

D. Unfunded Mandates Reform Act

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

E. Takings (E.O. 12630)

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

F. Federalism (E.O. 13132)

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

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

    This final rule complies with the requirements of E.O. 12988. 
Specifically, the final rule:
    (1) Meets the criteria of Section 3(a), which requires that ONRR 
review all regulations to eliminate errors and ambiguity to minimize 
litigation; and
    (2) meets the criteria of Section 3(b)(2), which requires that all 
regulations be written in clear language using clear legal standards.

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

    ONRR strives to strengthen its government-to-government 
relationship with Indian Tribes through a commitment to consultation 
with Indian Tribes and recognition of their right to self-governance 
and Tribal sovereignty. ONRR evaluated this final rule under the 
Department's consultation policy and the criteria in E.O. 13175 and 
determined that it does not have substantial direct effects on 
Federally-recognized Indian Tribes. Thus, consultation under ONRR's 
Tribal consultation policy is not required.
    ONRR reached this conclusion, in part, based on the consultations 
it conducted before the adoption of the 2016 Valuation Rule. At that 
time, ONRR held six Tribal consultations with the three Tribes (Navajo 
Nation, Crow Nation, and Hopi Tribe) for which ONRR collected and 
disbursed Indian coal royalties. Upon the conclusion of each 
consultation, ONRR and the Tribal partners determined that the 2016 
Valuation Rule would not have a substantial impact on any of the 
represented Tribes. With the exception of the Kayenta Mine located on 
the lands belonging to the Navajo Nation, which ceased production in 
2019, the circumstances relevant to the Indian coal leases have not 
changed since the prior consultations occurred. As with the 2016 
Valuation Rule and the 2020 Rule, ONRR's review of the royalty impact 
to Tribes from this final rule demonstrates that this final rule will 
not substantially impact any of the three Tribes. Further, the rule is 
not estimated to impact the royalty value of Indian coal.

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

    Certain collections of information require OMB's approval under the 
Paperwork Reduction Act. This final rule does not require any new or 
modify any existing information collections that are subject to OMB's 
approval. Thus, ONRR did not submit any new information collection 
requests to OMB related to this final rule.
    This final rule leaves intact the information collection 
requirements that OMB previously approved under OMB Control Numbers 
1012-0004, 1012-0005, and 1012-0010.

[[Page 54070]]

J. National Environmental Policy Act of 1970

    This final rule does not constitute a major Federal action 
significantly affecting the quality of the human environment. ONRR is 
not required to provide a detailed statement under NEPA because this 
action is categorically excluded under 43 CFR 46.210(c) and (i), as 
well as the Departmental Manual, part 516, section 15.4.D, which 
covers: ``(c) Routine financial transactions including such things as . 
. . audits, fees, bonds, and royalties . . . [and] (i) [p]olicies, 
directives, regulations, and guidelines . . . [t]hat are of an 
administrative, financial, legal, technical, or procedural nature.'' 
This final rule does not involve any of the extraordinary circumstances 
listed in 43 CFR 46.215 which require further analysis under NEPA.

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

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

L. Clarity of This Regulation

    E.O. 12866 (section 1(b)(12)), 12988 (section 3(b)(1)(B)), E.O. 
13563 (section 1(a)), and the Presidential Memorandum of June 1, 1998, 
require ONRR to write all rules in plain language. This means that the 
rules ONRR publishes must use:
    (1) Logical organization.
    (2) Active voice to address readers directly.
    (3) Clear language rather than jargon.
    (4) Short sections and sentences.
    (5) Lists and tables wherever possible.
    If you believe that ONRR has not met these requirements, send your 
comments to onrr.gov">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 have been useful.

M. Congressional Review Act

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

Rachael S. Taylor,
Principal Deputy Assistant Secretary--Policy, Management and Budget.
[FR Doc. 2021-20979 Filed 9-28-21; 11:15 am]
BILLING CODE 4335-30-P