Rule2021-20979
ONRR 2020 Valuation Reform and Civil Penalty Rule: Final Withdrawal Rule
Primary source
Metadata and text below are from the Federal Register, a public-domain U.S. government work. Always verify the official published version before relying on it for any legal matter.
Published
September 30, 2021
Effective
November 1, 2021
Issuing agencies
Interior DepartmentNatural Resources Revenue Office
Abstract
ONRR is withdrawing the ONRR 2020 Valuation Reform and Civil Penalty Rule ("2020 Rule").
Full Text
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<title>Federal Register, Volume 86 Issue 187 (Thursday, September 30, 2021)</title>
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[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 [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[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withdrawn.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
<a href="/cdn-cgi/l/email-protection#7b3435292924291e1c0e171a0f12141508361a12171914033b471a5b13091e1d46" http: onrr.gov">onrr.gov</a>">ONRR_RegulationsMailbox@<a href="http://onrr.gov">onrr.gov</a></a>, or by telephone (303) 231-3418.
SUPPLEMENTARY INFORMATION:
Table of Abbreviations and Commonly Used Acronyms in This Rule
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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, <a href="https://www.bsee.gov/what-we-do/conservation/gulf-of-mexico-deepwater-province/special-case-royalty-relief-overview">https://www.bsee.gov/what-we-do/conservation/gulf-of-mexico-deepwater-province/special-case-royalty-relief-overview</a>. 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 <a href="https://www.blm.gov/programs/energy-and-minerals/helium/division-of-helium-resources">https://www.blm.gov/programs/energy-and-minerals/helium/division-of-helium-resources</a> (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), <a href="https://dog.dnr.alaska.gov/Documents/Leasing/SaleDocuments/AKPeninsula/2016/LeaseForm-DOG201503.pdf">https://dog.dnr.alaska.gov/Documents/Leasing/SaleDocuments/AKPeninsula/2016/LeaseForm-DOG201503.pdf</a>, 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), <a href="https://lands.wyo.gov/trust-land-management/mineral-leasing/oil-gas-leases">https://lands.wyo.gov/trust-land-management/mineral-leasing/oil-gas-leases</a>,
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
<a href="http://onrr.gov">onrr.gov</a>. 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 (``CO<INF>2</INF>''), 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 CO<INF>2</INF> 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 CO<INF>2</INF> 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 <a href="https://revenuedata.doi.gov/how-it-works/gomesa/">https://revenuedata.doi.gov/how-it-works/gomesa/</a>), 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 <a href="https://revenuedata.doi.gov/explore/#federal-disbursements">https://revenuedata.doi.gov/explore/#federal-disbursements</a>.
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:
<bullet> Code 2111, Oil and Gas Extraction; and
<bullet> 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 <a href="/cdn-cgi/l/email-protection#fbb4b5a9a9a4a99e9c8e979a8f92949588b69a9297999483bbc79adb93899e9dc6" http: onrr.gov">onrr.gov</a>">ONRR_RegulationsMailbox@<a href="http://onrr.gov">onrr.gov</a></a>. 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
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This is legal information, not legal advice. Laws vary by jurisdiction and change frequently. Always verify current law with official sources and consult a licensed attorney in your jurisdiction for advice on your specific situation.