31196 Federal Register / Vol. 86, No. 111 / Friday, June 11, 2021 / Proposed Rules 

71.00.21 Rev 1, as applicable to your 

helicopter model and version, is acceptable 

for compliance with the requirement of this 

paragraph. The action required by this 

paragraph may be performed by the owner/ 

operator (pilot) holding at least a private pilot 

certificate and must be entered into the 

aircraft records showing compliance with 

this AD in accordance with § 43.9(a)(1) 

through (4) and § 91.417(a)(2)(v). The record 

must be maintained as required by § 91.417, 

§ 121.380, or § 135.439. 

(2) Install a placard in full view of the pilot 

and co-pilot by following the 

Accomplishment Instructions, paragraph 

3.B., of ASB AS355–71.00.21 Rev 1. 

Note 1 to paragraph (g)(2): Airbus 

Helicopters service information refers to a 

placard as a label. 

(h) Special Flight Permits 

Special flight permits are permitted so long 

as continuous engine operation between 71 

and 88% N2 is avoided. 

(i) Alternative Methods of Compliance 

(AMOCs) 

(1) The Manager, International Validation 

Branch, FAA, has the authority to approve 

AMOCs for this AD, if requested using the 

procedures found in 14 CFR 39.19. In 

accordance with 14 CFR 39.19, send your 

request to your principal inspector or local 

Flight Standards District Office, as 

appropriate. If sending information directly 

to the manager of the International Validation 

Branch, send it to the attention of the person 

identified in paragraph (j)(1) of this AD. 

Information may be emailed to: 9-AVS-AIR730-AMOC@faa.gov. 

(2) Before using any approved AMOC, 

notify your appropriate principal inspector, 

or lacking a principal inspector, the manager 

of the local flight standards district office/ 

certificate holding district office. 

(j) Related Information 

(1) For more information about this AD, 

contact Michael Hughlett, Aerospace 

Engineer, General Aviation & Rotorcraft 

Section, International Validation Branch, 

FAA, 10101 Hillwood Pkwy., Fort Worth, TX 

76177; telephone (817) 222–5110; email 

michael.hughlett@faa.gov. 

(2) For service information identified in 

this AD, contact Airbus Helicopters, 2701 

North Forum Drive, Grand Prairie, TX 75052; 

telephone (972) 641–0000 or (800) 232–0323; 

fax (972) 641–3775; or at https://

www.airbus.com/helicopters/services/ 

technical-support.html. You may view this 

referenced service information at the FAA, 

Office of the Regional Counsel, Southwest 

Region, 10101 Hillwood Pkwy., Room 6N– 

321, Fort Worth, TX 76177. For information 

on the availability of this material at the 

FAA, call (817) 222–5110. 

(3) The subject of this AD is addressed in 

European Union Aviation Safety Agency 

(EASA) AD 2020–0266, dated December 8, 

2020. You may view the EASA AD on the 

internet at https://www.regulations.gov in 

Docket No. FAA–2021–0460. 

Issued on June 6, 2021. 

Lance T. Gant, 

Director, Compliance & Airworthiness 

Division, Aircraft Certification Service. 

[FR Doc. 2021–12226 Filed 6–10–21; 8:45 am] 

BILLING CODE 4910–13–P 

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: Notification of Proposed 

Withdrawal 

AGENCY: Office of Natural Resources 

Revenue (‘‘ONRR’’), Interior. 

ACTION: Proposed rule; request for 

comments. 

SUMMARY: ONRR is proposing to 

withdraw the final rule entitled ‘‘ONRR 

2020 Valuation Reform and Civil 

Penalty Rule’’ (‘‘2020 Rule’’). This 

action opens a 60-day comment period 

to allow interested parties to comment 

on ONRR’s proposed withdrawal of the 

2020 Rule. 

DATES: The final rule published on 

January 15, 2021, at 86 FR 4612, which 

was delayed at 86 FR 9286 on February 

12, 2021, and 86 FR 20032 on April 16, 

2021, is proposed to be withdrawn. To 

be assured consideration, comments 

must be received at one of the addresses 

provided below by 11:59 p.m. EST on 

August 10, 2021. 

ADDRESSES: You may submit comments 

to ONRR using one of the following two 

methods. Please reference the 

Regulation Identifier Number (‘‘RIN’’) 

for this action, ‘‘RIN 1012–AA27,’’ in 

your comment: 

• Electronically via the Federal 

eRulemaking Portal: Please visit https:// 

www.regulations.gov. In the Search Box, 

enter Docket ID ‘‘ONRR–2020–0001’’ 

and click ‘‘search’’ to view the 

publications associated with the docket 

folder. Locate the document with an 

open comment period and then click 

‘‘Comment.’’ Follow the instructions to 

submit your public comments prior to 

the close of the comment period. 

• Email Submissions: Please submit 

your comments via email at ONRR_

RegulationsMailbox@onrr.gov with 

‘‘RIN 1012–AA27’’ listed in the subject 

line of your message. Email submissions 

must be postmarked on or before the 

close of the comment period. 

Instructions: All comments must 

include the agency name and docket 

number or RIN for this rulemaking. All 

comments, including any personal 

identifying information or confidential 

business information contained in a 

comment, will be posted without 

change to https://www.regulations.gov. 

Docket: For access to the docket to 

read background documents or 

comments received, go to https://

www.regulations.gov and locate the 

docket folder by searching the Docket ID 

(ONRR–2020–0001) or RIN number (RIN 

1012–AA27). 

FOR FURTHER INFORMATION CONTACT: For 

questions, contact Luis Aguilar, 

Regulatory Specialist, at (303) 231–3418 

or by email at ONRR_

RegulationsMailbox@onrr.gov. 

SUPPLEMENTARY INFORMATION: 

TABLE OF ABBREVIATIONS AND COMMONLY USED ACRONYMS IN THIS PROPOSED RULE

Abbreviation What it means 

2016 Valuation Rule ............................. ONRR’s Consolidated Federal Oil and Gas and Federal and Indian Coal Valuation Reform Rule, 81 FR 

43338 (July 1, 2016). 

2016 Civil Penalty Rule ........................ ONRR’s Amendments to Civil Penalty Regulations, 81 FR 50306 (August 1, 2016). 

2017 Repeal Rule ................................ ONRR’s Repeal of the 2016 Valuation Rule, 82 FR 36934 (August 7, 2017). 

ALJ ....................................................... Administrative Law Judge. 

APA ...................................................... Administrative Procedure Act of 1946, as amended. 

API ........................................................ American Petroleum Institute. 

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’s May 20, 1999, memorandum entitled ‘‘Guidance for Determining Transportation Allowances for 

Production from Leases in Water Depths Greater Than 200 Meters’’. 


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Federal Register / Vol. 86, No. 111 / Friday, June 11, 2021 / Proposed Rules 31197 

TABLE OF ABBREVIATIONS AND COMMONLY USED ACRONYMS IN THIS PROPOSED RULE—Continued 

Abbreviation What it means 

DOI ....................................................... U.S. Department of the Interior. 

E.O. ...................................................... Executive Order. 

FERC .................................................... Federal Energy Regulatory Commission. 

2020 Rule ............................................. ONRR 2020 Valuation Reform and Civil Penalty Rule, 86 FR 4612 (January 15, 2021). 

First Delay Rule .................................... ONRR 2020 Valuation Reform and Civil Penalty Rule: Delay of Effective Date and 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.. 

GOM ..................................................... Gulf of Mexico. 

MLA ...................................................... Mineral Leasing Act of 1920, 30 U.S.C. 181, et seq.. 

MMS ..................................................... Minerals Management Service. 

NEPA .................................................... National Environmental Policy Act of 1970. 

NGL ...................................................... Natural Gas Liquids. 

OCS ...................................................... Outer Continental Shelf. 

OCSLA ................................................. Outer Continental Shelf Lands Act of 1953, 43 U.S.C. 1331, et seq. 

ONRR ................................................... Office of Natural Resources Revenue. 

Proposed 2020 Rule ............................ ONRR 2020 Valuation Reform and Civil Penalty Rule, Proposed Rule, 85 FR 62054 (October 1, 2020). 

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 U.S. Department of the Interior. 

S.O. ...................................................... Secretarial Order. 

I. Introduction 

A. Statutory Authority 

Through the enactment of various 

mineral leasing laws, Congress 

authorized the Secretary to issue and 

administer leases to allow for the 

exploration, development, and 

production of mineral resources from 

Federal and Indian lands and the OCS. 

These laws include, for onshore lands, 

the MLA, for offshore lands, the OCSLA, 

and for Indian and allotted lands, 25 

U.S.C. 396, et seq. The Secretary has 

delegated the statutory authority to 

lease, permit, and inspect mineral 

extraction activities on those lands to 

several bureaus and offices. 

The Secretary is also responsible for 

collecting, accounting for, and 

disbursing royalties and other financial 

obligations related to the leasing, 

production, and sale of minerals from 

Federal and Indian lands. Mineral 

leasing laws, regulations, and lease 

terms establish royalty rates and other 

obligations that a lessee must pay to the 

United States or Indian lessor. Relevant 

to this rulemaking, see, e.g., 25 U.S.C. 

396a–g, 400a; 30 U.S.C. 207(a), 226(b)(1) 

(MLA); 43 U.S.C. 1337(a)(1) (OCSLA); 

25 CFR 211.43; 43 CFR 3103.3–1, 43 

CFR 3473.3–2. 

Congress enacted FOGRMA to further 

clarify and establish the Secretary’s 

responsibilities with respect to royalty 

management. Through FOGRMA, 

Congress directed the Secretary ‘‘to 

improve methods of accounting for such 

royalties and payments’’ and required 

‘‘the development of enforcement 

practices that ensure the prompt and 

proper collection and disbursement of 

oil and gas revenues owed to the United 

States and Indian lessors and those 

inuring to the benefit of States.’’ 30 

U.S.C. 1701(a)(3) and (b)(3). 

Over the years, royalty management 

responsibilities have been transferred 

within DOI and in 2010, following the 

reorganization of MMS, ONRR was 

created. The Secretary delegated 

authority to ONRR to carry out its 

responsibilities specific to ‘‘royalty and 

revenue collection, distribution, 

auditing and compliance, investigation 

and enforcement, and asset management 

for both onshore and offshore 

activities.’’ S.O. 3299, Sec. 5 (August 29, 

2011); see also S.O. 3306 (September 30, 

2010). Pursuant to FOGRMA, the 

mineral leasing acts, and the authority 

delegated by the Secretary, ONRR has 

adopted regulations specifying the 

methods to be used to determine the 

value of Federal and Indian mineral 

production for royalty purposes. 

ONRR’s responsibilities are distinct 

from other DOI offices and bureaus and 

pertain specifically to the collection, 

verification, and disbursement of 

royalty revenue realized from 

production of natural resources on 

Federal and Indian lands and the OCS. 

See 30 CFR 1201.100. 

FOGRMA and the mineral leasing 

laws grant the Secretary broad 

rulemaking authority to carry out and 

accomplish the purposes set forth in the 

governing statutes. See 30 U.S.C. 189 

(MLA); 30 U.S.C. 1751 (FOGRMA); and 

43 U.S.C. 1334 (OCSLA). In turn, the 

Secretary delegated rulemaking 

authority specific to ONRR’s portfolio of 

responsibilities to ONRR. See S.O. 3299, 

sec. 5 and S.O. 3306, sec. 3–4. 

B. Rulemaking History 

1. The 2020 Proposed Rule 

On October 1, 2020, ONRR published 

the Proposed 2020 Rule. The Proposed 

2020 Rule proposed to amend certain 

regulations that inform the manner in 

which ONRR values oil and gas 

produced from Federal leases for royalty 

purposes; values coal produced from 

Federal and Indian leases for royalty 

purposes; and assesses civil penalties 

for violations of certain statutes, 

regulations, lease terms, and orders 

associated with mineral leases. The 

Proposed 2020 Rule stated its purposes 

were to: Align the 2016 Valuation Rule 

with certain E.O.s issued after the 2016 

Valuation Rule’s publication date; 

address some of the amendments in the 

2016 Valuation Rule asserted to be 

controversial and problematic; simplify 

processes and provide early clarity 

regarding royalties owed; better explain 

ONRR’s civil penalty practices; and 

return certain provisions to the 

framework that had existed for decades 

prior to the 2016 Valuation Rule and 

2016 Civil Penalties Rule. 

The 60-day comment period for the 

Proposed 2020 Rule closed on 

November 30, 2020. ONRR received 

comments from numerous industry 

members, trade associations, public 

interest groups, members of Congress, 

members of the public, and State and 

local entities. ONRR received 36 unique 

comment submissions totaling to 40,456 

pages of comment materials, of which 

38,150 pages were a one-page form 

comment. 


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31198 Federal Register / Vol. 86, No. 111 / Friday, June 11, 2021 / Proposed Rules 

2. The 2020 Rule 

On January 15, 2021, 46 days after the 

close of the comment period, ONRR 

published the 2020 Rule. The 2020 Rule 

adopted amendments on 15 topics, 

generally summarized as: 

1. Deepwater gathering—allowing 

certain gathering costs to be deducted as 

part of a lessee’s transportation 

allowance for Federal oil and gas 

produced on the OCS at water depths 

greater than 200 meters. 

2. Extraordinary processing 

allowances—allowing a lessee to apply 

for approval to claim an extraordinary 

processing allowance for Federal gas in 

situations where the gas stream, plant 

design, and/or unit costs are 

extraordinary, unusual, or 

unconventional relative to standard 

industry conditions and practice. 

3. Default provision—removed the 

default provision and references thereto 

from the Federal oil and gas and Federal 

and Indian coal regulations. The default 

provision established criteria limiting 

how ONRR will exercise the Secretary’s 

authority to establish royalty value 

when typical valuation methods are 

unavailable, unreliable, or unworkable. 

4. Misconduct—removed the 

misconduct definition from 30 CFR 

1206.20. 

5. Signed contracts—removed the 

requirement that a lessee have contracts 

signed by all parties. 

6. Citation to legal precedent— 

eliminated the requirement for a lessee 

to cite legal precedent when seeking a 

valuation determination. 

7. Arm’s-length valuation option— 

adopted an index-based valuation 

option for arm’s-length Federal gas 

sales. 

8. Change in indices to be used in 

index-based valuation options— 

changed from the high index price to 

the average index price. 

9. Standard deduction for 

transportation allowance—amended the 

standard deduction included in the 

index-based valuation method to reflect 

more recent average transportation cost 

data. 

10. Valuation of coal based on 

electricity sales—removed the 

requirement to value certain Federal 

and Indian coal based on the sales price 

of electricity. 

11. Coal cooperative—removed the 

definition of ‘‘coal cooperative’’ and the 

method to value sales between members 

of a ‘‘coal cooperative’’ for Federal and 

Indian coal. 

12. Facts considered in penalizing 

payment violations—modified ONRR’s 

civil penalty regulations to specify that 

ONRR considers unpaid, underpaid, or 

late payment amounts in the severity 

analysis for payment violations only. 

13. Consideration of aggravating and 

mitigating circumstances—modified 

ONRR’s civil penalty regulations to 

specify that ONRR may consider 

aggravating and mitigating 

circumstances when calculating the 

amount of a civil penalty. 

14. Conforming civil penalty 

regulations to court decision—removed 

a provision permitting an ALJ to vacate 

a previously-granted stay of an accrual 

of penalties if the ALJ later determines 

that a violator’s defense to a notice of 

noncompliance was frivolous. 

15. Non-substantive corrections— 

amended various regulations by making 

non-substantive corrections. 

The 2020 Rule did not adopt 

amendments on three topics discussed 

in the Proposed 2020 Rule: 

1. Regulatory caps on transportation 

allowances for Federal oil and gas. See 

86 FR 4613. 

2. Regulatory caps on processing 

allowances for Federal gas. See 86 FR 

4614. 

3. Shallow water gathering. See 86 FR 

4614. 

The effective date of the 2020 Rule 

was originally February 16, 2021. For 

amendments to 30 CFR part 1206 only, 

the 2020 Rule established a compliance 

date of May 1, 2021. 

3. The First Delay Rule 

On January 20, 2021, the Assistant to 

the President and Chief of Staff issued 

a memorandum entitled ‘‘Regulatory 

Freeze Pending Review’’ which, along 

with the Office of Management and 

Budget (‘‘OMB’’) January 20, 2021, 

Memorandum M–21–14, directed 

agencies to consider a delay of the 

effective date of rules published in the 

Federal Register that had not yet 

become effective and to invite public 

comment on issues of fact, law, and 

policy raised by those rules (86 FR 7424, 

January 28, 2021). 

On February 12, 2021, ONRR 

published the First Delay Rule which 

initially delayed by 60 days the effective 

date of the 2020 Rule, opened a 30-day 

comment period on the facts, law, and 

policy underpinning the 2020 Rule, as 

well as on the impact of a delay in the 

effective date of the 2020 Rule. In 

response, ONRR received 13 comment 

submissions totaling to 1,339 pages of 

comment materials, many of which 

were submitted by the same 

organizations that had commented on 

the Proposed 2020 Rule. 

4. The Second Delay Rule 

After the close of the First Delay 

Rule’s comment period, ONRR 

determined that an additional delay of 

the 2020 Rule’s effective date was 

needed. Thus, on April 16, 2021, ONRR 

published a second final rule which 

further delayed the effective date until 

November 1, 2021 (the ‘‘Second Delay 

Rule’’). 

The Second Delay Rule listed 15 

potential defects or shortcomings 

identified by ONRR in its initial 

reexamination of the 2020 Rule and in 

comments received in response to the 

First Delay Rule. 86 FR 20032. It also 

addressed public comments received on 

the impacts of delay of the effective date 

of the 2020 Rule. 

II. Basis for Proposed Action 

ONRR is proposing to withdraw the 

2020 Rule because the process used for 

its adoption arguably was without 

observance of procedure required by 

law, as well as in excess of ONRR’s 

statutory authority. See 5 U.S.C. 

706(2)(C), (D). While a complete 

withdrawal of the 2020 Rule may be 

warranted, ONRR requests public 

comment on potential alternatives in 

Section IV of this rule. For example, 

alternative outcomes following this 

proposed rule’s notice could include: 

Allowing the 2020 Rule to go into effect, 

a withdrawal limited to some or all of 

the 2020 Rule’s amendments to 30 CFR 

part 1206, a withdrawal limited to some 

or all of the 2020 Rule’s revenueimpacting amendments, a withdrawal 

limited to some or all of the 2020 Rule’s 

amendments to part 1241, or some 

combination thereof. ONRR 

acknowledges the importance of public 

participation as part of the rulemaking 

process. As such, this rule explains 

potential deficiencies in the 2020 Rule 

and invites public comment on the 

proposed withdrawal and new findings 

considered as part of this reevaluation. 

Following the close of this rule’s 

comment period, ONRR will consider 

all relevant information submitted 

through public comment and determine 

the appropriate course of action. 

A. APA Defects That Go to the Entirety 

of the 2020 Rule 

The 2020 Rule may be deficient under 

the APA for the following reasons. 

1. Adequacy of the Comment Period 

Though the 2016 Valuation Rule 

included a public comment period of 

120 days, the 2020 Rule included a 

public comment period of just 60 days. 

In litigation construing ONRR’s reversal 

of major policies adopted in the 2016 

Valuation Rule, the District Court found 

that ONRR failed to provide meaningful 

opportunity for comment when it 

enacted the reversal without a comment 


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Federal Register / Vol. 86, No. 111 / Friday, June 11, 2021 / Proposed Rules 31199 

1California v. U.S. Dep’t of the Interior, 381 F. 

Supp. 3d 1153, 1177–78 (N.D. Cal. 2019) (‘‘ONRR’s 

failure to provide a meaningful opportunity to 

comment is underscored by the brevity of the 

comment period. While there is no bright-line test 

for the minimum amount of time allotted for the 

comment period, at least one circuit has recognized 

that 90 days is the ‘usual’ amount of time allotted 

for a comment period. In cases involving the repeal 

of regulations, courts have considered the length of 

the comment period utilized in the prior 

rulemaking process as [ ] well as the number of 

comments received during that time-period. In the 

instant case, a comparison between the ONRR’s 

rulemaking process leading to the Valuation Rule 

and the process used to repeal it exemplifies the 

ONRR’s failure to provide for a meaningful 

rulemaking process. . . . In contrast to the years of 

consideration leading to the promulgation of the 

Valuation Rule, the ONRR’s actions to repeal it took 

place in a matter of months. Whereas the ONRR 

provided a 120-day comment period for the draft 

Valuation Rule, the ONRR allowed only a 30-day 

comment period to consider its repeal. . . . Based 

on the record presented, the Court finds that the 

ONRR failed to provide meaningful opportunity for 

comment.’’ (citations omitted)). 

2 Id. at 1168–69 (‘‘When considering revoking a 

rule, an agency must consider alternatives in lieu 

of a complete repeal, such as by addressing the 

deficiencies individually. In response to the 

Proposed Repeal, the ONRR received comments 

suggesting that in lieu of complete repeal of the 

Valuation Rule, the ONRR should address specific 

problems ‘separately and not entirely abandon the 

rule in its entirety.’ The ONRR responded that ‘[t]he 

cost of implementing the rule and subsequently 

trying to fix the defects in one or more separate 

rulemakings would far exceed the cost of repealing 

and replacing the rule.’ That conclusory 

statement—unsupported by facts, reasoning or 

analysis—is legally insufficient.’’). 

3Even if ONRR’s failure to fully explain its 

proposed action only affected the validity of certain 

amendments, a court may vacate an entire rule if 

it is not feasible to keep only the valid sections. See 

High Country Conservation Advocates v. U.S. Forest 

Serv., 951 F.3d 1217, 1228–29 (10th Cir. 2020) 

(holding that a court may only partially set aside 

a regulation if the invalid portion is severable, that 

is if the severed parts operate entirely 

independently of one another, and the 

circumstances indicate the agency would have 

adopted the regulations even without the faulty 

provision); see also Wyoming v. U.S. Dep’t of the 

Interior, 493 F. Supp. 3d 1046 (D. Wyo. 2020) 

(holding that the remainder of the BLM’s rule 

provisions could not function independently and 

vacating the entire rule.). 

4California, 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)). 

5See footnote 4. 

6California, 381 F. Supp 3d at 1168 (citing 

Encino Motorcars, LLC v. Navarro, 136 S. Ct. 2117, 

2126 (2016)). The District Court further found that, 

in its 2017 repeal, ONRR completely contradict[ed] 

its prior findings. Despite its previous, detailed 

conclusions in support of the Valuation Rule’s 

approach to valuing non-arm’s-length coal 

transactions—and dismissing the industry’s 

criticisms thereof—the ONRR now finds the 

approach prescribed in the Valuation Rule to be 

‘‘unnecessarily complicated and burdensome to 

implement and enforce.’’ Likewise, in contrast to its 

prior criticisms of the benchmarks, the ONRR now 

lauds the benchmark system as ‘‘proven and timetested,’’ as well as ‘‘reasonable, reliable, and 

consistent.’’ Although the ONRR is entitled to 

change its position, it must provide ‘‘a reasoned 

explanation . . . for disregarding facts and 

circumstances that underlay or were engendered by 

the prior policy’’ . . . . The Court finds that the 

ONRR’s conclusory explanation in the Final Repeal 

fails to satisfy its obligation to explain the 

inconsistencies between its prior findings in 

enacting the Valuation Rule and its decision to 

repeal such Rule. The ONRR’s repeal of the 

Valuation Rule is therefore arbitrary and capricious. 

Id. at 1167–68 (citations omitted). 

period of commensurate length. 

Specifically, the District Court found 

that the 30-day comment period used 

for the 2017 repeal of the 2016 

Valuation Rule was too brief when 

ONRR had a much longer comment 

period for the 2016 Valuation Rule— 

approximately 120 days.1 Here, though 

ONRR did allow for more than 30 days 

of comment on the 2020 Rule, as with 

the repeal of the 2016 Valuation Rule, 

ONRR may still have deprived the 

public of an adequate period within 

which to comment. 

2. Consideration of Alternatives 

The Proposed 2020 Rule does not 

demonstrate that ONRR considered 

alternatives to the repeal of select 

regulations adopted in the 2016 

Valuation Rule and, to a lesser extent, 

its 2016 Civil Penalty Rule. For 

example, the 2020 Rule did not discuss 

alternatives to the repeal of the 

definition of misconduct or the 

requirement of signed contracts, among 

other less controversial changes. This 

again resembles ONRR’s 2017 attempt to 

repeal the 2016 Valuation Rule, where 

the District Court found that ONRR did 

not discuss alternatives to a full repeal 

of the 2016 Valuation Rule and 

explained that an agency must discuss 

alternatives even if the agency is 

repealing less than an entire 

rulemaking.2

3. Lack of ‘‘Reasoned Explanation’’ for 

Proposed Rule Denies the Public an 

Opportunity To Comment 

In the Proposed 2020 Rule, ONRR 

may not have fully explained why it 

was proposing certain substantive 

amendments.3 The District Court noted 

a similar flaw in ONRR’s 2017 proposal 

to repeal the 2016 Valuation Rule, 

finding that ONRR did not identify the 

reasons supporting its proposed repeal.4

Specifically, ONRR’s Proposed 2020 

Rule may not have fully described the 

reasons why it was proposing to return 

to some of the ‘‘historical practices’’ or 

adopting other changes, including: (1) 

When production is completed offshore 

in waters 200 meters and deeper, 

allowing a lessee to report and claim 

certain gathering costs in its 

transportation allowances; (2) extension 

of index-based valuation to arm’s-length 

sales of Federal gas; and (3) lowering of 

the index, from the highest bidweek 

price to an average bidweek price, for 

valuation of non-arm’s-length sales of 

Federal gas. While the Proposed 2020 

Rule identified the proposed changes, 

discussed the anticipated economic 

impact of the changes, and set forth the 

language of the proposed amendments, 

ONRR could have more fully discussed 

why the changes were being proposed. 

Moreover, for the changes that were 

reverting to ‘‘historical practices’’ (i.e., 

those existing before the 2016 Valuation 

Rule was adopted), ONRR did not fully 

explain why it was reverting to practices 

it had rejected in its last substantive 

rulemaking. Thus, the Proposed 2020 

Rule may not have provided sufficient 

notice of the reasons for the substantive 

proposed changes to be adopted through 

the 2020 Rule such that the public was 

not provided with a meaningful 

opportunity to comment. 

4. Failure to Adequately Justify Change 

in Recently Adopted Policy 

At the time the Proposed 2020 Rule 

was published, the 2016 Valuation Rule 

had been in force for only seventeen 

months (from March 29, 2019 when the 

repeal of the 2016 Valuation Rule was 

overturned to October 1, 2020) and full 

compliance with that rule had been 

delayed by the series of Dear Reporter 

letters to October 1, 2020. Given that the 

Proposed 2020 Rule was, in many 

instances, an attempt to return to the 

valuation rules that existed prior to the 

2016 Valuation Rule, ONRR should 

have included justifications for the 

proposed changes in the Proposed 2020 

Rule. In addition, ONRR should have 

explained the inconsistencies between 

the 2016 Valuation Rule and the 

amendments described in the Proposed 

2020 Rule and, in addition, adequately 

explained its potential rejection of the 

position under which the agency and 

the regulated public had been operating 

for only a brief period of time.5

In considering ONRR’s 2017 attempt 

to repeal its 2016 Valuation Rule, the 

District Court similarly concluded that 

ONRR did not provide ‘‘a reasoned 

explanation . . . for disregarding facts 

and circumstances that underlay or 

were engendered by the prior policy.’’ 6

Here too, the APA may have been 

violated by ONRR’s failure to offer a 

reasoned explanation for the proposed 

amendments and its failure to describe 

why it was disregarding the findings in 

the 2016 Valuation Rule in favor of 


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7Bowen v. Georgetown Univ. Hosp., 488 U.S. 204, 

208 (1988) (‘‘It is axiomatic that an administrative 

agency’s power to promulgate legislative 

regulations is limited to the authority delegated by 

Congress.’’); Food & Drug Admin. v. Brown & 

Williamson Tobacco Corp., 529 U.S. 120, 125 (2000) 

(‘‘Regardless of how serious the problem an 

administrative agency seeks to address, . . . it may 

not exercise its authority ’in a manner that is 

inconsistent with the administrative structure that 

Congress enacted into law.’ ’’). 

reverting to prior policy after only a 

brief period of time operating under the 

2016 Valuation Rule. 

Moreover, the justification offered in 

the 2020 Rule, in some instances, could 

be interpreted as relying on matters 

outside of ONRR’s primary area of 

expertise—matters that were not 

signaled in the proposed rule. Since the 

explanation for its action was offered 

only in the 2020 Rule, and not in the 

Proposed 2020 Rule, members of the 

public may have been deprived of an 

opportunity to comment, as they were 

unlikely to anticipate that ONRR would 

cite external justification for the 2020 

Rule. 

B. APA and Other Defects That Go to 

Portions of the 2020 Rule 

Part A above explains four potential 

defects in the 2020 Rule. In addition to 

these defects, ONRR also believes it may 

have promulgated certain amendments 

in excess of the authority delegated to 

it, as explained below.7 The sum of 

these defects may warrant withdrawal of 

the entire 2020 Rule. 

Because ONRR is considering 

alternatives to complete withdrawal of 

the 2020 Rule, this section provides 

information regarding additional, 

amendment-specific problems which 

may warrant the withdrawal of some but 

not all of the 2020 Rule. The 

amendments covered in this Part B are: 

(1) Deepwater gathering allowances; (2) 

extraordinary processing allowances; (3) 

index-based valuation for arm’s-length 

sales; (4) modification of the index price 

used in index-based valuation; and (5) 

increasing the reduction to the index 

price used in index-based valuation to 

account for transportation expenses. 

Collectively, these five are referred to as 

the revenue-impacting provisions of the 

2020 Rule. 

1. ONRR’s Role in Incentivizing 

Production 

Since the 2020 Rule adopted each of 

these five revenue-impacting 

amendments to, in part, incentivize 

production by reducing royalties an oil 

and gas lessee would otherwise owe the 

United States, this section begins by 

discussing incentivization of production 

before turning to matters specific to 

individual revenue-impacting 

amendments. 

a. Secretarial Authorities Delegated to 

ONRR Do Not Include Incentivizing 

Production 

In response to the Proposed 2020 

Rule, some commenters noted that 

ONRR based the proposed rule on 

incentivizing or increasing Federal 

production despite the fact that ONRR 

has no explicit mandate to increase 

production. In the 2020 Rule, ONRR 

disagreed with the commenter and 

responded by stating that it shared in 

DOI’s goal of managing Federal 

resources on the OCS. See 86 FR 4623. 

It is true that Congress has established 

official policy that ‘‘the Outer 

Continental Shelf is a vital national 

resource reserve held by the Federal 

Government for the public, which 

should be made available for 

expeditious and orderly development, 

subject to environmental safeguards, in 

a manner which is consistent with the 

maintenance of competition and other 

national needs.’’ 43 U.S.C. 1332(3). This 

broad directive, framed primarily by the 

overarching requirement that DOI 

conduct leasing activities ‘‘to assure 

receipt of fair market value for the lands 

leased and the rights conveyed by the 

Federal Government,’’ 43 U.S.C. 

1344(a)(4), provides the Secretary with 

broad discretion to emphasize varying 

components of OCLSA’s objectives. 

Similarly, with respect to the royalty 

management program specifically, the 

Secretary has the authority to ‘‘prescribe 

such rules and regulations as he deems 

reasonably necessary to carry out this 

chapter’’ under FOGRMA, 30 U.S.C. 

1751(a). 

Notably, however, ONRR has 

reconsidered its responsibilities and 

determined that they are much narrower 

than the 2020 Rule suggested. ONRR 

was established, together with BOEM 

and BSEE, to purposefully separate and 

reassign the responsibilities of the 

former MMS in order to improve 

management, oversight, and 

accountability of activities on the OCS, 

ensure a fair return to the public from 

royalty and revenue collection and 

disbursement activities, and provide 

independent safety and environmental 

oversight and enforcement of offshore 

activities. See S.O. 3299 (May 19, 2010) 

and S.O. 3306 (Sept. 30, 2010). Under 

these S.O.s, ONRR is specifically 

responsible for managing royalty and 

revenue collection, distribution, 

auditing and compliance, investigation 

and enforcement, and asset management 

for both onshore and offshore activities. 

Id. Consistent with the S.O.s, ONRR is 

primarily responsible for carrying out 

the Secretary’s duty to ‘‘establish a 

comprehensive inspection, collection 

and fiscal and production accounting 

and auditing system to provide the 

capability to accurately determine oil 

and gas royalties, interest, fines, 

penalties, fees, deposits, and other 

payments owed, and to collect and 

account for such amounts in a timely 

manner’’ under 30 U.S.C. 1711(a). 

Unlike most agencies within DOI, ONRR 

has no organic statute and the role of 

ONRR under S.O. 3299 and S.O. 3306 is 

narrowly focused on the accounting and 

auditing activities that form the bedrock 

of ONRR’s responsibilities. Thus, 

questions exist regarding the scope of 

ONRR’s authority and the range of 

activities that have been assigned or 

delegated to it. 

The need to separate the auditing and 

accounting responsibilities from the 

planning and leasing activities was one 

of the primary stated purposes for the 

dissolution of the former MMS and the 

creation of BOEM, BSEE, and ONRR. 

MMS was divided into the three 

separate bureaus and offices to separate 

conflicting missions. See https://

www.doi.gov/news/pressreleases/ 

Salazar-Divides-MMSs-ThreeConflicting-Missions. Among other 

things, the establishment of ONRR in 

the Office of the Assistant Secretary for 

Policy Management and Budget, 

‘‘centralize[d] the collection and 

management of revenues from energy 

development on our public lands and 

oceans, which strengthens the ability of 

employees to independently and 

rigorously carry out their revenue 

management responsibilities, and 

ensures better protection of American 

taxpayer interests.’’ See July 15, 2011 

Statement of the Director of the Office 

of Natural Resources Revenue, to the 

Committee on Natural Resources, House 

of Representatives, doi.gov/ocl/ 

hearings/112/ 

OffshoreEnergyAgenciesGould_071511. 

Tasking ONRR with incentivizing 

energy production would seem to be 

inconsistent with the current delegation 

of responsibilities between BOEM, 

BSEE, and ONRR. 

Finally, it should be remembered that 

ONRR’s primary functions include 

ensuring fair return (i.e., fair value) for 

the public from royalty and revenue 

collection and disbursement activities. 

As a result, any decision by ONRR to 

incentivize or disincentivize production 

that compromises the attainment of a 

fair return for the United States would 

be outside ONRR’s primary function. 


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b. The 2020 Rule Failed To Show How

It Incentivized Production

In response to the First Delay Rule, 

one commenter wrote that ONRR 

revealed for the first time in the 2020 

Rule that it evaluated the issue of 

production impacts using its economic 

models. The commenter referred to the 

following language: The ‘‘margin of 

error for estimating this rule’s negligible 

or marginal impact on actual production 

is beyond the capability of the 

Department’s existing models, and the 

Department does not know of other 

economic models that are sufficiently 

sensitive to accurately measure these 

changes.’’ 86 FR 4616. The commenter 

described this language as convoluted. 

The commenter interpreted this 

statement to mean that, using the 

estimating models available to it, ONRR 

ultimately determined that the rule 

would have a ‘‘negligible or marginal 

impact on production’’ within the 

margin of error of its models. According 

to the commenter, ONRR’s statement 

means the premise for adopting the 

2020 Rule—that it would increase 

production—was false. The commenter 

also stated that ONRR failed to provide 

this finding to the public in the 

Proposed 2020 Rule to allow the public 

the opportunity to comment on this new 

information. The commenter asserted 

that ONRR instead proceeded to adopt 

the 2020 Rule despite knowing the 

premise for its rulemaking had been 

withheld and, moreover, was materially 

false. The commenter claimed that on 

this basis alone, the 2020 Rule should 

be withdrawn. 

ONRR rejects the commenter’s 

assertions that information was 

withheld in the Proposed 2020 Rule to 

undermine the public’s opportunity to 

comment. Agencies routinely add, 

expand, and revise explanations 

between proposed and final rules based 

on public comments and their own 

continued analysis and search for 

information. However, ONRR agrees 

with the commenter that the 2020 Rule 

ultimately failed to explain or 

substantiate how it accomplished its 

stated purpose to incentivize 

production—regardless of whether, as 

discussed above, it is within ONRR’s 

authority to adopt rules for that 

purpose. 

c. The 2020 Rule Failed To Consider

Existing Methods DOI Uses To

Incentivize Production

ONRR’s sister bureaus have 

regulations in place to incentivize 

production through royalty relief in 

certain situations. This section briefly 

describes some of these bureaus’ 

royalty-relief programs, which ONRR 

failed to consider when adopting the 

2020 Rule. Immediately below we 

discuss BSEE’s offshore royalty relief 

programs, and then BLM’s onshore 

royalty relief programs. 

DOI’s statutory authority allows it to 

reduce or eliminate a lessee’s OCS 

royalty obligation in order to promote 

development, increase production, or 

encourage production of marginal 

resources. See 43 U.S.C. 1337(a)(3). 

BSEE’s royalty relief regulations, 

including those found at 30 CFR part 

203, may provide a more appropriate 

incentive than the 2020 Rule’s revenueimpacting amendments, including the 

deepwater gathering allowance, which 

is limited to the OCS. 

The Secretary implements 43 U.S.C. 

1337(a)(3)(A)–(C) by offering royalty 

relief under two general categories, 

‘‘automatic’’ and ‘‘discretionary.’’ 

‘‘Automatic’’ refers to deepwater and 

deep gas royalty relief that is specified 

in an OCS lease issued by BOEM. See 

30 CFR 560.220. ‘‘Discretionary’’ refers 

to royalty relief that a lessee may apply 

for under certain scenarios and includes 

end-of-life and special case royalty 

relief. See 30 CFR 203.50 through 

203.56 and 203.80, respectively. For 

more information, see https://

www.boem.gov/oil-gas-energy/energyeconomics/royalty-relief. 

In order to receive discretionary 

royalty relief, a lessee must demonstrate 

and BSEE must verify that a project 

would be uneconomic without royalty 

relief and would become economic with 

royalty relief. See 30 CFR 203.2. The 

lessee must submit an application to 

BSEE outlining the estimated economics 

of the project, which BSEE then 

reviews. See id. (stating that for different 

types of royalty relief, the applicant 

must propose and demonstrate that their 

project or further development is 

uneconomic without relief); see also 

https://www.boem.gov/oil-gas-energy/ 

energy-economics/deepwater-royaltyrelief-economic-model. BSEE employs 

this process to balance the promotion of 

production with other considerations, 

including protection of royalty revenue. 

In contrast, some of the 2020 Rule’s 

revenue-impacting amendments, 

including the deepwater gathering 

allowance and amendments related to 

the index-based valuation option, may 

be claimed by all lessees producing 

from deepwater and are in no manner 

targeted to incentivize operations that 

otherwise would be uneconomic. 

Instead, these revenue-impacting 

amendments are an across-the-board 

benefit for any lessee that meets the 

criteria set out in the amendment— 

regardless of economic need. 

Specific to the deepwater gathering 

allowance, experience gained in 

numerous audits and other compliance 

activities has shown that many lessees 

commissioned deepwater projects 

without knowledge of the Deepwater 

Policy. Rather than having made 

investment decisions based on the 

Deepwater Policy, these lessees began to 

calculate allowances under that policy 

long after learning of the Deepwater 

Policy and, typically, long after a project 

began producing. Some companies, 

prior to the 2016 Valuation Rule’s 

rescission of the Deepwater Policy, 

applied the Deepwater Policy 

retroactively after selling the assets. 

Moreover, for production between 1999 

and 2016, ONRR found that many 

lessees misapplied the Deepwater Policy 

(for example, claiming disallowed costs 

or claiming gathering in situations that 

did not meet the Deepwater Policy’s 

criteria). While the Deepwater Policy 

(between 1999 and 2016) reduced 

royalty value, ONRR has seen no 

evidence that the Deepwater Policy 

impacted a lessee’s decision-making to 

invest or not in a deepwater project. 

BSEE’s royalty relief practices include 

safeguards for the public, including the 

application and approval process, 

volume thresholds, pricing thresholds, 

time limits, capital expenditure 

thresholds, and periodic reviews of 

approved royalty relief. 30 CFR 203.4 

(discretionary end-of-life and deepwater relief programs) and 30 CFR 

203.47 (deep gas relief program); see 

also https://www.bsee.gov/sites/ 

bsee.gov/files/special-case-royalty-reliefoverview-1.pdf (describing the special 

case relief program’s application 

process). Each application for 

discretionary royalty relief is reviewed 

by BSEE, allowing BSEE to grant relief 

only where needed and appropriate 

while still protecting public interests. 30 

CFR 203.1 and 203.2 (providing that 

BSEE may grant a ‘‘royalty suspension 

for a minimum production volume plus 

any additional volume needed to make 

your project economic’’). 

In contrast, four of the five revenueimpacting amendments adopted in the 

2020 Rule do not include an economic 

needs test or an application and 

approval process. There was and is no 

safeguard to prevent a lessee with a 

highly lucrative operation from taking 

advantage of these revenue-impacting 

amendments. 

Because the 2020 Rule did not 

consider existing BSEE regulations and 

practices which provide more targeted, 

structured methods to incentivize new 

or continuing OCS operations, it 

appears ONRR’s 2020 rulemaking 

process was inadequate to support 


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adoption of its revenue-impacting 

amendments, including, on the basis of 

incentivizing production. 

See also the ‘‘Memorandum of 

Understanding between BOEM, BSEE, 

and ONRR for the Collaboration on 

Processes, Policies and Systems Relating 

to the Management of [OCS] Energy and 

Marine Mineral Development,’’ signed 

in March of 2014 (‘‘2014 MOU’’), which 

outlines BOEM, BSEE, and ONRR’s 

respective duties for and involvement in 

various aspects of OCS production. 

ONRR’s role, with respect to these 

programs, is limited to the maintenance 

of royalty information in ONRR’s 

royalty management system. See 2014 

MOU, Attachment A, Information 

Sharing and Bureau Responsibilities; 

Offshore Federal Oil, Gas, Sulphur and 

Marine Minerals at page A–21 to A–22 

(noting BSEE and BOEM duties to track 

production and assess price forecasting, 

among other tasks, with ONRR’s 

responsibility with respect to royalty 

relief limited to ensuring volume and 

royalty data remain up-to-date, and 

ensuring the collection of any royalty 

payments). 2014 MOU located at 

https://www.boem.gov/sites/default/ 

files/documents//MOU%20BOEMBSEEONRR%20Collaboration%202014-04- 

16.pdf. 

Onshore, BLM may reduce the royalty 

on a lease ‘‘to encourage the greatest 

ultimate recovery of the resource and in 

the interest of conservation of natural 

resources.’’ See 43 CFR 3103.4–1(a). 

Prior to reducing a royalty rate, BLM 

must conduct an analysis to determine 

that the royalty reduction ‘‘is necessary 

to promote development of the lease or 

the BLM determines that the lease 

cannot be successfully operated under 

[the royalty rate agreed to in] the terms 

of the lease.’’ 43 CFR 3133.3(a)(2). The 

regulations also specify the process by 

which companies must apply for a 

royalty reduction and the required 

contents of an application. See 43 CFR 

3103.4–1(b)(1)–(3). 

ONRR invites public comment on 

whether the targeted royalty-relief 

authorities delegated to and 

administered by BSEE and BLM serve as 

more appropriate mechanisms to 

evaluate a lessee’s economic or 

production hardship and to 

appropriately respond thereto than do 

the 2020 Rule’s revenue-impacting 

provisions. 

2. Deepwater Gathering Allowances 

(§§ 1206.110(a) and 1206.152(a)) 

a. The Regulation Text Adopted in the 

2020 Rule Was Not in the Proposed 

2020 Rule 

Following the Proposed 2020 Rule’s 

publication, ONRR discovered that 

some of the regulatory text intended for 

§§ 1206.110(a) and 1206.152(a) was 

missing. In the 2020 Rule, at 86 FR 

4622, ONRR explained that the 

proposed regulatory text failed to 

include certain requirements that a 

lessee must meet to be eligible for a 

deepwater gathering allowance, as 

several commenters had noted. ONRR 

corrected for its prior error and revised 

the regulatory text in the 2020 Rule. It 

made the oil and gas sections consistent, 

and added language in both §§ 1206.110 

and 1206.152 to incorporate the two 

previously missing components from 

the Deepwater Policy—the adjacency 

limitation and requirement for a lessee 

to identify a central accumulation point 

at or near the subsea wellhead. See also 

86 FR 4654, 4656 (amendatory 

instructions for §§ 1206.110 and 

1206.152 in the 2020 Rule). While the 

preamble included in the Proposed 2020 

Rule had explained ONRR’s intention to 

adopt a deepwater gathering allowance 

consistent with the former Deepwater 

Policy, the revisions to regulation text 

made with publication of the 2020 Rule, 

which incorporated key aspects of the 

former Deepwater Policy into 

§§ 1206.110 and 1206.152, can be seen 

as substantive changes that should have 

triggered a reopening of the comment 

period. 

With respect to §§ 1206.110 and 

1206.152, the public was not adequately 

apprised of and afforded an opportunity 

to read and comment on the proposed 

amendments to regulation text as those 

changes first appeared in the final rule. 

Accordingly, commenters focused on 

the Proposed 2020 Rule’s regulation text 

would have been misled as to the 

availability of and criteria for a 

deepwater gathering allowance. ONRR 

believes that its failure to provide an 

opportunity for meaningful public 

comment on the regulation text of 

§§ 1206.110 and 1206.152 may 

constitute a procedural defect under 5 

U.S.C. 553(b) and justify withdrawal of 

the deepwater gathering allowance 

provisions. 

b. Deepwater Gathering Allowances 

Lack Statutory and Policy Support 

A Federal oil and gas lessee must pay 

a royalty of not less than 12.5 percent 

in amount or value of the production 

removed or sold from the lease. See 43 

U.S.C. 1337(a). Notwithstanding this 

statutory requirement, the 2020 Rule 

adopted the deepwater gathering 

allowance because doing so ‘‘may 

reduce a lessee’s total royalty burden 

resulting in a lower total cost to operate 

on the OCS, and thereby potentially 

encouraging continued production and 

conservation of a resource.’’ 86 FR 4622. 

As its basis for incentivizing offshore 

production, the 2020 Rule stated that 

‘‘Recent Executive and Secretarial 

Orders call on Federal agencies to 

appropriately promote and unburden 

domestic energy production, especially 

OCS resources.’’ Id. (citing E.O. 13783, 

‘‘Promoting Energy Independence and 

Economic Growth,’’ E.O. 13795, 

‘‘Implementing an America-First 

Offshore Energy Strategy,’’ and S.O. 

3350, which promotes the America-First 

Offshore Energy Strategy). 

The 2020 Rule’s stated goal of 

promoting offshore oil and gas 

production through deepwater gathering 

allowances appears to be in conflict 

with the statutory requirement that 

royalties be paid based on the ‘‘amount 

or value’’ of the oil and gas produced. 

Value for royalty purposes is the value 

of the oil and gas in marketable 

condition. See California Co. v. Udall, 

296 F.2d 384, 388 (D.C. Cir. 1961). 

Gathering costs, which include costs to 

measure and condition oil and gas for 

market, have long been considered a 

cost incurred by the lessee to place gas 

in marketable condition. Thus, 

gathering costs are the sole 

responsibility of the lessee. See 30 CFR 

1206.20 and 1206.171; 53 FR 1184 at 

1190–1191 (January 15, 1988); DCOR, 

ONRR–17–0074–OCS (FE), 2019 WL 

6127405 (Aug. 26, 2019). 

Also, the deepwater gathering 

allowance appears to lack policy 

support. E.O. 13783 and E.O. 13795 

(prior to withdrawal) provided that the 

E.O.s ‘‘shall be implemented consistent 

with applicable law.’’ Applicable law 

requires that royalties be paid based on 

the ‘‘amount or value’’ of the 

production. See 43 U.S.C. 1337(a)(1)(A). 

Thus, it is not clear that these E.O.s 

authorized DOI to incentivize offshore 

oil and gas production through 

reduction of the lessee’s royalty burden. 

Further, even if these E.O.s could be 

construed to provide such policy 

support, the E.O.s were revoked within 

days of the publication of the 2020 Rule 

and prior to the 2020 Rule’s effective 

date. 

c. The 2020 Rule Added Extensive 

Justification on Which the Public Was 

Unable To Comment 

While the Proposed 2020 Rule 

provided a lengthy background of the 

history of the Deepwater Policy, it 


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provided little justification for its 

codification, citing only that ONRR was 

‘‘reevaluating its rules in light of E.O. 

13783 and E.O. 13795, which call on 

Federal agencies to promote and 

unburden domestic energy production, 

and the Secretarial Orders encouraging 

robust and responsible exploration and 

development of [OCS] resources.’’ 85 FR 

62060. In the 2020 Rule, however, 

ONRR explained its reasoning in far 

greater detail. See 86 FR 4622–4625. 

Thus, the Proposed 2020 Rule’s lack of 

a fully-reasoned explanation for 

codifying a deepwater gathering 

allowance may have limited the public’s 

opportunity to meaningfully comment 

on ONRR’s intended regulatory change. 

See Section II.A.3. above and further 

discussion below. 

The 2020 Rule listed several new 

factors that warranted a deepwater 

gathering allowance in the GOM. First, 

it explained that the GOM is now a 

mature hydrocarbon province—most of 

the large fields have been discovered 

and developed and the remaining fields 

are smaller and more likely to be 

developed with subsea tiebacks, the 

costs of which would likely be allowed 

as a transportation allowance under the 

deepwater gathering allowance. See 86 

FR 4623. Second, the 2020 Rule noted 

the drop in commodity prices since the 

development and publication the 2016 

Rule, which seemingly makes 

deepwater investment less economic. 

See 86 FR 4623–4624. Third, the 2020 

Rule compared the decrease in 

applications for drilling permits in the 

GOM to an increase in onshore drilling 

permits. See 86 FR 4624. Fourth, it 

referenced BOEM’s current National 

Assessment of Undiscovered Oil and 

Gas Resources of the U.S. OCS, which 

shows declines in the GOM’s 

economically recoverable oil and gas 

resources. Id. Finally, it explained the 

increased risk, cost, and national 

importance of producing oil and gas 

from the deepwater OCS. 86 FR 4622– 

4625. Since this information was not 

provided in the Proposed 2020 Rule, the 

public did not have an opportunity to 

comment on these reasons for adopting 

a deepwater gathering allowance. 

3. Reinstated Extraordinary Processing 

Allowances for Federal Oil and Gas 

(§ 1206.159(c)(4)) 

a. Extraordinary Processing Allowances 

Lack Statutory and Policy Support 

Please see the discussion above at 

Section II.B.2.b. 

b. Final Rule Included Inconsistent 

Language on Incentivizing Production 

ONRR addressed extraordinary 

processing allowances and hard caps on 

transportation and processing 

allowances in the same section of the 

Proposed 2020 Rule. 85 FR 62058. 

ONRR asserted in the Proposed 2020 

Rule that reinstating a lessee’s ability to 

request approval to claim an 

extraordinary processing allowance and 

removing hard caps on transportation 

and processing allowances would 

incentivize production or remove a 

disincentive to produce. See 86 FR 

4615. Those assertions conflict with 

other statements in the 2020 Rule that 

indicate the incentives, if any exist, are 

negligible. See 86 FR 4616–4617. 

Moreover, the Proposed 2020 Rule and 

2020 Rule did not show any measurable 

connection between extraordinary 

processing allowances and increased 

production despite relying on an 

assertion that reinstating the allowance 

would incentivize production. The 2020 

Rule adopted the amendment on 

extraordinary processing allowances 

but, based on a new economic analysis, 

did not adopt the hard caps on 

transportation and processing 

allowances. 

The Proposed 2020 Rule stated that 

allowing a lessee to request approval for 

an extraordinary processing allowance 

and to request to exceed the 

transportation and allowance hard caps 

would incentivize production. 85 FR 

62058. The 2020 Rule referenced 

various statutes, E.O.s, and S.O.s to 

‘‘emphasize the importance of reducing 

regulatory burdens so that energy 

producers, and particularly oil, natural 

gas, and coal producers, are 

incentivized to produce more energy.’’ 

86 FR 4615. However, in response to 

public comments, the 2020 Rule also 

provided that it was ‘‘not premised on 

increasing the production of oil, gas, or 

coal by some measured amount’’ and 

was, instead, ‘‘meant to incentivize both 

the conservation of natural resources (by 

extending the life of current operations) 

and domestic energy production over 

foreign energy production.’’ 86 FR 4616. 

Later, the 2020 Rule presents a 

conflicting position—that the monetary 

impact of the rule’s amendments is 

insufficient to incentivize new 

production or to incentivize a lessee to 

continue producing from a Federal lease 

when the lessee otherwise would not. In 

response to comments that suggest the 

allowances provide a disincentive for a 

lessee to reduce their costs for 

transportation and processing, ONRR 

generally referred to the Federal 

Government’s royalty share of 

production, which is typically 12 1/2 or 

16 2/3 percent and a lessee’s retention 

of the remaining 87 1/2 or 83 1/3 

percent, respectively. The 2020 Rule 

concluded that the lessee’s interest 

provided a significant incentive in 

minimizing transportation and 

processing costs. See 86 FR 4620–4621. 

Thus, the 2020 Rule assumed the 

Federal Government benefits from a 

lessee’s motivation to be cost-conscious 

on its greater share. 86 FR 4646. 

Accordingly, ONRR stated it did not 

expect the regulatory limits on 

transportation and processing 

allowances on the government’s smaller 

share to affect a lessee’s decision 

making with respect to transportation 

and processing expenses 

proportionately applied to the lessee’s 

greater share. See 86 FR 4626. 

The 2020 Rule again contradicted 

earlier statements in that rule in its 

discussion on helium-bearing gas 

streams. See 86 FR 4628. Although 

ONRR acknowledges that helium 

production from Federal leases is 

managed by BLM, helium royalties are 

not affected by the extraordinary 

processing allowance provision. See 

Exxon Corp., 118 IBLA 221, 229 n.9 

(1991) (noting that MMS does not 

consider helium in valuing a gas stream 

for royalty purposes because ‘‘it is not 

considered a leasable mineral.’’); see 

also https://www.blm.gov/programs/ 

energy-and-minerals/helium/divisionof-helium-resources (noting that the 

BLM’s Division of Helium Resources 

‘‘adjudicates, collects, and audits 

monies for helium extracted from 

Federal lands’’). Further, only one of the 

prior extraordinary processing 

allowance approvals involved a heliumbearing gas stream. See 86 FR 4628. Yet, 

the 2020 Rule maintained that 

reinstating extraordinary processing 

allowances is necessary because ‘‘the 

U.S. has important economic and 

national security interests in ensuring 

the continuation of a reliable supply of 

helium, including that recovered from 

unique gas streams requiring costly 

equipment to remove carbon dioxide 

and hydrogen sulfide before helium can 

be extracted.’’ 86 FR 4628. 

c. ONRR’s Authority To Incentivize 

Production 

Please see discussion at Section 

II.B.1., above. 

d. The 2020 Rule Included Extensive 

Justification not Made Available for 

Public Comment 

The reasons stated in the Proposed 

2020 Rule for changes to the 2016 

Valuation Rule’s amendments to 

allowance limits (removing the 


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regulatory hard caps on transportation 

and processing allowances and 

reinstituting extraordinary processing 

allowances) were premised on 

promoting domestic production by 

reducing administrative burdens and 

incentivizing production by increasing 

transportation and processing 

allowances and thereby decreasing the 

royalties due. See 85 FR 62058. 

While the 2020 Rule did not adopt the 

proposed amendments to remove 

regulatory hard caps on transportation 

and processing allowances, it did 

reinstitute extraordinary processing 

allowances. In doing so, the 2020 Rule 

cited additional reasons from 

commenters that harken back to those 

submitted by commenters—and rejected 

by ONRR—during promulgation of the 

2016 Valuation Rule. See https://

www.onrr.gov/Laws_R_D/FRNotices/ 

AA13.htm. Specifically, the 2020 Rule 

identified the following reasons in 

support of reinstituting a lessee’s ability 

to request an extraordinary processing 

allowance: 

(1) The technology to process two 

Wyoming unique gas streams has not 

changed, ‘‘despite technological 

advances in processing relevant to many 

other areas and types of gas streams.’’ 86 

FR 4628. 

(2) Extraordinary processing 

allowances are essential for two major 

gas processing facilities in Wyoming 

that treat challenging gas streams, and 

without an extraordinary processing 

allowance approval, these two plants 

are at a competitive disadvantage and 

may be prematurely retired. 86 FR 4627. 

(3) One of Wyoming’s unique gas 

streams, which previously had been 

approved for an extraordinary 

processing allowance, contains 

recoverable quantities of helium, an 

element that is vital to the Nation’s 

security and economic prosperity. 86 FR 

4628. 

(4) In instances where a lessee might 

not otherwise choose to produce a gas 

stream containing helium, the 

opportunity to apply for an 

extraordinary processing allowance 

approval could incentivize the lessee to 

either continue producing or to initiate 

production. 86 FR 4628. 

(5) The overall positive economic 

impact to Wyoming of continuing 

operation of the Federal leases that 

historically benefitted from 

extraordinary processing allowances 

outweighs any reduction in royalties 

Wyoming receives. 86 FR 4628. 

As discussed above, although the 

Proposed 2020 Rule’s proposed 

amendment to reinstitute extraordinary 

processing allowances was premised on 

incentivizing production, ONRR 

concluded that in most cases, providing 

an extraordinary processing allowance 

is not sufficient to incentivize 

production. See 86 FR 4627–4629. Apart 

from an unpersuasive argument about 

incentivizing production, ONRR relied 

entirely on reasons submitted by 

commenters in response to the Proposed 

2020 Rule to support reinstating a 

lessee’s ability to request an 

extraordinary processing allowance. See 

86 FR 4627–4629. Therefore, the public 

did not have a meaningful opportunity 

to comment on most of the reasons that 

ONRR relied on in the 2020 Rule to 

reinstitute extraordinary processing 

allowances in the final rule. 

4. Expansion of the Federal Gas Index 

Pricing Valuation Option to Federal Gas 

Sold Under Arm’s-Length Contracts 

(§§ 1206.141(c) and 1206.142(d)) 

Prior to the 2016 Rule, ONRR 

regulations did not include an indexbased valuation option for Federal gas 

or natural gas liquids. The 2016 Rule 

included such an option. It allowed 

Federal oil and gas lessees a choice of 

methods in calculating royalties due on 

gas and on natural gas liquids. One 

option, which a lessee could elect for a 

two-year period of time (or longer), was 

to calculate royalty value for gas using 

a formula based on the high of certain 

published index prices, reduced by 

either 5% for onshore production or 

10% for offshore production (subject to 

certain limits), with the reduction 

designed to account for a conservative 

estimate of average transportation costs 

as adjusted by average, non-deductible 

costs of placing gas in marketable 

condition. This option was only 

available for gas a lessee disposed of in 

non-arm’s-length transactions— 

transactions which are most frequently 

between affiliates, and therefore may 

not be at market value, but rather at 

prices influenced by the affiliate 

relationship. Since index prices are 

published prices derived from reported 

arm’s-length transactions, ONRR 

considered the index-based valuation 

formula included in the 2016 Rule a 

simpler, acceptable, and potentially 

preferrable method to value gas 

disposed of in non-arm’s-length (or 

affiliate) transactions. 81 FR 43338, 

43346–43348. 

a. New Analysis Shows a Decrease in 

Royalties Collected 

Several commenters on the Proposed 

2020 Rule expressed concern that 

ONRR’s assumption that 50 percent of 

lessees would elect the index-based 

valuation option was flawed and failed 

to represent logical business decision 

making processes. As commenters 

suggested, a lessee might apply an 

internal, business-driven threshold to 

decide if the index-based valuation 

method would be of economic benefit or 

harm. Within a single lessee’s portfolio 

of properties, the lessee might choose to 

use the index-based valuation method 

for some properties but not others. 

As described in this Economic 

Analysis below, ONRR has performed a 

new analysis to identify a more accurate 

estimate of the potential annual impact 

to royalty collections associated with 

the expansion of the index-based 

valuation method to arm’s-length sales 

of natural gas and NGLs. This new 

analysis—based on the assumption that 

a lessee will act in its own financial best 

interest when deciding whether to use 

the index-based valuation option for its 

arm’s-length sales—resulted in a 

projected net decrease in royalty 

collections of over $7 million per year 

as compared to collections made 

without the use of an index-based 

valuation option for arm’s-length sales 

(i.e., as would occur under ONRR’s 

regulations prior to the 2020 Rule, 

which only allow index-based valuation 

for non-arm’s-length dispositions). This 

estimate sharply contrasts with the 

estimated $28.9 million per year 

increase in royalties stated in the 2020 

Rule. 

b. Arm’s-Length Transaction Data Is a 

Better Measure of Value 

Arm’s-length contracts are those 

negotiated between independent parties 

with opposing economic interests. See 

30 CFR 1206.20. ONRR has long 

concluded that the gross proceeds 

accruing under an arm’s-length contract 

is, in most cases, the best indicator of 

fair market value. See, e.g., 53 FR 1186 

(Jan. 15, 1988); 81 FR 43338 (July 1, 

2016). 

The 2020 Rule amended the 2016 

Valuation Rule to introduce an indexbased valuation option for Federal gas 

sold in arm’s-length sales. The 

Economic Analysis in the 2020 Rule 

explained that, due to those 

amendments, royalty payments were 

expected to increase. ONRR relied on 

that analysis to deviate from its longheld position of relying exclusively on 

gross proceeds valuation (or a proxy 

where gross proceeds could not be 

reliably determined) to value arm’slength sales of Federal gas for royalty 

purposes. ONRR found that it had 

protected the Federal lessor’s interest 

based on the conclusion that royalties 

were expected to meet or exceed values 

based on gross proceeds. But as 

explained in the Economic Analysis of 

this rule, the analysis in the 2020 Rule 

was flawed because it did not consider 


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that economic factors will influence a 

lessee’s decision to elect to use the 

index-based valuation method. ONRR 

has now reviewed historical data and 

can now show that electing the indexbased valuation option would likely 

result in collecting less royalties for 

arm’s-length sales. 

5. Change of Index-Based Value to the 

Published Average Bidweek Price 

The 2020 Rule amended regulations at 

§§ 1206.141(c)(1)(i) and (ii) and 

1206.142(d)(1)(i) and (ii) to change 

references to the ‘‘highest monthly 

bidweek price’’ for the index pricing 

points to which a lessee’s gas could 

flow, to the ‘‘highest of the monthly 

bidweek average prices’’ for the index 

pricing points to which a lessee’s gas 

could flow. The use of average index 

prices was considered during the 2016 

valuation rulemaking process and 

rejected. However, the 2020 Rule sought 

to reverse ONRR’s earlier decision on 

that point so as to incentivize 

production. But, as discussed above, 

ONRR’s authority to amend its valuation 

regulations to incentivize production is 

questionable; its 2020 Rule did not 

prove that it would incentivize 

production; and the same rule was 

internally inconsistent on whether it 

would, in fact, incentivize production. 

6. Further Reduction to Index in IndexBased Valuation To Account for 

Transportation 

The 2020 Rule amended regulations at 

§§ 1206.141(c)(1)(iv) and 

1206.142(d)(1)(iv) to increase the 

amount of a reduction to index to 

account for the average costs of 

deductible transportation, after 

adjustment for the non-deductible costs 

of placing gas into marketable 

condition. This amendment was 

justified, in part, on an economic 

analysis of more recent royalty data, 

which showed higher average 

transportation costs than ONRR had 

relied on in adopting the 2016 Valuation 

Rule. However, the amendment also was 

justified on an intent to incentivize 

production. But, as discussed above, 

ONRR’s authority to amend its valuation 

regulations to incentivize production is 

questionable; its 2020 Rule did not 

prove that it would incentivize 

production; and the same rule was 

internally inconsistent on whether it 

would, in fact, incentivize production. 

C. Comments in Response to the First 

Delay Rule 

ONRR received numerous comments 

in response to the First Delay Rule. Most 

commenters stated that a complete 

withdrawal of the 2020 Rule is 

warranted. Several commenters 

presented material and arguments that 

were distinguishable from earlier 

comments. The new materials provided 

by commenters, along with ONRR’s 

most recent findings and updated 

economic analysis, led ONRR to change 

its position with respect to several 

considerations that were thought to 

support the 2020 Rule. ONRR addresses 

below many of the public comments 

that ONRR received in response to 

specific questions posed in the First 

Delay Rule. 

1. Reliance on E.O.s and Scope of 

Secretarial Authorities Delegated to 

ONRR 

ONRR relied on E.O.s in effect during 

the time it promulgated the 2020 

Proposed Rule and the 2020 Rule. See 

86 FR 4612 and 85 FR 62056–62057 

(citing E.O. 13783, E.O. 13795, and E.O. 

13892). 

Public Comment: Multiple 

commenters opined that the change in 

policy requires ONRR to reconsider all 

or certain provisions of the 2020 Rule. 

Other commenters suggested the 

opposite, asserting that the prior E.O.s 

were not the sole justification for the 

2020 Rule, and that ONRR provided 

sufficient detail in the 2020 Proposed 

and Final Rules to justify the 

amendments independent of the E.O.s. 

The commenters stated that the 2020 

Rule sought to improve certainty and 

accuracy in royalty reporting and 

accounting consistent with FOGRMA 

and other mineral leasing laws. 

Commenters contended that ONRR 

relied on appropriate legal mandates to 

promulgate the 2020 Rule and asserted 

that policy changes cannot outweigh 

ONRR’s governing legal authority under 

FOGRMA and the mineral leasing laws 

when it conducts rulemaking. One 

commenter asserted that changing 

policy where there is a new 

Administration or shift in E.O.s would 

ultimately create regulatory instability 

with respect to valuation and reporting 

requirements, thereby directly 

contradicting 30 U.S.C. 1711(a), which 

requires ONRR ‘‘to establish a 

comprehensive . . . production 

accounting and . . . auditing system to 

provide the capability to accurately 

determine . . . royalties . . . and other 

payments owed and to collect and 

account for such amounts in a timely 

manner.’’ 

ONRR Response: ONRR proposed the 

2020 Rule ‘‘because policy directives 

issued after [the 2016 Valuation Rule’s 

publication] give different weight to the 

factual findings, and also dictate that a 

different policy-based outcome be 

pursued.’’ 85 FR 62056. The Proposed 

2020 Rule also explained that an 

agency’s reconsideration of regulations 

in light of a new Administration’s 

policy objectives is acceptable and 

within the agency’s discretion. Id. As 

such, ONRR’s discussions for the 

regulatory changes largely focused on 

reducing regulatory burden or 

uncertainty and incentivizing 

production. See 85 FR 62054, 62056– 

62057. The Proposed 2020 Rule 

generally sought to further the 

objectives of E.O. 13783, E.O. 13795, 

E.O. 13892, S.O. 3350, and S.O. 3360 in 

two ways, providing mechanisms that 

promote new and continued domestic 

energy production and simplify 

reporting. See 85 FR 62057. However, 

ONRR did not (a) articulate how the 

2020 Rule’s proposed amendments 

furthered ONRR’s delegated revenue 

management responsibilities, (b) explain 

the source of the delegation to ONRR to 

incentivize production, or (c) describe 

how the amendments would incentivize 

production or simplify reporting. In 

part, ONRR proposes to withdraw the 

2020 Rule due to the revocation of these 

E.O.s and the uncertainty as to whether 

ONRR’s authority and responsibilities 

permit it to adopt valuation rules for the 

purpose of incentivizing production and 

whether the amendments adopted 

would, in fact, incentivize production. 

Additional discussion of ONRR’s 

reliance on incentivizing production as 

a rulemaking consideration is addressed 

in Section II.B.1. 

2. Deepwater Gathering Costs 

MMS issued the Deepwater Policy on 

May 20, 1999, authorizing a lessee to 

include certain deepwater gathering 

costs in its transportation allowance. 

Although the Deepwater Policy 

conflicted with 30 CFR 1206.110(a) and 

1206.152(a), neither MMS nor ONRR 

adopted regulations resolving this 

conflict. The 2016 Valuation Rule ended 

the practice that had existed under the 

Deepwater Policy since 1999. See 30 

CFR 1206.110(a) and 1206.152(a) (2019). 

The 2020 Rule sought to return to the 

practice permitted by the Deepwater 

Policy by codifying the policy in 

ONRR’s regulations. See 86 FR 4612. 

The justification for the deepwater 

gathering amendments was based, in 

part, on declining oil and gas 

production in and revenues from the 

Gulf of Mexico. See 86 FR 4623–4624. 

Public Comment: Some commenters 

stated that the deepwater gathering 

allowance is not consistent with the 

current law and policy of the United 

States. Some commenters emphasized 

that the deepwater gathering allowance 

evidenced that ONRR was prioritizing 

increased oil and gas production over 


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other considerations, including proper 

management of royalty revenues and 

protecting the public interest. One 

commenter emphasized that the 

deepwater gathering allowance reduces 

Federal royalties without adequate 

justification. This commenter also noted 

that, while DOI must make the OCS 

available for development, OCSLA does 

not require ONRR to incentivize 

production for a lessee’s benefit. A 

commenter asserted that ONRR 

provided no support for the assertion 

that a deepwater gathering allowance 

would incentivize production. 

Some commenters supported the 

deepwater gathering allowance and 

emphasized that industry relied on the 

Deepwater Policy between 1999 and 

2016 when making financial 

investments and leasing and 

development decisions. These 

commenters suggest that retroactively 

eliminating such allowances would 

present legal vulnerabilities (stating that 

it was unlawful for ONRR to eliminate 

the deepwater gathering allowance 

considering that a lessee relied on it to 

make leasing and development 

decisions) and may disincentivize 

future investment and development on 

the OCS. Commenters described the 

deepwater production environment as 

very different from typical onshore or 

shallow water environments. Another 

commenter disagreed with the premise 

of the question posed in the First Delay 

Rule because, according to the 

commenter, subsea movement of oil and 

gas is not gathering. That commenter 

asserted that ONRR has not construed 

the subsea movement of oil and gas as 

gathering for many years. A commenter 

that supported the 2020 Rule’s 

deepwater gathering allowance 

explained that the Deepwater Policy 

was originally created and implemented 

in 1999 and that the elimination of the 

Deepwater Policy in 2016 violated 

contract law and the APA. 

ONRR Response: Reliance on the 

Deepwater Policy as part of long-term 

decision making is questionable since 

that guidance was, from the time of its 

issuance in 1999 up to its rescission in 

the 2016 Valuation Rule (see 81 FR 

43340, 43343, and 43352), not in 

conformity with the express language of 

MMS’ regulations that governed 

gathering and transportation 

allowances. See 30 CFR 1206.20 

(defining gathering and transportation); 

30 CFR 1206.110 (governing oil 

transportation allowance); 30 CFR 

1206.152 (governing gas transportation 

allowance); see also Federal Crop Ins. 

Corp. v. Merrill, 332 U.S. 380, 386 

(1947) (holding that reliance on an 

agency’s advice that Federal crop 

insurance would cover a loss was 

unwarranted where such advice 

conflicted with a Federal regulation, 

noting that ‘‘not even the temptations of 

a hard case can elude the clear meaning 

of the regulation’’). 

Additionally, ONRR acknowledges 

that the 2020 Rule may have contained 

inconsistent language on incentivizing 

production and may not have 

demonstrated how and to what extent 

the amendments would impact 

production. In Sections II.A. II.B.1., and 

II.B.2., this proposed rule discusses 

these possible deficiencies in the 2020 

Rule’s justifications and other possible 

procedural errors specific to deepwater 

gathering costs. 

3. Extraordinary Processing Allowances 

Public Comment: Some commenters 

asserted that ONRR failed to provide a 

reasoned or detailed justification in the 

2020 Rule for its decision to reinstate 

extraordinary processing allowances. 

Some commenters said reinstatement of 

the allowances would not incentivize 

production, opining that, instead, 

producers will produce when they are 

likely to receive enough proceeds to 

conduct economic operations. Other 

commenters generally characterized the 

allowances as a benefit extended to 

industry at cost borne by the public in 

the form of environmental harms and 

loss of royalty revenue. 

A few commenters were in favor of 

reinstating extraordinary processing 

allowances, emphasizing that the 

allowances incentivize ongoing 

investment, as well as mutually 

beneficial development and production 

in atypical areas. These commenters 

noted that, due to the application and 

approval process, these allowances exist 

in limited circumstances. Commenters 

stated that industry relied on the 

allowances when making investment 

decisions and argued that the allowance 

is one of the tools that can be used to 

extend the life of existing wells and 

maximize the value of the associated 

leases. 

ONRR Response: ONRR acknowledges 

that the 2020 Rule contained 

inconsistent language on incentivizing 

production. See discussion in Section 

II.B.1., infra. 

4. Considering the Impacts of Climate 

Change 

Public Comment: Multiple 

commenters urged ONRR to consider 

science on the source and impacts of 

climate change in setting royalty and 

revenue management policy. One 

commenter stated that ONRR should 

incorporate climate damages when 

setting royalties from fossil fuel 

extraction on public lands and waters, 

and the best way to do that is to include 

a carbon adder in the royalty rate that 

reflects the social cost of carbon and 

social cost of methane. 

Other commenters disagreed. One 

commenter explained that this topic 

falls outside the scope of the 2020 Rule 

because ONRR’s role within DOI is the 

collection and disbursement of Federal 

and Indian royalties owed on leases that 

have already been issued, which 

constitute binding contracts. This 

commenter further stated that the 

matters relating to the issuance of new 

leases and potential impacts on climate 

change arising from leasing activity fall 

outside of the authority delegated to 

ONRR and, accordingly, are irrelevant to 

an evaluation of the 2020 Rule. 

Another commenter stated that, for 

purposes of determining the value for 

royalty purposes of coal production 

from Federal leases, consideration of 

climate change factors is unlawful as it 

contravenes DOI’s statutory mandate 

under the MLA. 

One commenter stated that ONRR 

appropriately addressed climate change 

in the 2020 Rule. See 86 FR 4612, 4617. 

This commenter urged that further 

environmental review of leases in the 

context of ONRR’s royalty valuation 

rulemaking is inappropriate. 

ONRR Response: Addressing climate 

change is a priority to the Federal 

Government. See, e.g., E.O. 13990, 

‘‘Protecting Public Health and the 

Environment and Restoring Science to 

Tackle the Climate Crisis’’ and E.O. 

14008, ‘‘Tackling the Climate Crisis at 

Home and Abroad.’’ However, as 

described in Section I.A., ONRR is to 

collect, verify, and then disburse the 

revenues associated with the production 

of natural resources on Federal and 

Indian lands and the OCS. 30 U.S.C. 

1711; 30 CFR 1201.100. Moreover, the 

evaluation of environmental impacts is 

typically addressed by bureaus and 

agencies performing leasing and 

permitting functions. 86 FR 4612, 4617. 

5. Assumptions Regarding the IndexBased Valuation Option 

In the 2020 Rule, ONRR assumed that 

50 percent of reported royalties would 

come from eligible lessees that elected 

to use the index-based valuation option, 

while the remaining 50 percent would 

not (86 FR 4643–4645) and, as a result, 

the lessees that elected the index-based 

valuation option were estimated to pay 

an additional $28.9 million per year in 

royalties while saving $1.35 million in 

administrative costs. 86 FR 4648–4650. 

ONRR posited these assumptions even 

though the result is that a lessee would 

pay additional royalties far in excess of 


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the administrative cost savings they 

would realize. In the First Delay Rule, 

ONRR requested public comment on 

whether the assumption was flawed, 

and whether the resulting conclusion is 

appropriate and supported by current 

law and policy. See 86 FR 9288. 

Public Comment: Multiple 

commenters disagreed with the 

assumption that 50 percent of lessees 

would elect to use the index-based 

valuation option. One commenter 

described the assumption as baseless 

and urged ONRR to refrain from making 

conclusions based on the assumption. 

One commenter concluded that a lessee 

will value gas by the option that 

minimizes the royalty burden, 

explaining, for example, if the royalty 

payment resulting from a first arm’slength sale is less than the royalty 

payment that would be due using an 

index-based valuation methodology, 

then the lessee will elect to use the first 

arm’s-length sale. 

A few commenters agreed the 

estimate was appropriate, noting that 

industry values early certainty and may 

elect to use the index-based valuation 

option even if the price is slightly 

higher than gross proceeds to avoid 

audits and other compliance reviews 

that lead to the issuance of an order 

directing payment of additional 

royalties and late payment interest. One 

commenter suggested that ONRR 

designed the index-based valuation 

option solely to collect a greater royalty 

payment than what a lessee historically 

paid. The commenter opined that ONRR 

correctly assumed that some companies 

would elect to use the index-based 

valuation method for the certainty 

alone. 

ONRR Response: ONRR recently 

revised the method of its economic 

analysis (provided in the Section III) to 

more accurately value the potential 

annual impact to royalty collections 

resulting from the expansion of the 

index-based valuation method to arm’slength sales of Federal gas and NGLs. 

The new analysis estimates that this 

provision of the 2020 Rule would 

decrease royalty collections by $7 

million per year, rather than the $28.9 

million per year increase previously 

estimated. Please refer to Sections II.B.4. 

through II.B.6. for further discussion of 

the amendments to the index-based 

valuation method. 

6. Transparency in Royalty 

Administration in Index-Based 

Valuation 

Public Comment: A commenter stated 

that the index-based option provides 

clarity and early certainty for the 

producer but not for the public, 

asserting there is insufficient 

transparency in royalty administration 

for the public. 

ONRR Response: ONRR appreciates 

the public’s interest in bringing greater 

clarity, certainty, and transparency to 

royalty valuation in a manner that fits 

the needs of all stakeholders. The scope 

of this rulemaking is limited to the 

methods used to determine value for 

royalty purposes and does not consider 

topics related to how ONRR shares 

royalty information with the public. For 

additional information on production, 

collection, and disbursement activities, 

please visit https://revenuedata.doi.gov/ 

7. Substitution of Index-Based Value for 

Arm’s-Length Sales 

Public Comment: A commenter stated 

that it was premature for ONRR to 

extend the index-based valuation option 

to arm’s-length gas sales without 

evaluating the impact of the index-based 

option on non-arm’s-length gas 

dispositions. 

Another commenter reiterated that 

royalty payments are not expected to be 

reduced under the index-based option. 

The commenter added that ONRR 

retains the ability to access sales 

information from a lessee that elects an 

index-based valuation methodology and 

concluded that ONRR will be able to use 

the sales information to monitor the 

royalty implications of the index-based 

method and, if appropriate, revisit the 

index-based valuation options. 

Another commenter stated that, while 

they agree that arm’s-length negotiated 

contracts are the best indicator of value, 

the index-based valuation option may 

better serve both ONRR and lessees 

because of the estimated $28.9 million 

per year increase in royalty payments 

while permitting a lessee to avoid the 

complex reporting required by a gross 

proceeds valuation method. The 

commenter added that the two-year 

election period will prevent a lessee 

from manipulating reporting based on 

what method might be more 

economically beneficial each month. 

One commenter explained that industry 

values early certainty and assurance it 

will not face a burdensome audit years 

after the initial royalty payment. 

ONRR Response: ONRR, and 

previously MMS, has long viewed the 

gross proceeds received under an arm’slength contract between independent 

persons who are not affiliates and who 

have opposing economic interests to be 

the best indicator of value in most 

circumstances. See 53 FR 1186 (Jan. 15, 

1988); 81 FR 43338 (July 1, 2016). A 

lessee that sells gas for a price higher 

than the index-based price will have a 

financial incentive to use the indexbased price because valuation based on 

gross proceeds will result in the 

payment of more royalties. A lessee that 

sells the gas for a price lower than the 

index-based price has a financial 

incentive to use its gross proceeds for 

valuation. A lessee knows its gross 

proceeds and lessees have long used 

this amount to report and pay royalties 

for arm’s-length sales. An index-based 

option for arm’s-length sales may 

provide minimal value to industry since 

they have long used their gross proceeds 

to report and pay royalties. ONRR is 

proposing to withdraw the 2020 Rule in 

part because there are significant 

questions about whether the indexbased option adds to early certainty and 

whether it will adequately ensure a fair 

return for the public. 

In Section III, this proposed rule 

provides a revised economic analysis 

that estimates royalties impacts when a 

lessee bases its decision regarding 

whether to use index-based valuation on 

its financial interest. That analysis 

shows that this provision of the 2020 

Rule would decrease royalty collections 

by over $7 million per year. Please refer 

to Sections II.B.4. through II.B.6. and III 

for further discussion of the 

amendments to the index-based 

valuation method and the solicitation of 

comments on ONRR’s revised analysis 

and assumptions. 

8. Procedural Adequacy of the 2020 

Rulemaking Process 

Public Comment: Several commenters 

stated the 2020 Rule was procedurally 

inadequate, asserting that interested 

parties did not have a fair opportunity 

to comment. One commenter stated that 

the 2020 Rule failed to provide a 

‘‘reasoned explanation’’ for rescinding 

key portions of ONRR’s 2016 

rulemaking. The commenter explained 

that when an agency rescinds a prior 

policy, it must provide ‘‘a reasoned 

analysis for the change beyond that 

which may be required when an agency 

does not act in the first instance.’’ 

Another commenter stated that ONRR 

failed to respond to several public 

comments or responded in an 

incomplete or inaccurate manner. This 

commenter explained that the proposed 

rule failed to provide the general public, 

outside of the oil and gas industry, with 

sufficient information regarding the 

impacts of the proposals to enable the 

public to effectively participate in the 

rulemaking process. Another 

commenter noted that during the 2020 

rulemaking, ONRR did not have public 

meetings and evidently accepted only 

the suggestions it received from 

industry. 


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Other commenters disagreed. One 

commenter stated that the 2020 Rule is 

sound law based on policy deliberations 

that span almost a decade of thorough 

public process properly conducted 

under the APA. Another commenter 

concluded that the 2020 Rule 

appropriately complied with the APA. 

This commenter explained that a 

proposed rule was issued that described 

in detail each change that the agency 

was considering, interested persons 

were given an opportunity to comment, 

and the final rule responds to those 

comments. 

ONRR Response: ONRR agrees that 

procedural flaws exist in the 2020 Rule. 

Those flaws are explained in Sections 

II.A. and II.B. Further, ONRR notes that 

the 2020 Rule was not part of a 

rulemaking process that spanned a 

decade, as implied by the commenter. 

III. Economic Analysis 

ONRR’s delay rules have afforded 

ONRR more time to reexamine the 

methods and analyses it used to 

estimate economic impacts of the 2020 

Rule. ONRR recognizes that estimated 

changes to royalty obligations and 

regulatory costs in the 2020 Rule impact 

many groups, including the Federal 

Government, State and local 

governments, and industry. These 

potential changes to royalty obligations 

can have broader impacts beyond the 

amount of royalties. Royalty collections 

are used by these governments in a 

variety of ways that include funding 

projects, developing infrastructure, and 

fueling economic growth. 

Further, changes to royalties are 

transfers that are distinguishable from 

regulatory costs or cost savings. The 

estimated changes in royalties would 

affect both the private cost to the lessee 

and the amount of revenue collected by 

the Federal Government and disbursed 

to State and local governments. Based 

on an updated analysis, the net impact 

of the withdrawal of the 2020 Rule is an 

estimated $64.6 million annual increase 

in royalty collections. 

Please note that, unless otherwise 

indicated, numbers in the tables in this 

section are rounded to the nearest 

thousand, and that the totals may not 

match due to rounding. 

ESTIMATED CHANGES TO ROYALTY COLLECTIONS RESULTING FROM WITHDRAWAL OF THE 2020 RULE (ANNUAL) 

Rule provision 

Net change 

in royalties 

paid by 

lessees 

Index-Based Valuation Method Extended to Arm’s-Length Gas Sales .............................................................................................. $6,800,000 

Index-Based Valuation Method Extended to Arm’s-Length NGL Sales ............................................................................................. 660,000 

High to Midpoint Index Price for Non-Arm’s-Length Gas Sales ......................................................................................................... 5,062,000 

Transportation Deduction Non-Arm’s-Length Index-Based Valuation Method ................................................................................... 8,033,000 

Extraordinary Processing Allowances ................................................................................................................................................. 11,131,000 

Allowances for Certain OCS Gathering Costs .................................................................................................................................... 32,900,000 

Total .............................................................................................................................................................................................. 64,600,000 

ONRR also estimated that the oil and 

gas industry would face increased 

annual administrative costs of $2.8 

million under the 2020 Rule. As 

discussed below, this is the net impact 

of various cost increasing and cost 

saving measures. Withdrawal of the 

2020 Rule will result in an estimated net 

cost savings for industry. 

SUMMARY OF ANNUAL ADMINISTRATIVE IMPACTS TO INDUSTRY FROM WITHDRAWAL OF THE 2020 RULE

Rule provision Cost 

(cost savings) 

Administrative Cost for Index-Based Valuation Method for Gas & NGLs .......................................................................................... $1,077,000 

Administrative Cost Savings for Allowances for Certain OCS Gathering ........................................................................................... (3,931,000) 

Total .............................................................................................................................................................................................. (2,850,000) 

Following the publication of the delay 

rules and after consideration of 

comments received in response to the 

First Delay Rule, ONRR assessed which 

parts of the previous economic analysis 

warrant revision. To provide a more 

complete analysis, this rule presents the 

estimated royalty impacts of the 

withdrawal of the 2020 Rule using 

updated analyses. Changes are 

measured relative to a baseline that 

includes the royalty changes finalized in 

the 2020 Rule. 

As shown in the tables, an updated 

analysis of the impact to royalty under 

the 2020 Rule results in a total decrease 

in royalties of $64.6 million per year, 

which translates to an increase of $64.6 

million per year under this proposed 

withdrawal. This amount stands in 

contrast to the annual decrease of $28.9 

million per year in royalties previously 

estimated in the 2020 Rule. The change 

in amounts is largely attributable to the 

new assumption and method used to 

estimate the impact from extending the 

index-based valuation method to arm’slength natural gas and NGL sales. A 

more detailed explanation of the new 

method is described below. All amounts 

other than those related to the indexbased valuation option remain 

unchanged from those published in the 

2020 Rule. 

The administrative costs and potential 

administrative cost savings attributable 

to the 2020 Rule should also be updated 

using the new assumptions for the 

extension of index-based valuation 

method to arm’s-length sales. The 

administrative cost to industry for 

deepwater gathering allowances would 

remain unchanged from the value 

published in the 2020 Rule. 

ONRR also recalculated the estimated 

one-time administrative cost associated 

with the optional use of the index-based 

valuation method. These costs are only 

calculated by a lessee once to 

distinguish allowed and disallowed 

costs in reported processing and 

transportation allowances. Unless there 

is a significant change in processing and 

transportation costs, the ratio of allowed 


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to disallowed costs should not 

substantially change from year to year. 

ONE-TIME ADMINISTRATIVE IMPACTS TO INDUSTRY FROM WITHDRAWAL OF 2020 RULE

Rule provision Cost 

Administrative Cost of Unbundling Related to Index-Based Valuation Method for Gas & NGLs ...................................................... $4,520,000 

If the 2020 Rule is withdrawn, there 

will be an increase in administrative 

costs when compared to the current 

status quo. 

ONRR used the same base dataset for 

this proposed rule’s economic analysis 

as it used in the 2020 Rule for 

consistency and comparability. The 

description of the data was provided in 

the Economic Analysis of the 2020 Rule 

and is repeated here. ONRR reviewed 

royalty data for Federal oil, condensate, 

residue gas, unprocessed gas, fuel gas, 

gas lost (flared or vented), carbon 

dioxide, sulfur, coalbed methane, and 

natural gas products (product codes 03, 

04, 15, 16, 17, 19, 39, 07, 01, 02, 61, 62, 

63, 64, and 65) from five calendar years, 

2014–2018. ONRR used five calendar 

years of royalty data to reduce volatility 

caused by fluctuations in commodity 

pricing and volume swings. ONRR 

adjusted the historical data in this 

analysis to calendar year 2018 dollars 

using the Consumer Price Index (all 

items in U.S. city average, all urban 

consumers) published by the BLS. 

ONRR found that some companies 

aggregate their natural gas volumes from 

multiple leases into pools and sell that 

gas under multiple contracts. A lessee 

reports those sales and dispositions 

using the ‘‘POOL’’ sales type code. Only 

a small portion of these gas sales are 

non-arm’s-length. ONRR used estimates 

of 10 percent of the POOL volumes in 

the economic analysis of non-arm’slength 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’sLength Federal Unprocessed Gas, 

Residue Gas, Fuel Gas, and Coalbed 

Methane 

ONRR analyzed this provision 

similarly to the 2020 Rule, assuming 

that half of lessees would elect to use 

the index-based valuation method. 

ONRR received many comments stating 

that this assumption was flawed, 

because a lessee will typically act in a 

manner that maximizes, not harms, 

financial benefits to the lessee. ONRR 

stated in the 2020 Rule that the 

assumption that half of lessees would 

elect to use the index-based valuation 

option was an attempt to simplify the 

royalty impact estimation. Due to the 

delay rules, ONRR was able to apply a 

more sophisticated set of assumptions to 

accurately identify the lessees that 

would likely benefit from the 2020 

Rule’s amendments to the index-based 

valuation option and those that would 

not. ONRR began the analysis with a 

similar rationale on the same data that 

it used in the 2020 Rule’s calculation. 

ONRR reviewed the reported royalty 

data for all Federal gas sales except for 

non-arm’s-length transactions 

(discussed below), future valuation 

agreements, and percentage of proceeds 

(‘‘POP’’) contracts. ONRR also adjusted 

the POOL sales down to 90 percent (as 

described above), which were spread 

across 10 major geographic areas with 

active index prices. The 10 areas 

account for over 95 percent of all 

Federal gas produced. ONRR assumed 

the remaining five percent of lessees 

producing Federal gas will not elect the 

index-based method because areas 

outside of major producing basins may 

have infrastructure limitations or 

limited access to index pricing. The 10 

geographic areas are: 

1. Offshore Gulf of Mexico 

2. Big Horn Basin 

3. Green River Basin 

4. Permian Basin 

5. Piceance Basin 

6. Powder River Basin 

7. San Juan Basin 

8. Uinta Basin 

9. Williston Basin 

10. Wind River Basin 

To calculate the estimated royalty 

impact, ONRR: 

(1) Identified the monthly bidweek 

price index, published by Platts Inside 

FERC, for each applicable area— 

Northwest Pipeline Rockies for Green 

River, Piceance and Uinta basins; El 

Paso San Juan for San Juan basin; 

Colorado Interstate Gas for Big Horn, 

Powder River, Williston, and Wind 

River basins; El Paso Permian for 

Permian basin; and Henry Hub for the 

GOM. ONRR determined the 

applicability of a price index based on 

proximity to the producing area and the 

frequency with which ONRR’s audit and 

compliance staff verify these index 

prices in sales contracts; 

(2) subtracted the appropriate 

transportation deduction as described in 

the 2020 Rule from the midpoint index 

price identified in step (1); 

(3) compared the reported monthly 

price for each property inclusive of any 

reported transportation allowances to 

the applicable index price for the 

property calculated in step (2) for all 

months in the first year of reported 

royalty data in the dataset; 

(4) identified all properties in step (3) 

where the reported price exceeded the 

price calculated in step (2) for seven or 

more months in the time period; 

(5) used the property list created in 

step (4) as the base universe of 

properties that would elect to use the 

index-based valuation method available; 

(6) compared the actual reported price 

for each month for each property in the 

universe identified in step (5), inclusive 

of transportation allowances reported, to 

the calculated price in step (2) to 

identify the difference between what 

was reported as actual royalties and 

what would have been reported as 

royalties under the terms of the indexbased valuation method; 

(7) performed this calculation and 

comparison for the next two sets of twoyear time periods in the remaining four 

years of royalty reporting in the dataset; 

and 

(8) Calculated the total difference in 

the four years between the original 

reported royalty prices and royalties of 

the identified property universe that 

elected the index-based valuation 

method, then divided that total by four 

to get an annual estimated royalty 

impact. 

This new method of identification of 

the property universe that would elect 

the index-based valuation method if 

given the opportunity is the basis for the 

differences between the estimated 

royalty impact published in the 2020 

Rule and the estimated royalty impact 

included in this proposed rule. Also, 

this identification of the properties that 

stand to benefit is similar to how a 

lessee will make its decisions and is a 

better method to estimate the royalty 

impact. 

ONRR estimates the index-based 

valuation method in the 2020 Rule will 

decrease royalty payments on arm’slength natural gas by approximately 

$6.8 million per year when compared to 

ONRR regulations in effect prior to the 


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2020 Rule. ONRR requests comments on the assumptions in the method 

described above. 

ANNUAL CHANGE IN ROYALTIES PAID USING INDEX-BASED METHOD FOR ARM’S-LENGTH GAS SALES IF 2020 RULE IS

WITHDRAWN

Gulf of 

Mexico 

Onshore 

basins Total 

Annualized Reported Royalties from Identified Lease Universe ................................................. $51,720,000 $168,850,000 $220,570,000 

Royalties Estimated using Index-Based Valuation Method for Lease Universe ......................... 53,940,000 159,790,000 213,730,000 

Difference ............................................................................................................................. (2,220,000) 9,060,000 6,840,000 

Change in Royalties 2: Using the IndexBased 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’slength sales of NGLs. As in the previous 

section, ONRR’s goal was to identify a 

universe of properties that would 

benefit financially from electing the 

index-based valuation method. In the 

2020 Rule, ONRR assumed that half of 

the lessees would elect the method 

without regard to financial benefit or 

harm. 

ONRR used the same dataset for this 

analysis that was used in the 2020 Rule. 

It included all NGL sales except for nonarm’s-length transactions and future 

valuation agreements. ONRR also 

adjusted the POOL sales down to 90 

percent (as described above). These 

sales were spread across the same 10 

major geographic areas with active 

index prices for this analysis. To 

calculate the estimated royalty impact of 

the index-based valuation method on 

NGLs from Federal properties, ONRR: 

(1) Identified the Platts Oilgram Price 

Report Price Average Supplement 

(Platts Conway) or OPIS LP Gas Spot 

Prices Monthly (OPIS Mont Belvieu) for 

published monthly midpoint NGL 

prices per component applicable to each 

area: Platts Conway for Williston and 

Wind River basins; and OPIS Mont 

Belvieu non-TET for the Gulf of Mexico, 

Big Horn, Green River, Permian, 

Piceance, Powder River, San Juan, and 

Uinta basins. In ONRR’s audit 

experience, OPIS’ prices are used to 

value NGLs in contracts more frequently 

at Mont Belvieu, and Platts’ prices are 

used more frequently at Conway; 

(2) calculated an NGL basket prices 

(weighted average prices to group the 

individual NGL components), which 

compared to the imputed price from the 

monthly royalty report. The baskets 

illustrate the difference in the gas 

composition between Conway, Kansas 

and Mont Belvieu, Texas. The NGL 

basket hydrocarbon allocations are: 

Platts Conway Basket OPIS Mont Belvieu Basket 

Ethane-propane (EP mix) ............................................. 40% Ethane .......................................................................... 42% 

Propane ........................................................................ 28 Non-TET Propane ........................................................ 28 

Isobutane ...................................................................... 10 Non-TET Isobutane ...................................................... 6 

Normal Butane .............................................................. 7 Normal Butane .............................................................. 11 

Natural Gasoline ........................................................... 15 Natural Gasoline ........................................................... 13 

(3) subtracted the current processing 

deductions, as well as fractionation 

costs and transportation costs 

referenced in ONRR regulations without 

amendment by the 2020 Rule and 

published online at https://

www.onrr.gov, as shown in the table 

below from the NGL basket price 

calculated in step (2): 

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 property inclusive of any 

reported transportation or processing 

allowances to the applicable index price 

for the property calculated in step (3) for 

all months in the first year of reported 

royalty data in the dataset; 

(5) identified all properties in step (4) 

where the reported price exceeded the 

price calculated in step (3) for seven or 

more months in the time period; 

(6) used the property list created in 

step (5) as the base universe of 

properties that would elect to use the 

index-based valuation method if 

available; 

(7) compared the actual reported price 

for each month for each property in the 

universe identified in step (6), inclusive 

of transportation and processing 

allowances reported, to the calculated 

price in step (3) to identify the 

difference between what was reported 

as actual royalties and what would have 

been reported as royalties under the 

terms of the index-based valuation 

method; 

(8) performed this calculation and 

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Federal Register / Vol. 86, No. 111 / Friday, June 11, 2021 / Proposed Rules 31211 

year time periods in the remaining four 

years of royalty reporting in the dataset; 

and 

(9) calculated the total difference in 

the four years between the original 

reported royalty prices and the royalties 

if the identified property universe 

elected the index-based valuation 

method, then divided that total by four 

to get an annual estimated royalty 

impact. 

This new method of identification of 

the property universe that would elect 

the index-based valuation method is the 

basis for the difference between the 

estimated royalty impact published in 

the 2020 Rule and the estimated royalty 

impact included in this proposed rule. 

ONRR estimates the index-based 

valuation method in the 2020 Rule will 

decrease royalty payments on arm’slength NGLs by approximately $660,000 

per year, and that withdrawing the rule 

will increase royalty payments by 

$660,000 annually. ONRR requests 

comments on the assumptions in the 

method described above. 

ANNUAL CHANGE IN ROYALTIES PAID USING INDEX-BASED VALUATION METHOD FOR ARM’S-LENGTH NGL SALES IF 2020 

RULE IS WITHDRAWN

Gulf of Mexico New Mexico Other Areas Total 

Annualized Reported Royalties from Identified Lease Universe ..................... $4,990,000 $350,000 $9,100,000 $14,440,000 

Royalties Estimated Using Index-Based Valuation Method for Lease Universe ............................................................................................................. 3,470,000 290,000 10,020,000 13,780,000 

Annual Net Change in Royalties Paid Using Index-Based Valuation 

Method for NGLs .................................................................................. 1,520,000 60,000 (920,000) 660,000 

Change in Royalties 3: Using the 

Average Index Price Versus the Highest 

Published Index Price To Value NonArm’s-Length Federal Unprocessed Gas, 

Residue Gas, Coalbed Methane, and 

NGLs 

In the 2020 Rule, ONRR amended the 

index-based valuation method to use the 

average published bidweek price, rather 

than the highest published bidweek 

price, for the appropriate index-pricing 

point. ONRR accounted for the impacts 

to royalty collections attributable to 

arm’s-length natural gas transactions in 

the earlier section. This section will 

focus on the impact to royalty 

collections only attributable to nonarm’s-length natural gas transactions. 

The method for calculation in this 

proposed rule is similar to the method 

used in the 2020 Rule with adjustments 

made related to the universe of 

properties that would elect the indexbased valuation method. ONRR 

compared the monthly prices reported 

to it in the first year of the data period, 

inclusive of transportation allowances, 

to the index prices for the appropriate 

producing areas, inclusive of 

transportation deductions. ONRR then 

identified the properties with reported 

prices higher than the index price in 

seven or more months of the year. For 

non-arm’s-length natural gas sales, this 

equates to 56.4 percent of the entire list 

of properties, and represents a 

percentage that is higher than the 50 

percent assumption made by ONRR in 

the 2020 Rule’s estimated impacts on 

royalty collections of this same 

provision. This new percentage 

incorporates a more logical 

identification of the properties taking 

into account a lessee’s potential 

financial benefit. 

ONRR used reported royalty data 

using non-arm’s-length (‘‘NARM’’) sales 

and 10 percent of the POOL sales type 

codes based on the assumption above in 

the same 10 major geographic areas with 

active index-pricing points, also listed 

above. 

To calculate the estimated impact, 

ONRR: 

(1) Identified the Platts Inside FERC 

published monthly midpoint and high 

prices for the index applicable to each 

area—Northwest Pipeline Rockies for 

Green River, Piceance and Uinta basins; 

El Paso San Juan for San Juan basin; 

Colorado Interstate Gas for Big Horn, 

Powder River, Williston, and Wind 

River basins; El Paso Permian for 

Permian basin; and Henry Hub for the 

Gulf of Mexico; 

(2) multiplied the royalty volume by 

the published index prices identified for 

each region; 

(3) totaled the estimated royalties 

using the published index prices 

calculated in step (2); 

(4) calculated the annual average 

index-based royalties for both the high 

and volume-weighted-average prices 

calculated in step (3) by dividing by five 

(number of years in this analysis); and 

(5) subtracted the difference between 

the totals calculated in step (4). 

Because ONRR identified that 56.4 

percent of properties fall in the universe 

of properties that would elect the indexbased valuation method, ONRR reduced 

the total estimate by 43.6 percent in the 

following table. ONRR estimated that 

the result of this change is that the 2020 

Rule, if it went into effect, would result 

in a decrease in annual royalty 

payments of approximately $5 million, 

and a withdrawal of that rule would 

result in an increase in annual royalty 

payments by a like amount, as reflected 

in the table below. 

ESTIMATED IMPACT TO ROYALTY COLLECTIONS DUE TO WITHDRAWAL OF 2020 RULE’S HIGH TO MIDPOINT MODIFICATION

FOR NON-ARM’S-LENGTH SALES OF NATURAL GAS USING INDEX-BASED VALUATION METHOD

Gulf of Mexico Onshore 

basins Total 

Royalties Estimated Using High Index Price ............................................................................... $107,736,000 $198,170,000 $305,907,000 

Royalties Estimated Using Published Average Bidweek Price ................................................... 107,448,000 189,483,000 296,931,000 

Annual Change in Royalties Paid due to High to Midpoint Change .................................... 288,000 8,687,000 8,975,000 

56.4% of applicable properties .................................................................................................... ........................ ........................ 5,062,000 


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Change in Royalties 4: Modifying the 

Index-Based Valuation Method To 

Account for Transportation in Valuing 

Non-Arm’s-Length Federal Unprocessed 

Gas, Residue Gas, and Coalbed Methane 

The 2020 Rule increased the 

reductions to index price to account for 

transportation of production valued 

under the non-arm’s-length index-based 

valuation method. ONRR used the new 

method described previously in this 

Economic Analysis to identify the likely 

lease universe of non-arm’s-length 

natural gas sales. ONRR identified the 

same 56.4 percent of non-arm’s-length 

natural gas properties as the universe 

that would elect the method. 

To estimate the royalty impact of the 

change in amount intended to account 

for transportation, ONRR used reported 

royalty data using NARM and 10 

percent of the POOL sales type codes 

from the same 10 major geographic areas 

with active index-pricing points listed 

above. 

To calculate the estimated impact, 

ONRR: 

(1) Identified appropriate areas using 

Platts Inside FERC index prices (see list 

above); 

(2) calculated the transportationrelated adjustment as published in the 

current regulations and the adjustment 

outlined in the table below for each area 

identified in step (1); 

TRANSPORTATION DEDUCTION OF INDEX-BASED VALUATION METHOD FOR NON-ARM’S-LENGTH GAS

[$/MMBtu] 

Element 

2016 

Valuation 

Rule 

2020 Rule 

Gulf of Mexico % ..................................................................................................................................................... 5% 10% 

Gulf of Mexico Low Limit ......................................................................................................................................... $0.10 $0.10 

Gulf of Mexico High Limit ........................................................................................................................................ $0.30 $0.40 

Other Areas % ......................................................................................................................................................... 10% 15% 

Other Areas Low Limit ............................................................................................................................................. $0.10 $0.10 

Other Areas High Limit ............................................................................................................................................ $0.30 $0.50 

(3) multiplied the royalty volume by 

the applicable transportation deduction 

identified for each area calculated in 

step (2); 

(4) totaled the estimated royalty 

impact based off both transportation 

deductions calculated in step (3); 

(5) calculated the annual average 

royalty impact for both methods 

calculated in step (4) by dividing by five 

(number of years in this analysis); and 

(6) subtracted the difference between 

the totals calculated in step (5). 

Because ONRR identified the universe 

of 56.4 percent of lessees that will likely 

elect this method, ONRR reduced the 

total estimated impact to royalty 

collections by 43.6 percent. ONRR 

estimated the change will result in a 

decrease in royalty collections of 

approximately $8 million per year if the 

2020 Rule goes into effect, and an 

increase in royalty collections of like 

amount if the 2020 Rule is withdrawn, 

as reflected in the table below. 

ANNUAL ROYALTY IMPACT DUE TO TRANSPORTATION DEDUCTION MODIFICATION FOR NON-ARM’S-LENGTH SALES OF

NATURAL GAS IF 2020 RULE IS WITHDRAWN

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 properties ....................................................................................................... ........................ ........................ 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. ONRR adopted the same 

calculation method for these royalty 

impacts as it did in the 2020 Rule. Using 

the approvals ONRR granted prior to the 

2016 Valuation Rule, ONRR identified 

the 127 leases claiming an extraordinary 

processing allowance for residue gas, 

sulfur, and carbon dioxide (CO2) for 

calendar years 2014–2018. The total 

processing costs are reported across all 

three products for these unique 

situations. For these leases, ONRR 

retrieved all form ONRR–2014 royalty 

lines with a processing allowance 

reported by lessees. For CO2 and sulfur 

produced from these leases, ONRR then 

calculated the annual average 

processing allowances which exceeded 

the 662⁄3 percent limit and found that 

only two years exceeded the 662⁄3

percent limit. Under these unique 

approved exceptions, the processing 

allowances are also reported against 

residue gas. To account for this, ONRR 

added the average annual processing 

allowances taken from those same leases 

for residue gas. Based on these 

calculations, ONRR estimates the 

royalty impact of withdrawing this 

provision of the 2020 rule would be an 

increase in royalties of $11.1 million per 

year. 

ONRR recognizes that there could be 

an increase in the number of requests 

submitted to ONRR related to 

extraordinary cost processing 

allowances under this provision. There 

is little data available to identify the 

magnitude of these requests, and there 

is not enough information to determine 

how many of these potential requests 

would be approved or denied by ONRR. 

ONRR invites public comment on this 

issue and solicits any data that would 

allow the agency to better quantify these 

impacts. 


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ESTIMATED ANNUAL CHANGE IN ROYALTY COLLECTIONS IF 2020 RULE IS WITHDRAWN

Annual Average Sulfur Allowances in Excess of 662⁄3% .................................................................................................................... $348,000 

Annual Average Residue Gas Allowance ........................................................................................................................................... 10,783,000 

Estimated Annual Impact on Royalties ............................................................................................................................................... 11,131,000 

Change in Royalties 6: Transportation 

Allowances for Certain OCS Gathering 

for Federal Oil and Gas 

In the 2020 Rule, ONRR proposed 

regulatory changes that would allow an 

OCS lessee to take certain gathering 

costs as transportation. ONRR adjusted 

its method for calculating this royalty 

impact in response to comments 

received on the Proposed 2020 Rule and 

published a corrected method in the 

2020 Rule. ONRR will continue to use 

the adjusted method here to estimate the 

royalty impact if the 2020 Rule goes into 

effect. 

As previously discussed, the 

Deepwater Policy was in effect from 

1999 until January 1, 2017. Under the 

Deepwater Policy, ONRR allowed a 

lessee to treat certain costs for subsea 

gathering as transportation expenses 

and to deduct those costs in calculating 

its royalty obligations. The 2016 

Valuation Rule rescinded the Deepwater 

Policy, but the 2020 Rule would codify 

a deepwater gathering allowance similar 

to the Deepwater Policy. To analyze the 

impact to industry of 2020 Rule’s 

deepwater gathering allowance, ONRR 

used data from BSEE’s Technical 

Information Management System 

database to identify 113 subsea pipeline 

segments, and 169 potentially eligible 

leases, which might have qualified for 

an allowance thereunder. ONRR 

assumed that all segments were similar 

(in other words, no adjustments were 

made to account for the size, length, or 

type of pipeline) and considered only 

the pipeline segments that were active 

and supporting producing leases. To 

determine the range (shown in the 

tables at the end of this section as low, 

mid, and high estimates) of changes to 

royalties, ONRR estimated a 15 percent 

error rate in the identification of the 113 

eligible pipeline segments. This resulted 

in a range of 96 to 130 eligible pipeline 

segments. ONRR’s audit data is 

available for 13 subsea gathering 

segments serving 15 leases covering 

time periods from 1999 through 2010. 

ONRR used the data to determine an 

average initial capital investment in the 

pipeline segments. Then, ONRR used 

the initial capital investment total to 

calculate depreciation and a return on 

undepreciated capital investment (also 

known as the return on investment or 

‘‘ROI’’) for eligible pipeline segments 

and calculated depreciation using a 20- 

year straight-line depreciation schedule. 

ONRR calculated the return on 

investment using the average BBB Bond 

rate for January 2018 (the BBB Bond 

rating is a credit rating used by the 

Standard & Poor’s credit agency to 

signify a certain risk level of long-term 

bonds and other investments). ONRR 

based the calculations for depreciation 

and ROI on the first year a pipeline was 

in service. From the same audit 

information, ONRR calculated an 

average annual operating and 

maintenance (‘‘O&M’’) cost. ONRR 

increased the O&M cost by 12 percent 

to account for overhead expenses. 

ONRR then decreased the total annual 

O&M cost per pipeline segment by nine 

percent because, on average, nine 

percent of wellhead production volume 

is water, which must be excluded from 

any calculation of a permissible 

deduction. ONRR chose these two 

percentages based on knowledge and 

information gathered during audits of 

leases located in the GOM. Finally, 

ONRR used an average royalty rate of 14 

percent, which is the volume-weightedaverage royalty rate for the non-Section 

6 leases in the GOM (See 43 U.S.C. 

1335(a)(9)). Based on these calculations, 

the average annual allowance per 

pipeline segment during the period that 

ONRR collected data from was 

approximately $233,000. ONRR used 

this value to calculate a per-lease cost 

based on the number of eligible leases 

during the same period. ONRR then 

applied this value to the current number 

of eligible leases. This represented the 

estimated amount per lease for gathering 

that ONRR would allow a lessee to take 

as a transportation allowance based on 

the 2020 Rule’s deepwater gathering 

allowance. To calculate a range for the 

total cost, ONRR multiplied the average 

annual allowance by the low (96), mid 

(113), and high (130) number of 

potentially eligible segments. The low, 

mid, and high annual allowance 

estimates are $35 million, $41.1 million, 

and $47.3 million, respectively. 

Of the eligible leases, 68 of 169, or 

about 40 percent, are estimated to 

qualify for a deduction under the 2020 

Rule’s deepwater gathering allowance. 

But due to varying lease terms, multiple 

royalty relief programs, price 

thresholds, volume thresholds, and 

other factors, ONRR estimated that half 

of the 68, or 34, leases eligible for 

royalty relief (20 percent of 169) have 

received royalty relief, which limits the 

value of a deepwater gathering 

allowance. ONRR chose to use an 

estimate of half of the leases for 

consistency, and it decreased the low, 

mid, and high annual cost-to-industry 

estimates by 20 percent. The table below 

shows the estimated royalty impact of 

withdrawing this provision of the 2020 

Rule. 

ANNUAL ESTIMATED IMPACT TO ROYALTY COLLECTIONS IF 2020 RULE IS WITHDRAWN

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 qualified lessees to monitor 

their costs and perform additional 

calculations. ONRR identified no need 

to adjust or change the analysis 

performed in the 2020 Rule to estimate 

this cost to industry. The cost to 

perform these calculations is significant 

because industry often hires additional 

labor or outside consultants to calculate 

subsea pipeline movement costs. ONRR 

estimates that each lessee with leases 

eligible for transportation allowances for 

deepwater gathering systems will 

allocate one full-time employee 

annually (or incur the equivalent cost 

for an outside consultant) to perform the 

calculation. ONRR used data from the 


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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 IF 2020 RULE

IS WITHDRAWN

Annual 

burden 

hours per 

company 

Industry 

labor cost/ 

hour 

Companies 

reporting 

eligible 

leases 

Estimated 

cost savings 

to industry 

Allowance for Certain OCS Gathering Costs .................................................. 2,080 $59.26 32 $3,931,000 

Cost 1: Administrative Cost From Using 

Index-Based Valuation Method To 

Value Arm’s-Length Federal 

Unprocessed Gas, Residue Gas, Fuel 

Gas, Coalbed Methane, and NGLs 

In the 2020 Rule, ONRR assumed that 

half of the lessees would elect to use the 

index-based valuation method to value 

their arm’s-length natural gas and NGL 

transactions. As described earlier in this 

Economic Analysis, ONRR identified 

that 39.8 percent of properties with 

arm’s-length sales would elect this 

option. This is more accurate than the 

2020 Rule assumption, and ONRR will 

use it to estimate the potential 

administrative cost savings for industry. 

ONRR estimated the index-based 

valuation method will shorten the time 

burden per line reported by 50 percent 

(to 1.5 minutes per electronic line 

submission and 3.5 minutes per manual 

line submission). As with Cost Savings 

1, ONRR used tables from the BLS to 

estimate the fully burdened hourly cost 

for an industry accountant in a 

metropolitan area working in oil and gas 

extraction. The industry labor cost 

factor for accountants would be 

approximately $59.26 per hour = 

[$42.33 (mean hourly wage) × 1.4 

(including employee benefits)]. Using a 

labor cost factor of $59.26 per hour, 

ONRR estimates the annual 

administrative cost to industry will be 

approximately $1.1 million if the 2020 

Rule is withdrawn. 

ANNUAL ADMINISTRATIVE COSTS TO INDUSTRY IF 2020 RULE IS WITHDRAWN

Time burden 

per line 

reported 

Estimated 

lines 

reported 

using index 

option 

(50%) 

Annual 

burden hours 

Electronic Reporting (99%) .......................................................................................................... 1.5 min 710,525 17,763 

Manual Reporting (1%) ................................................................................................................ 3.5 min 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 lessees elect 

to use the index-based valuation 

method. ONRR believes this calculation 

and method are still adequate and will 

use the same information again in this 

rule. Use of the index-based valuation 

method eliminates the need to segregate 

deductible costs of transportation and 

processing from non-deductible costs of 

placing production in marketable 

condition. This segregation or allocation 

of costs, is often referred to as 

‘‘unbundling.’’ Industry would 

unbundle transportation systems and 

processing plants one time in the 

absence of the 2020 Rule, and then use 

those unbundled cost allocations for 

subsequent royalty calculations. While 

industry is responsible for calculating 

these costs, ONRR has published and 

calculated several unbundling cost 

allocations. It takes approximately 100 

hours of labor per gas plant. ONRR 

calculated the average number of gas 

plants reported per payor to be 3.4, 

across a total of 448 payors reporting 

residue gas and NGLs, between 2014– 

2018. Using the BLS labor cost per hour 

of $59.26 (described above) and 

adjusting the assumption to half of 

lessees choosing the index-based 

valuation method, ONRR believes the 

2020 Rule would have resulted in a onetime cost savings to industry of $4.5 

million dollars. If the 2020 Rule is 

withdrawn, lessees will incur this onetime administrative cost. 

State and Local Governments 

ONRR estimated that, as a result of 

the 2020 Rule, States and certain local 

governments would receive an overall 

decrease in royalty disbursements based 

on the category that properties fall 

under, including OCSLA section 8(g) 

leases (See 43 U.S.C. 1337(g)), GOMESA 

(See 43 U.S.C. 1331 et seq.), and 

onshore Federal lands. ONRR disburses 

royalties based on where the royaltybearing oil and gas was produced. 

Except for production from Federal 

leases in Alaska (where Alaska receives 

90 percent of the distribution), Section 

8(g) leases in the OCS, and qualified 

leases under GOMESA in the OCS (more 

information on distribution percentages 

at https://revenuedata.doi.gov/how-itworks/gomesa/), the following 

distribution table generally applies: 

ONRR DISBURSEMENTS BY AREA

Onshore Offshore 

Federal .............. 51% 95.2% 

State ................. 49% 4.8% 


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Please visit https://

revenuedata.doi.gov/explore/#federaldisbursements to find more information 

on ONRR’s disbursements to any 

specific State or local government. More 

specific details about estimated royalty 

disbursement impacts can be found 

below. 

Indian Lessors 

The provisions in the 2020 Rule and 

this proposed withdrawal are not 

expected to affect Indian lessors. 

Federal Government 

The impact of the 2020 Rule to the 

Federal Government will be a decrease 

in royalty collections. ONRR estimates 

the impact to the Federal Government 

(detailed in the next table of this 

section) would be a reduction in 

royalties of $49.7 million per year. If the 

2020 Rule is withdrawn, this estimated 

impact to royalty collections relative to 

the 2020 Rule would be an increase in 

royalties of $49.7 million per year. 

Summary of Royalty Impacts and Costs 

to Industry, State and Local 

Governments, Indian Lessors, and the 

Federal Government 

The table below shows the updated 

net change in royalties expected under 

withdrawal of the 2020 Rule. The table 

breaks out the impacts to Federal and 

State disbursements based on the 

typical distributions noted in the table 

above and the appropriate product 

weightings and the location of the 

affected properties. 

WITHDRAWAL OF THE 2020 RULE: ANNUAL IMPACT TO ROYALY COLLECTIONS, THE FEDERAL GOVERNMENT, AND STATES

Rule provision 

Impact to 

royalty 

collections 

Federal 

portion 

State 

portion 

Index-Based Valuation Method Extended to Arm’s-Length Gas Sales ...................................... $6,800,000 $4,180,000 $2,620,000 

Index-Based Valuation Method Extended to Arm’s-Length NGL Sales ..................................... 660,000 430,000 230,000 

High to Midpoint Index Price for Non-Arm’s-Length Gas Sales ................................................. 5,060,000 3,110,000 1,950,000 

Transportation Deduction Non-Arm’s-Length Index-Based Valuation Method ........................... 8,030,000 4,930,000 3,100,000 

Extraordinary Processing Allowance ........................................................................................... 11,130,000 5,680,000 5,450,000 

Allowance for Certain OCS Gathering Costs .............................................................................. 32,900,000 31,320,000 1,580,000 

Total ...................................................................................................................................... 64,600,000 49,700,000 14,900,000 

Note: totals may not add due to rounding. 

Federal Oil and Gas Amendments With 

No Estimated Change to Royalty or 

Regulatory Costs 

Change 1: Eliminate Reference to 

Default Provision Requirements for 

Federal Oil and Gas 

The 2020 Rule removed the default 

provision from its regulations. In 

instances of misconduct, breach of a 

lessee’s duty to market, or other 

situations where royalty value cannot be 

determined under the rules, ONRR can 

use statutory authority to determine 

Federal oil and gas royalty value under 

lease terms, FOGRMA, and other 

authorizing legislation in the same 

manner—as ONRR would have prior to 

adoption of the 2016 Valuation Rule. 

There is no impact to royalty collections 

on account of the default provision 

regardless of whether the Final 2020 

Rule goes into effect or is withdrawn in 

whole or part. 

Federal and Indian Coal 

In the 2020 Rule, ONRR estimated 

there will be no change to royalty 

collections for the Federal Government, 

Tribes, individual Indian mineral 

owners, States, or industry for Federal 

and Indian coal. ONRR has not changed 

or adjusted this estimate in this 

proposed rule. There is no impact to 

royalty collections on account of the 

coal provisions in the 2020 Rule 

regardless of whether the 2020 Rule 

goes into effect or is withdrawn in 

whole or part. 

IV. Request for Public Comments 

ONRR is proposing to withdraw the 

2020 Rule. For ONRR’s consideration, 

before reaching a final decision on this 

action, ONRR requests comments, 

without limitation, on this proposed 

action. ONRR is also requesting any 

comments pertaining to the substance or 

merits of the 2020 Rule, and the prior 

regulatory scheme it replaced. 

Additionally, ONRR seeks public 

comment on the following: 

1. Should ONRR withdraw only the 

deepwater gathering allowance, 

extraordinary processing allowance, 

and/or index-based valuation provisions 

of the 2020 Rule, all of which reduce 

royalties; withdraw all royalty valuation 

provisions of the 2020 Rule; or allow all 

royalty valuation provisions 2020 Rule 

to go into effect? 

2. Should ONRR allow some or all of 

the 2020 Rule’s civil penalty 

amendments, at 30 CFR part 1241, to go 

into effect? Or should ONRR withdraw 

those amendments, and, if so, should it 

initiate a new civil penalty rulemaking 

on the same or different subjects? 

3. What impacts, if any, or other 

information should ONRR consider if it 

were to adopt a final rule to either 

withdraw the deepwater gathering 

allowance, extraordinary processing 

allowance, and index-based valuation 

amendments of the 2020 Rule, or 

withdraw the 2020 Rule in its entirety, 

and make the withdrawal effective 

immediately upon publication under 5 

U.S.C. 553(d)(1) or (3)? 

4. This proposed rule provides a 

revised economic analysis of the Final 

2020 Rule’s amendments to the indexbased valuation method. The updated 

analysis shows the net impact of the 

amendments is an estimated decrease of 

$20.6M in royalty collection per year 

(from table above, $6,800,000 + 

$660,000 + $5,062,000 + $8,033,000). 

Because the new analysis is presented 

for the first time in this rule, the public 

has not been given an opportunity to 

comment on the new analysis. ONRR 

invites public comment on the new 

information, methods ONRR used to 

perform its estimates, and whether it 

justifies withdrawal of some or all of the 

Final 2020 Rule’s amendments to indexbased valuation. 

V. Procedural Matters 

A. Regulatory Planning and Review 

(E.O. 12866 and 13563) 

E.O. 12866 provides that the Office of 

Information and Regulatory Affairs 

(‘‘OIRA’’) of OMB will review all 

significant rulemakings. This proposed 

rule is a significant regulatory action 

under E.O. 12866. Because the primary 

effect is on royalty payments, ONRR 

expects that withdrawal of the 2020 

Rule will largely result in transfers, 

which are described in the table below. 

ONRR also anticipates that withdrawal 

of the 2020 Rule would result in annual 

administrative cost savings of $2.85 


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million and a one-time administrative 

cost of $4.52 million. 

Please note that, unless otherwise 

indicated, numbers in the tables in this 

section are rounded to the nearest 

thousand, and that the totals may not 

match due to rounding. 

SUMMARY OF ESTIMATED CHANGES TO ROYALTY COLLECTIONS FROM WITHDRAWAL OF 2020 RULE

[Annual] 

Rule provision 

Net change 

in royalties 

paid by 

lessees 

Index-Based Valuation Method Extended to Arm’s-Length Gas Sales .............................................................................................. $6,800,000 

Index-Based Valuation Method Extended to Arm’s-Length NGL Sales ............................................................................................. 660,000 

High to Midpoint Index Price for Non-Arm’s-Length Gas Sales ......................................................................................................... 5,062,000 

Transportation Deduction Non-Arm’s-Length Index-Based Valuation Method ................................................................................... 8,033,000 

Extraordinary Processing Allowances ................................................................................................................................................. 11,131,000 

Allowances for Certain OCS Gathering Costs .................................................................................................................................... 32,900,000 

Total .............................................................................................................................................................................................. 64,600,000 

To estimate the present value of 

potential administrative costs/savings to 

industry from withdrawal of the 2020 

Rule, ONRR looked at two potential 

time periods to represent various 

production lives of oil and gas leases. 

ONRR applied three percent and seven 

percent discount rates as described in 

OMB Circular A–4, using a base year of 

2021 and reported in 2020 dollars. As 

described above, ONRR estimates a cost 

to industry in the first year the 2020 

Rule is in effect and incursion of 

administrative cost savings each year 

thereafter. 

SUMMARY OF ANNUAL ADMINISTRATIVE IMPACTS TO INDUSTRY FROM WITHDRAWAL OF 2020 RULE

Rule provision Cost 

(cost savings) 

Administrative Cost Savings for Index-Based Valuation Method for Arm’s-Length Gas & NGL Sales ............................................. $1,077,000 

Administrative Cost for Allowances for Certain OCS Gathering ......................................................................................................... (3,931,000) 

Total .............................................................................................................................................................................................. (2,850,000) 

SUMMARY OF ONE-TIME ADMINISTRATIVE IMPACTS TO INDUSTRY FROM WITHDRAWAL OF 2020 RULE

Rule provision Cost 

Administrative Cost-Savings in lieu of Unbundling related to Index-Based Valuation Method for ARMS Gas & NGLs ................... $4,520,000 

NET PRESENT VALUE OF ADMINISTRATIVE IMPACTS TO INDUSTRY FROM WITHDRAWAL OF 2020 RULE

Time horizon 3% Discount 

rate 

7% Discount 

rate 

Administrative Costs over 10 years ......................................................................................................................... $19,920,000 $15,790,000 

Administrative Costs over 20 years ......................................................................................................................... 38,010,000 25,970,000 

E.O. 13563 reaffirms the principles of 

E.O. 12866, while calling for 

improvements in the nation’s regulatory 

system to promote predictability, to 

reduce uncertainty, and to use the most 

innovative and least burdensome tools 

for achieving regulatory ends. E.O. 

13563 directs agencies to consider 

regulatory approaches that reduce 

burdens and maintain flexibility and 

freedom of choice for the public where 

these approaches are relevant, feasible, 

and consistent with regulatory 

objectives. E.O. 13563 further 

emphasizes that regulations must be 

based on the best available science and 

that the rulemaking process must allow 

for public participation and an open 

exchange of ideas. ONRR developed this 

rule in a manner consistent with these 

requirements. 

B. Regulatory Flexibility Act 

The Regulatory Flexibility Act (5 

U.S.C. 601 et seq.) generally requires 

Federal agencies to prepare a regulatory 

flexibility analysis for rules that are 

subject to the notice-and-comment 

rulemaking requirements under the 

Administrative Procedure Act (5 U.S.C. 

553), if the rule would have a significant 

economic impact on a substantial 

number of small entities. See 5 U.S.C. 

601–612. 

For the changes to 30 CFR part 1206, 

this rule would affect lessees of Federal 

oil and gas leases. For the changes to 30 

CFR part 1241, this rule could affect 

alleged and actual violators of 

obligations under Federal and Indian 

mineral leases. Federal and Indian 

mineral lessees are, generally, 

companies classified under the North 

American Industry Classification 

System (‘‘NAICS’’), as follows: 

• Code 2111, Oil and Gas Extraction; 

and 

• Code 21211, Coal Mining. 

Under NAICS code classifications, a 

small company is one with fewer than 

500 employees. ONRR estimates that 


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approximately 1,208 different 

companies submit royalty reports for 

Federal oil and gas leases and other 

Federal mineral leases to ONRR each 

month. Of these, approximately 106 

companies are not considered small 

businesses because they exceed the 

employee count threshold for small 

businesses. ONRR estimated that the 

remaining 1,102 companies affected by 

this rule are small businesses. ONRR 

has not changed the determination it 

made in the 2020 Rule. See 86 FR 4651. 

As stated in the Summary of Royalty 

Impacts and Costs Table, shown above, 

withdrawal of the 2020 Rule would 

impact industry through an increase in 

royalties of approximately $64.6 million 

per year. Small businesses account for 

approximately eight percent of those 

royalties. Applying that percentage, 

ONRR estimates that withdrawal of the 

2020 Rule would increase royalty 

payments made by small-business 

lessees by approximately $5.2 million 

per year, or $4,690 per small business, 

on average. The extent of any royalty 

impact would vary between companies 

due to, for example, differences in the 

revenues generated by a small business 

that is subject to royalties. 

Also stated above, withdrawal of the 

2020 Rule would impact industry 

through a decrease in administrative 

costs of approximately $2.9 million per 

year and a first-year increase of $4.5 

million. Applying the eight percent 

small-business share, ONRR estimates 

that withdrawal of the 2020 Rule would 

decrease administrative costs to small 

business lessees by approximately $211 

per year and separately increase costs by 

$327 in the first year. 

In 2020, ONRR collected $6.3 billion 

in royalties from Federal oil and gas 

leases. Applying the eight-percent share, 

ONRR estimates that small-business 

lessees paid $504 million in royalties in 

2020. Most Federal oil and gas leases 

have a 12.5 percent royalty rate, which 

calculates to an estimated $4 billion in 

total small-business lessee revenue from 

the production and sale of Federal oil 

and gas ($504 million divided by .125). 

Thus, on average, ONRR estimates that 

small-business lessees earn $3.6 million 

in revenue per year from the production 

and sale of Federal oil and gas ($4 

billion divided by 1,102). 

The estimated increase in royalties 

($4,690) and decrease in administrative 

burden ($211) net to an increase in 

overall cost to 1,102 small businesses of 

$4,479 per year. As a percentage of 

average small-business revenue, this 

proposed rule would increase costs to 

those entities by 0.12 percent ($4,479 

divided by $3.6 million). 

According to the U.S. Census 

Bureau’s 2017 Economic Census data, 

oil and gas extractors with 20 employees 

or less collected $2.1 million per year 

per entity. Taking the $4,479 discussed 

above, divided by $2.1 million equals an 

estimated maximum impact of 0.2 

percent of total revenue per year. 

Further, ONRR anticipates that the 

smallest entities would realize less of an 

increase in royalties because, for 

example, the changes to deepwater 

gathering and extraordinary processing 

allowances are capital-intensive 

operations that small entities typically 

do not participate in. 

In accordance with 5 U.S.C. 605, the 

head of the agency certifies that this 

proposed rule would have an impact on 

a substantial number of small entities, 

but the economic impact on those small 

entities would not be significant under 

the Regulatory Flexibility Act. Thus, 

ONRR did not prepare a Regulatory 

Flexibility Act Analysis nor is a Small 

Entity Compliance Guide required. 

C. Small Business Regulatory 

Enforcement Fairness Act 

The 2020 Rule was not a major rule 

under Subtitle E of the Small Business 

Regulatory Enforcement Fairness Act of 

1996. See 5 U.S.C. 804(2). ONRR 

therefore expects that the withdrawal of 

the 2020 rule would likewise not be a 

major rule under that provision. Like 

the 2020 rule, ONRR anticipates that 

this rule, if finalized: 

(1) Would not have an annual effect 

on the economy of $100 million or 

more. ONRR estimates that the 

cumulative effect on all of industry if 

the 2020 Rule goes into effect would be 

a reduction in private cost of nearly 

$61.45 million per year, which is the 

sum of $64.6 million in decreased 

royalty payments and $2.85 million in 

additional costs due to increased 

administrative burdens. This net change 

in royalty payments would be a transfer 

rather than a cost or cost savings. The 

Summary of Royalty Impacts and Costs 

Table, as shown above, demonstrates 

that the 2020 Rule’s cumulative 

economic impact on industry, State and 

local governments, and the Federal 

Government would be well below the 

$100 million threshold that the Federal 

Government uses to define a rule as 

having a significant impact on the 

economy; 

(2) would not cause a major increase 

in costs or prices for consumers, 

individual industries, Federal, State, or 

local government agencies, or 

geographic regions. Please see the data 

tables in the Regulatory Planning and 

Review (E.O. 12866 and E.O. 13563) 

section above; and 

(3) would not have significant adverse 

effects on competition, employment, 

investment, productivity, innovation, or 

the ability of United States-based 

enterprises to compete with foreignbased enterprises. ONRR estimates no 

significant adverse impacts to small 

business. 

D. Unfunded Mandates Reform Act 

Neither the 2020 Rule nor its 

withdrawal would impose an unfunded 

mandate or have a significant effect on 

State, local, or Tribal governments, or 

on the private sector, of more than $100 

million per year. Therefore, ONRR is not 

required to provide a statement 

containing the information that the 

Unfunded Mandates Reform Act (2 

U.S.C. 1501 et seq.) requires because the 

2020 Rule or its withdrawal is an 

unfunded mandate. 

E. Takings (E.O. 12630) 

Under the criteria in section 2 of E.O. 

12630, neither the 2020 Rule nor its 

withdrawal have any significant takings 

implications. Neither rule imposes 

conditions or limitations on the use of 

any private property because they apply 

to the valuation of Federal oil and gas 

and Federal and Indian coal only. The 

2020 Rule only makes minor technical 

changes to ONRR’s civil penalty 

regulations that have no expected 

economic impact, and the withdrawal of 

the 2020 Rule would have no economic 

impact. Neither rule requires a takings 

implication assessment. 

F. Federalism (E.O. 13132) 

Under the criteria in section 1 of E.O. 

13132, the 2020 Rule or its withdrawal 

does not have sufficient federalism 

implications to warrant the preparation 

of a federalism summary impact 

statement. The management of Federal 

oil and gas is the responsibility of the 

Secretary, and ONRR distributes all of 

the royalties that it collects under 

Federal oil and gas leases as directed by 

the relevant disbursement statutes. The 

2020 Rule or its withdrawal would not 

impose administrative costs on States or 

local governments or substantially and 

directly affect the relationship between 

the Federal and State governments. 

Thus, a federalism summary impact 

statement is not required. 

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

The proposed withdrawal of the 2020 

Rule complies with the requirements of 

E.O. 12988. Specifically, the proposed 

withdrawal rule: 

(1) Meets the criteria of Section 3(a), 

which requires that ONRR review all 

regulations to eliminate errors and 

ambiguity to minimize litigation; and 


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(2) meets the criteria of Section 

3(b)(2), which requires that all 

regulations be written in clear language 

using clear legal standards. 

H. Consultation With Indian Tribal 

Governments (E.O. 13175) 

ONRR strives to strengthen its 

government-to-government relationship 

with Indian tribes through a 

commitment to consultation with Indian 

tribes and recognition of their right to 

self-governance and tribal sovereignty. 

ONRR evaluated the 2020 Rule and the 

proposed withdrawal under the 

Department’s consultation policy and 

the criteria in E.O. 13175 and 

determined that neither have substantial 

direct effects on Federally-recognized 

Indian tribes. Thus, consultation under 

ONRR’s tribal consultation policy is not 

required. 

ONRR reached this conclusion, in 

part, based on the consultations it 

conducted before the adoption of the 

2016 Valuation Rule. At that time, 

ONRR held six tribal consultations with 

the three tribes (Navajo Nation, Crow 

Nation, and Hopi Tribe) for which 

ONRR collected and disbursed Indian 

coal royalties. Upon the conclusion of 

each consultation, ONRR and the tribal 

partners determined that the 2016 

Valuation Rule would not have a 

substantial impact on any of the 

potentially impacted tribes. With the 

exception of the Kayenta Mine located 

in Navajo Nation, which ceased 

production in 2019, the circumstances 

relevant to the Indian coal leases have 

not changed since the prior 

consultations occurred. As with the 

2016 Valuation Rule, ONRR’s review of 

the royalty impact to tribes from the 

2020 Rule and its proposed withdrawal 

concludes that neither would 

substantially impact the three tribes. 

Further, neither rule is estimated to 

impact the royalty value of Indian coal. 

I. Paperwork Reduction Act (44 U.S.C. 

3501 et seq.) 

Certain collections of information 

require OMB’s approval under the 

Paperwork Reduction Act. The 2020 

Rule and its proposed withdrawal do 

not require any new or modify any 

existing information collections subject 

to OMB’s approval. Thus, ONRR did not 

submit any new information collection 

requests to OMB related to the 2020 

Rule or its proposed withdrawal. 

Both the 2020 Rule and its proposed 

withdrawal leave intact the information 

collection requirements that OMB has 

already approved under OMB Control 

Numbers 1012–0004, 1012–0005, and 

1012–0010. 

J. National Environmental Policy Act of 

1969 

The 2020 Rule and its proposed 

withdrawal do not constitute a major 

Federal action significantly affecting the 

quality of the human environment. 

ONRR is not required to provide a 

detailed statement under the NEPA 

because both rules qualify for a 

categorical exclusion under 43 CFR 

46.210(c) and (i), as well as the 

Departmental Manual, part 516, section 

15.4.D, which covers routine financial 

transactions including such things as 

audits, fees, bonds, and royalties and 

policies, directives, regulations, and 

guidelines that are of an administrative, 

financial, legal, technical, or procedural 

nature. ONRR also determined that both 

the 2020 Rule and its proposed 

withdrawal do not involve any of the 

extraordinary circumstances listed in 43 

CFR 46.215 that require further analysis 

under NEPA. 

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

13211) 

Both the 2020 Rule and its proposed 

withdrawal are not significant energy 

actions under the definition in E.O. 

13211. Neither is not likely to have a 

significant adverse effect on the supply, 

distribution, or use of energy. Moreover, 

the Administrator of OIRA has not 

otherwise designated either action as a 

significant energy action. A Statement of 

Energy Effects pursuant to E.O. 13211, 

therefore, is not required. 

L. Clarity of This Regulation 

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

(section 3(b)(1)(B)), E.O. 13563 (section 

1(a)), and the Presidential Memorandum 

of June 1, 1998, require ONRR to write 

all rules in plain language. This means 

that the rules ONRR publishes must use: 

(1) Logical organization. 

(2) Active voice to address readers 

directly. 

(3) Clear language rather than jargon. 

(4) Short sections and sentences. 

(5) Lists and tables wherever possible. 

If you believe that ONRR has not met 

these requirements, send your 

comments to ONRR_

RegulationsMailbox@onrr.gov. To better 

help ONRR understand your comments, 

please make your comments as specific 

as possible. For example, you should 

tell ONRR the numbers of the sections 

or paragraphs that you think were 

written unclearly, the sections or 

sentences that you think are too long, 

and the sections for which you believe 

lists or tables would be useful. 

This action is taken pursuant to 

delegated authority. 

List of Subjects 

30 CFR Part 1206 

Coal, Continental shelf, Geothermal 

energy, Government contracts, Indianslands, Mineral royalties, Oil and gas 

exploration, Public lands-mineral 

resources, Reporting and recordkeeping 

requirements. 

30 CFR Part 1241 

Administrative practice and 

procedure, Coal, Geothermal energy, 

Indians-lands, Mineral royalties, Natural 

gas, Oil and gas exploration, Penalties, 

Public lands-mineral resources. 

Rachael S. Taylor, 

Principal Deputy Assistant Secretary—Policy, 

Management and Budget. 

[FR Doc. 2021–12318 Filed 6–10–21; 8:45 am] 

BILLING CODE 4335–30–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R04–OAR–2020–0221; FRL–10024– 

71–Region 4] 

Air Plan Approval; TN; Knoxville Area 

Limited Maintenance Plan for the 1997 

8-Hour Ozone NAAQS 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: The Environmental Protection 

Agency (EPA) is proposing to approve a 

state implementation plan (SIP) revision 

submitted by the State of Tennessee, 

through the Tennessee Department of 

Environment and Conservation (TDEC), 

Air Pollution Control Division, via a 

letter dated January 23, 2020. The SIP 

revision includes the 1997 8-hour ozone 

national ambient air quality standards 

(NAAQS) Limited Maintenance Plan 

(LMP) for the Knoxville, Tennessee Area 

(hereinafter referred to as the ‘‘Knoxville 

Area’’ or ‘‘Area’’). The Knoxville Area, 

as defined in this proposed action, is 

comprised of Jefferson, Loudon, and 

Sevier Counties in their entireties, the 

portion of Cocke County that falls 

within the boundary of the Great Smoky 

Mountains National Park, and a portion 

of Anderson County that excludes the 

area surrounding TVA Bull Run Fossil 

Plant. EPA is proposing to approve the 

Knoxville Area LMP because it provides 

for the maintenance of the 1997 8-hour 

ozone NAAQS within the Knoxville 

Area through the end of the second 10- 

year portion of the maintenance period. 

The effect of this action would be to 

make certain commitments related to 


jbell on DSKJLSW7X2PROD with PROPOSALS