4612 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

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 

AGENCY: Department of the Interior, 

Office of the Secretary, Office of Natural 

Resources Revenue. 

ACTION: Final rule. 

SUMMARY: The Office of Natural 

Resources Revenue (‘‘ONRR’’) is 

amending certain regulations on how it 

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, leases, and 

orders associated with mineral leases. In 

addition, it is making some minor, nonsubstantive corrections to its 

regulations. 

DATES: Effective date: This rule is 

effective February 16, 2021. 

Compliance date: With respect to the 

amendments to 30 CFR part 1206 only, 

compliance is required for production 

that occurs on or after May 1, 2021. 

Compliance with the amendments to 30 

CFR part 1241 is required on the 

effective date. 

FOR FURTHER INFORMATION CONTACT: For 

questions on procedural issues, contact 

Dane Templin, Regulations Supervisor, 

at (303) 231–3149 or Dane.Templin@

onrr.gov. For questions on technical 

issues related to royalty valuation, 

contact Amy Lunt, Supervisor Royalty 

Valuation Team A, at (303) 231–3746 or 

Amy.Lunt@onrr.gov, or Peter 

Christnacht, Supervisor Royalty 

Valuation Team B, at (303) 231–3651 or 

Peter.Christnacht@onrr.gov. For 

questions on technical issues related to 

civil penalties, contact Michael 

Marchetti, Program Manager Office of 

Enforcement, at (303) 231–3125 or 

Michael.Marchetti@onrr.gov. 

SUPPLEMENTARY INFORMATION: 

Table of Contents 

I. Introduction 

A. ONRR’s Rulemaking Authority 

B. Rulemaking Objectives 

C. Executive Discretion is a Permissible 

Initiative for Rulemaking 

D. ONRR’s Relevant Prior Rulemakings and 

Associated Litigation 

E. Public Comment Overview 

II. Amendment Discussion—Part 1206 

Product Valuation 

A. Index-Based Valuation Method To 

Value Federal Gas 

B. Transportation Allowance for Certain 

Offshore Federal Oil and Gas Gathering 

Costs 

C. Allowance Limits for Federal Oil and 

Gas 

D. The Default Provision for Federal Oil, 

Gas, and Coal and Indian Coal 

E. ‘‘Misconduct’’ Definition for Federal Oil, 

Gas, and Coal and Indian Coal 

F. Contract Signature Requirement for 

Federal Oil, Gas, and Coal and Indian 

Coal 

G. Citation to Legal Precedent as Part of a 

Valuation Determination Request 

H. Coal Valued for Royalty Purposes Based 

on an Electricity Sale 

I. ‘‘Coal Cooperative’’ Definition 

III. Amendment Discussion—Part 1241 

Penalties 

A. Civil Penalties for Payment Violations 

B. Consideration of Aggravating and 

Mitigating Circumstances When ONRR 

Assesses a Civil Penalty 

C. Forfeiture of a Stay of the Civil Penalty 

Accrual Under Limited Circumstances 

IV. Non-Substantive Corrections 

V. Economic Analysis 

VI. Severability Statement 

VII. Procedural Matters 

A. Regulatory Planning and Review 

(Executive Orders 12866 and 13563) 

B. Regulatory Flexibility Act 

C. Small Business Regulatory Enforcement 

Fairness Act 

D. Unfunded Mandates Reform Act 

E. Takings (Executive Order 12630) 

F. Federalism (Executive Order 13132) 

G. Civil Justice Reform (Executive Order 

12988) 

H. Consultation With Indian Tribal 

Governments (Executive Order 13175) 

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

3501 et seq.) 

J. National Environmental Policy Act 

K. Effects on the Energy Supply (Executive 

Order 13211) 

L. Clarity of this Regulation 

M. Congressional Review Act 

TABLE OF ABBREVIATIONS AND COMMONLY USED ACRONYMS IN THIS 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 Postponement Notice ............ ONRR’s Notice of Postponement, 82 FR 11823 (February 27, 2017) (sought to stay implementation of the 

2016 Valuation Rule). 

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

2020 Proposed Rule ....................... ONRR’s 2020 proposed rule titled: ONRR 2020 Valuation Reform and Civil Penalty Rule, 85 FR 62054 

(October 1, 2020). 

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

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

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

APD ................................................. Application for a Permit to Drill. 

BLM ................................................. Bureau of Land Management. 

BLS ................................................. Bureau of Labor Statistics. 

BOEM .............................................. Bureau of Ocean Energy Management. 

BSEE ............................................... Bureau of Safety and Environmental Enforcement. 

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

Deepwater Policy ............................ MMS’s May 20, 1999, memorandum titled ‘‘Guidance for Determining Transportation Allowances for Production from Leases in Water Depths Greater Than 200 Meters’’. 

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

FCCP .............................................. Failure to Correct Civil Penalty. 

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

FLPMA ............................................ Federal Land Policy and Management Act of 1976. 

FOGRMA ........................................ Federal Oil and Gas Royalty Management Act of 1982. 

FY .................................................... Fiscal Year. 

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

IBLA ................................................ Interior Board of Land Appeals. 

ILCP ................................................ Immediate Liability Civil Penalty. 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4613 

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

Abbreviation What it means 

MLA ................................................. Mineral Leasing Act of 1920. 

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. 

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

Secretary ......................................... Secretary of the U.S. Department of the Interior. 

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

I. Introduction 

This final rule amends ONRR’s 

regulations under 30 CFR Chapter XII, 

Parts 1206 (product valuation) and 1241 

(penalties). In 30 CFR part 1206, this 

final rule amends certain definitions 

(Subpart A) and provisions used to 

value Federal oil (Subpart C), Federal 

gas (Subpart D), Federal coal (Subpart 

F), and Indian coal (Subpart J). In 30 

CFR part 1241, this final rule amends 

ONRR’s regulations on the practices it 

uses to assess civil penalties (Subparts 

A and C). 

This rule is effective 30 days after its 

publication in the Federal Register. 

However, ONRR recognizes that lessees 

typically report and pay royalties based 

on monthly production, sales, and costs. 

In addition, compliance with the 

requirements of the Rule will require 

system modifications by ONRR to 

accept reports and for industry reporters 

in order to submit reports. These system 

modifications will take some time to 

program. For those reasons, a separate 

compliance date is provided under the 

DATES caption to establish that—for the 

amendments to 30 CFR part 1206 only— 

lessees must conform to the amended 

requirements under this final rule 

beginning with production that occurs 

on and after May 1, 2021. 

As stated under the DATES caption, the 

amendments to 30 CFR part 1241 shall 

become effective on and compliance is 

required by February 16, 2021. 

ONRR explained in the 2020 

Proposed Rule that, with regard to 30 

CFR part 1206, several of ONRR’s 

proposed amendments would extend, 

revise, or remove regulations that ONRR 

had adopted through the 2016 Valuation 

Rule. See 85 FR 62054–62062. ONRR 

also explained the factors it was 

considering in its decision making, 

including: (1) Executive Orders (E.O.s) 

and Secretarial Orders (S.O.s) issued 

after the 2016 Valuation Rule’s effective 

date; (2) specific to coal cooperatives 

and coal valuation based on electricity 

sales, ONRR’s consideration of the 

parties’ briefs filed in litigation 

challenging the 2016 Valuation Rule 

and the court’s decision in that 

litigation to stay implementation of the 

rule’s Federal and Indian coal 

provisions; and (3) ONRR’s continued 

work to consider and implement 

regulatory changes that simplify or 

better explain ONRR’s processes, and to 

provide early clarity regarding royalties 

owed. See 85 FR 62054–62057. 

For 30 CFR part 1241, ONRR 

explained in the 2020 Proposed Rule 

that, in addition to some of the reasons 

listed above, ONRR was considering 

changes to its civil penalty practices to 

conform with a (subsequently-vacated) 

Federal District Court’s decision on an 

industry challenge to ONRR’s 2016 Civil 

Penalty Rule and to conform the civil 

penalty regulations to certain IBLA 

decisions. See 85 FR 62055 and 62056. 

ONRR finds that those reasons, 

additional reasons raised in public 

comments, and additional information 

(identified by ONRR or provided to 

ONRR by its sister agencies) warrant the 

amendments adopted in this final rule 

on the following topics: 

1. Allowing a lessee producing 

Federal oil and gas from the OCS under 

leases in water depths of 200 meters or 

greater to take a deduction for certain 

gathering costs as part of its 

transportation allowance. 

2. Allowing a lessee to apply to ONRR 

for approval to claim an extraordinary 

processing allowance for Federal gas in 

situations where the gas stream, plant 

design, and/or unit costs were 

extraordinary, unusual, or 

unconventional relative to standard 

industry conditions and practice. 

3. Removing the definition of 

‘‘misconduct’’ from 30 CFR part 1206 as 

it applies to Federal oil and gas, and 

Federal and Indian coal. 

4. Removing the default provision and 

references thereto from the regulations 

applying to Federal oil and gas, and 

Federal and Indian coal. 

5. Removing the requirement that a 

lessee have contracts signed by all 

parties in order for those contracts to be 

recognized valid and binding with 

respect to the valuation of Federal oil 

and gas, and Federal and Indian coal. 

6. Removing the requirement for a 

lessee to cite legal precedent when 

seeking a valuation determination for 

Federal oil and gas or a valuation 

decision for Federal or Indian coal. 

7. Expanding the option to use indexbased valuation to arm’s-length Federal 

gas sales, which, under the 2016 

Valuation Rule, was only available for 

non-arm’s-length Federal gas sales. 

8. For unprocessed and residue gas 

valued using the index-based valuation 

method, changing from the high index 

price to the average index price. 

9. Changing the transportation 

deductions allowed under an indexbased valuation method to reflect more 

recent transportation cost data reported 

to ONRR. 

10. Amending other regulation 

language to make non-substantive 

corrections so as to make the regulations 

more clear and workable. 

11. Amending ONRR’s Federal and 

Indian coal valuation regulations to 

remove the requirement to value certain 

coal based on the sale of electricity. 

12. Amending ONRR’s Federal and 

Indian coal valuation regulations to 

remove the definition of ‘‘coal 

cooperative’’ and the method to value 

sales between members of a ‘‘coal 

cooperative.’’ 

13. Amending ONRR’s civil penalty 

regulations to clarify that ONRR will 

consider the unpaid, underpaid, or late 

payment amounts in the severity 

analysis for payment violations only. 

14. Amending ONRR’s civil penalty 

regulations to clarify that ONRR may 

consider aggravating and mitigating 

circumstances when calculating the 

amount of a civil penalty. 

15. Amending ONRR’s civil penalty 

regulations to remove an ALJ’s ability to 

vacate the benefit of a stay of an accrual 

of penalties if the ALJ later determines 

that a violator’s defense to a notice of 

noncompliance was frivolous. 

This rule does not adopt three 

amendments that ONRR proposed in the 

2020 Proposed Rule. This rule does not: 

1. Remove or otherwise amend the 

regulatory cap on transportation 

allowances for Federal oil and gas. 

4614 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

2. Remove or otherwise amend the 

regulatory cap on processing allowances 

for Federal gas. 

3. Allow a lessee producing oil or gas 

on the OCS in waters shallower than 

200 meters to file an application seeking 

ONRR’s permission to include certain 

gathering costs in its transportation 

allowance. 

A. ONRR’s Rulemaking Authority 

ONRR’s royalty program is ‘‘a 

complex and highly technical regulatory 

program, in which the identification 

and classification of relevant criteria 

necessarily require significant expertise 

and entail the exercise of judgment 

grounded in policy concerns.’’ Amoco 

Prod. Co. v. Watson, 410 F.3d 722, 729 

(D.C. Cir. 2005) (internal quotations and 

citation omitted). FOGRMA grants the 

Secretary authority to ‘‘prescribe such 

rules and regulations as he deems 

reasonably necessary to carry out this 

chapter.’’ See 30 U.S.C. 1751(a); see 

also, e.g., 30 U.S.C. 1719. Re-evaluating 

the best means of balancing these 

statutory priorities within the bounds of 

the specific commands of the statute, as 

called for in the Executive and 

Secretarial Orders, is well within the 

scope of authority that Congress granted 

to the Secretary under FOGRMA and 

which was delegated by the Secretary to 

ONRR. 

B. Rulemaking Objectives 

The E.O.s explained below do not 

prescribe an outcome, rather, they note 

policy positions that are well within the 

specific authorities outlined in the 

relevant statutes, namely the MLA and 

the OCSLA. Specifically, 43 U.S.C. 

1332(3) states that: ‘‘It is hereby 

declared to be the policy of the United 

States that . . . the [OCS] 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. . . .’’ Moreover, the 

MLA, at 30 U.S.C. 201, states that ‘‘[t]he 

Secretary of the Interior is authorized to 

divide any lands subject to this chapter 

which have been classified for coal 

leasing into leasing tracts of such size as 

he finds appropriate and in the public 

interest and which will permit the 

mining of all coal which can be 

economically extracted in such tract and 

thereafter he shall, in his discretion, 

upon the request of any qualified 

applicant or on his own motion, from 

time to time, offer such lands for leasing 

and shall award leases thereon by 

competitive bidding.’’ With respect to 

oil and gas, the MLA, at 30 U.S.C. 226, 

states that ‘‘[a]ll lands subject to 

disposition under this chapter which 

are known or believed to contain oil or 

gas deposits may be leased by the 

Secretary’’ and provides that ‘‘[l]ease 

sales shall be held for each State where 

eligible lands are available at least 

quarterly and more frequently if the 

Secretary of the Interior determines 

such sales are necessary.’’ 

While neither of these statutes define 

or employ the term ‘‘fair return,’’ both 

the OCSLA and the MLA make use of 

the term ‘‘fair market value.’’ OCSLA, at 

43 U.S.C. 1331(o), defines ‘‘fair market 

value’’ as ‘‘the value of any mineral (1) 

computed at a unit price equivalent to 

the average unit price at which such 

mineral was sold pursuant to a lease 

during the period for which any royalty 

or net profit share is accrued or reserved 

to the United States pursuant to such 

lease, or (2) if there were no such sales, 

or if the Secretary finds that there were 

an insufficient number of such sales to 

equitably determine such value, 

computed at the average unit price at 

which such mineral was sold pursuant 

to other leases in the same region of the 

[OCS] during such period, or (3) if there 

were no sales of such mineral from such 

region during such period, or if the 

Secretary finds that there are an 

insufficient number of such sales to 

equitably determine such value, at an 

appropriate price determined by the 

Secretary[.]’’ FOGRMA built upon the 

royalty provisions of the MLA and the 

OCSLA by stating that the Secretary 

shall: ‘‘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.’’ 30 U.S.C. 1711(a). 

Both of the statutes provide for 

minimum royalty rates when leasing 

areas for energy and mineral 

development and offer some direction 

on royalty collection. The mineral 

leasing authorities granted to the 

Secretary by Congress provide broad 

authorities to ‘‘prescribe necessary and 

proper rules and regulations and to do 

any and all things necessary to carry out 

and accomplish the purposes of [the 

leasing statutes]’’ including the 

collection of all revenues associated 

with such activities (bonus bids, 

royalties, rentals and other fees). See 25 

U.S.C. 396, 396d (tribal lands); 30 U.S.C. 

189 (public lands); 30 U.S.C. 1751 

(FOGRMA); 43 U.S.C. 1334(a) (OCS 

lands). 

In addition to these policy goals, 

ONRR’s objectives include 

implementing court decisions and 

analyses, making changes that reduce 

regulatory burdens while maintaining 

royalty value and ONRR’s ability to 

provide oversight, and making 

regulations more simple, clear, and 

workable. Further, ONRR explains 

additional reasons to adopt or not adopt 

the specific proposed amendments in 

the amendment discussion sections that 

follow. 

The 2020 Proposed Rule, at 85 FR 

62054 and 62056–62057, explained that 

ONRR’s objective for this rulemaking 

included furtherance of the policy goals 

described in: 

1. E.O. 13783, ‘‘Promoting Energy 

Independence and Economic Growth.’’ 

In E.O. 13783, the President 

emphasized that ‘‘[i]t is in the national 

interest to promote clean and safe 

development of our Nation’s vast energy 

resources, while at the same time 

avoiding regulatory burdens that 

unnecessarily encumber energy 

production, constrain economic growth, 

and prevent job creation.’’ The President 

further directed executive departments 

and agencies to immediately review 

existing regulations that potentially 

burden the development or use of 

domestically produced energy resources 

and appropriately suspend, revise, or 

rescind those that unduly burden the 

development of domestic energy 

resources beyond the degree necessary 

to protect the public interest or 

otherwise comply with the law. 

Pursuant to E.O. 13783, agency heads 

are required to review all existing 

regulations that potentially burden the 

development or use of domestically 

produced energy resources, ‘‘with 

particular attention to oil, natural gas, 

coal, and nuclear energy resources.’’ 

E.O. 13783 further explained that 

‘‘burden’’ means to unnecessarily 

obstruct, delay, curtail, or otherwise 

impose significant costs on the siting, 

permitting, production, utilization, 

transmission, or delivery of energy 

resources. 

2. E.O. 13795, ‘‘Implementing an 

America-First Offshore Energy 

Strategy.’’ 

Through E.O. 13795, the President 

stated his policy goal of emphasizing 

‘‘the energy needs of American families 

and businesses first’’ and to ‘‘continue 

implementing a plan that ensures 

energy security and economic vitality 

for decades to come.’’ E.O. 13795 stated 

that ‘‘[i]ncreased domestic energy 

production on Federal lands and waters 

strengthens the Nation’s security and 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4615 

reduces reliance on imported energy’’ 

and ‘‘help[s] reinvigorate American 

manufacturing and job growth.’’ 

Accordingly, E.O. 13795 stated that ‘‘[i]t 

shall be the policy of the United States 

to encourage energy exploration and 

production, including on the [OCS], in 

order to maintain the Nation’s position 

as a global energy leader and foster 

energy security and resilience for the 

benefit of the American people. . . .’’ 

3. E.O. 13892, ‘‘Promoting the Rule of 

Law Through Transparency and 

Fairness in Civil Administrative 

Enforcement and Adjudication.’’ 

Through E.O. 13892, the President 

stated his policy goal of emphasizing 

that ‘‘[a]gencies shall act transparently 

and fairly with respect to all affected 

parties, as outlined in this order, when 

engaged in civil administrative 

enforcement or adjudication.’’ E.O. 

13892 stated that ‘‘the Federal 

Government should, where feasible, 

foster greater private-sector cooperation 

in enforcement, promote information 

sharing with the private sector, and 

establish predictable outcomes for 

private conduct. . . .’’ With emphasis 

on fairness and transparency, E.O. 

13892 also reinforced that ‘‘regulated 

parties must know in advance the rules 

by which the Federal Government will 

judge their actions,’’ and required that 

agencies provide ‘‘prior public notice’’ 

of any legal standards the agency will be 

applying. 

4. S.O.s 3306, 3350, and 3360. 

Three Secretarial Orders are also 

relevant to this rulemaking. S.O. 3306, 

Organizational Changes Under the 

Assistant Secretary—Policy, 

Management and Budget, signed on 

September 30, 2010, created ONRR and 

reorganized this office under the 

Assistant Secretary for Policy, 

Management and Budget to: ‘‘discharge 

the duties of the Secretary for 

management of revenues from Federal 

and Indian onshore and offshore 

mineral and energy resource leases . . . 

to assure full and timely collection, 

distribution, and disbursement of 

bonuses, rentals, royalties, and other 

revenues and coordination of related 

Departmental policy.’’ 

Through S.O. 3350, America-First 

Offshore Energy Strategy, the Secretary 

of the Interior (‘‘Secretary’’) took 

specific steps to implement E.O. 13795. 

Significant to the proposed rule, the 

Secretary specifically stated that S.O. 

3350 is designed to implement the 

President’s directives as set forth in E.O. 

13795 to ‘‘ensure that responsible OCS 

exploration and development is 

promoted and not unnecessarily 

delayed or inhibited.’’ The Order 

directed BOEM and BSEE to take 

specific actions, but also more generally 

expressed a desire for active 

coordination of energy policy in order to 

enhance opportunities for energy 

exploration, leasing, and development 

on the OCS. S.O. 3360 is likewise 

directed at continuing to implement 

E.O. 13783 and the directive to the 

Department to review existing 

regulations that ‘‘potentially burden the 

development or utilization of 

domestically produced energy 

resources.’’ 

These statutes, Executive Orders and 

Secretarial Orders make clear that it is 

in the national interest to promote 

domestic energy development for a 

variety of reasons, including stimulating 

the economy, job creation, and national 

security. They also 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. Through this rulemaking, 

ONRR furthers these policy objectives 

by several means, including providing 

mechanisms that simplify reporting and 

compliance, and promoting domestic 

energy production. 

C. Executive Discretion is a Permissible 

Initiative for Rulemaking 

As described in greater detail in the 

discussion of each amendment that 

follows, this rule is, in part, founded 

upon new factual findings that, in some 

instances, contradict those upon which 

the 2016 Valuation Rule was based. In 

some instances, the operative facts have 

changed since 2016. In other instances, 

ONRR has reconsidered the weighing of 

different policy priorities and values as 

they apply to the relevant facts. See 

generally F.C.C. v. Fox Television 

Stations, Inc., 556 U.S. 502, 514 (2009); 

Nat’l Ass’n of Home Builders v. EPA, 

682 F.3d 1032, 1038, 1043 (D.C. Cir. 

2012); Dana Corp. v. ICC, 703 F.2d 

1297, 1305 (D.C. Cir. 1983). With 

respect to the latter category and as 

explained further herein, ONRR is 

implementing this rule, in part, because 

policy directives issued after July 1, 

2016, give different weight to the factual 

findings, and also set other policy-based 

priorities. Agency action representing a 

policy change ‘‘is not subject to a more 

searching review.’’ F.C.C. v. Fox 

Television Stations, Inc., 556 U.S. 502, 

514 (2009). 

Indeed, ‘‘regulatory agencies do not 

establish rules of conduct to last 

forever.’’ Am. Trucking Assoc., Inc. v. 

Atchison, T. & S.F.R. Co., 387 U.S. 397, 

416 (1967). An agency must be given 

ample latitude to ‘‘adapt their rules and 

policies to the demands of changing 

circumstances.’’ Permian Basin Area 

Rate Cases, 390 U.S. 747, 784 (1968). A 

revised rulemaking based on ‘‘a 

reevaluation of which policy would be 

better in light of the facts’’ is ‘‘well 

within an agency’s discretion.’’ Nat’l 

Ass’n of Home Builders v. EPA, 682 

F.3d 1032, 1038 (D.C. Cir. 2012) (citing 

F.C.C. v. Fox Television Stations, Inc., 

556 U.S. 502, 514–15 (2009)). Further, 

‘‘[a] change in administration brought 

about by the people casting their votes 

is a perfectly reasonable basis for an 

executive agency’s reappraisal of the 

costs and benefits of its programs and 

regulations.’’ Id. at 1043 (quoting Motor 

Vehicle Mfrs. Ass’n of the U.S., Inc. v. 

State Farm Mut. Auto. Ins. Co., 463 U.S. 

29, 59 (1983) (Rehnquist, J., concurring 

in part and dissenting in part)). An 

‘‘agency is entitled to have second 

thoughts, and to sustain action which it 

considers in the public interest upon 

whatever basis more mature reflection 

suggests.’’ Dana Corp. v. ICC, 703 F.2d 

1297, 1305 (D.C. Cir. 1983). An agency 

is entitled to give more weight to 

socioeconomic concerns than it may 

have under a different administration. 

Am. Trucking Associations v. Atchison, 

T. & S.F. Ry. Co., 387 U.S. 397, 416, 87 

S. Ct. 1608, 1618 (1967); see also, Fox, 

556 U.S. at 515–516, 129 S. Ct. at 1811. 

D. ONRR’s Relevant Prior Rulemakings 

and Associated Litigation 

1. Federal Oil and Gas, and Federal and 

Indian Coal 

i. The 2016 Valuation Rule and Industry 

Lawsuit 

On July 1, 2016, ONRR published the 

2016 Valuation Rule, which extensively 

updated the royalty valuation 

framework for Federal oil and gas and 

Federal and Indian coal. The effective 

date of the 2016 Valuation Rule was 

January 1, 2017. 

ii. The 2017 Postponement Notice 

On February 27, 2017, ONRR 

published the 2017 Postponement 

Notice, which attempted to postpone 

the effective date of the 2016 Valuation 

Rule. In response, the States of 

California and New Mexico filed suit in 

the United States District Court for the 

Northern District of California to 

challenge the 2017 Postponement 

Notice. See Becerra v. U.S. Dep’t. of the 

Interior, 276 F. Supp. 3d 953 (N.D. Cal. 

2017). 

iii. The 2017 Repeal Rule 

On August 7, 2017, ONRR published 

the 2017 Repeal Rule, which attempted 

to repeal the 2016 Valuation Rule in its 

entirety. On October 7, 2017, the States 

4616 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

of California and New Mexico filed a 

second suit in the United States District 

Court for the Northern District of 

California to challenge the 2017 Repeal 

Rule. On March 29, 2019, the District 

Court issued a decision that vacated the 

2017 Repeal Rule. Becerra v. U.S. Dep’t 

of the Interior, 381 F. Supp. 3d 1153 

(N.D. Cal. 2019). The decision reinstated 

the 2016 Valuation Rule, including the 

rule’s original effective date of January 

1, 2017. Id. at 1179. See also Becerra v. 

U.S. Dep’t of the Interior, Case No. C 17– 

5948 SBA, Order at page 3 (July 30, 

2020). 

ONRR included mention of the 

District Court’s findings in the 2020 

Proposed Rule (85 FR 62054, 62055– 

62056), and discusses those findings 

further below. 

Several months after the 2016 

Valuation Rule was reinstated, industry 

filed litigation in the United States 

District Court for the District of 

Wyoming, challenging the 2016 

Valuation Rule. See Cloud Peak Energy, 

Inc. v. U.S. Dep’t of the Interior, Case 

No. 19–CV–120–SWS (D. Wyo.). On 

October 8, 2019, the Wyoming District 

Court entered an Order granting in part 

and denying in part industry’s request 

for a preliminary injunction with 

respect to the 2016 Valuation Rule. The 

Order stayed all portions of the 2016 

Valuation Rule applicable to Federal 

and Indian coal. Cloud Peak, 415 F. 

Supp. 3d 1034, 1053 (D. Wyo. 2019). 

Thus, Federal and Indian coal lessees 

continue to report and pay royalties 

under the 1989 Federal and Indian Coal 

Valuation Regulations (54 FR 1492) 

while the Cloud Peak case is being 

litigated. 

2. Civil Penalties 

ONRR previously amended portions 

of its civil penalty regulations, at 30 

CFR part 1241, on August 1, 2016 (81 

FR 50306) in order to clarify the civil 

penalty regulations and increase 

transparency about how ONRR assesses 

civil penalties. API challenged the 2016 

Civil Penalty Rule in the United States 

District Court for the District of 

Wyoming. The District Court upheld the 

2016 Civil Penalty Rule, except as to 

one issue. See API v. U.S. Dep’t. of the 

Interior, 366 F. Supp. 3d 1292, 1309–10 

(D. Wyo. 2018). The exception was 30 

CFR 1241.11(b)(5), which provides that 

a petitioner may forfeit the benefit of a 

stay of the accrual of civil penalties if 

an ALJ determines that the petitioner’s 

defense to a previously issued civil 

penalty is frivolous. The District Court 

held that the provision was an abuse of 

discretion and facially not in 

accordance with the law. See API, 366 

F. Supp. 3d at 1310. 

API appealed to the United States 

Court of Appeals for the Tenth Circuit, 

which vacated the District Court’s 

decision, finding API lacked standing to 

pursue its facial challenge to the 2016 

Civil Penalty Rule. See API v. U.S. Dep’t 

of the Interior, 823 Fed. Appx. 583 (10th 

Cir. 2020). Upon remand, the District 

Court dismissed API’s claim for lack of 

jurisdiction. API, Case No. 17–cv–83– 

NDF, D. Wyo., Order dated Sept. 29, 

2020. 

E. Public Comment Overview 

1. Public Comment Period 

On August 7, 2020, the Department 

issued a press release to notify the 

public of the 2020 Proposed Rule and, 

on the same day, ONRR published the 

text of the 2020 Proposed Rule on its 

website for the public to view in 

advance of the 2020 Proposed Rule’s 

publication in the Federal Register. 

On October 1, 2020, ONRR published 

the 2020 Proposed Rule in the Federal 

Register. The 2020 Proposed Rule 

provided a 60-day comment period that 

closed on Monday, November 30, 2020. 

See 85 FR 62054. 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 a total of 

40,456 pages of comments, of which 

38,150 pages were a similar form 

comment. If the 38,150 pages of form 

comments are treated as a single 

comment, ONRR received 2,307 unique 

pages of comment materials. 

2. Specific Comments Requested by 

ONRR in the 2020 Proposed Rule 

In section F of the 2020 Proposed 

Rule, ONRR requested comments on 

specific topics (85 FR 62070–62071). 

This rule addresses those comments in 

the applicable amendment discussions 

herein. 

3. General Comments 

Public Comment: One commenter 

claimed that ONRR’s 2020 Proposed 

Rule is arbitrary and capricious. ONRR’s 

claim that the 2020 Proposed Rule will 

increase natural resource production is 

arbitrary and capricious because it is 

unsupported in the rulemaking record, 

the commenter said. The commenter 

stated that ONRR failed to provide any 

analysis or record to demonstrate that 

production increases will occur. 

According to the commenter, ONRR also 

contradicted itself by stating that the 

2020 Proposed Rule would not 

materially alter natural resource 

exploration, production, or 

transportation. 

ONRR Response: In the 2020 

Proposed Rule, ONRR provided its 

rationale for proposing the amendments. 

ONRR acknowledged instances where it 

believed additional information could 

improve its analyses. Consequently, 

ONRR posed a list of specific, targeted 

questions in the 2020 Proposed Rule to 

solicit additional information from 

public commenters for ONRR’s 

consideration. ONRR reviewed and 

considered all substantive comments it 

received, and, where appropriate, 

revised its analysis in this final rule 

based on the information provided by 

the public comments. 

The commenter is correct that the 

2020 Proposed Rule does not quantify 

an increase in domestic energy 

production—neither does this final rule. 

This rule is not premised on increasing 

the production of oil, gas, or coal by 

some measured amount. Instead, this 

rule, in part, is meant to incentivize 

both the conservation of natural 

resources (by extending the life of 

current operations) and domestic energy 

production over foreign energy 

production. The Department typically 

conducts economic analyses regarding 

changes in leasing fiscal terms or 

increased/decreased regulatory burdens. 

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. The 

Department’s models are designed to 

analyze newly available geologic 

information, changes in prices and fiscal 

changes to future lease terms. The 

model results provide estimates of the 

downstream impact on public lands 

leasing and production, and it would 

not be appropriate for ONRR to use 

these results to estimate to estimate any 

production changes due to the 

provisions of this rulemaking because 

these provisions impact leases currently 

in production. 

ONRR disagrees with the commenter 

that ONRR contradicted itself in the 

2020 Proposed Rule. ONRR believes the 

commenter misunderstood the separate 

activities of (1) ONRR’s explanation of 

the rule’s objectives and estimating its 

royalty and administrative impacts, and 

(2) ONRR’s application of certain 

criteria to determine whether it must 

make an additional statement or 

analysis to comply with NEPA 

requirements. 

Public Comment: A commenter also 

claimed that if production does increase 

as a result of the rule, then ONRR’s 

failure to address the environmental 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4617 

costs associated with such production 

increase is arbitrary and capricious. 

According to the commenter, increased 

production will result in negative 

environmental externalities, which 

ONRR must consider under Federal 

land management statutes and the APA. 

The commenter specifically cites to 

FLPMA, MLA, and OCSLA as 

authorities that require ONRR to 

consider environmental impacts when 

promulgating regulations involving 

energy production on Federal lands. As 

the commenter pointed out, the APA 

also requires agencies to ‘‘examine the 

relevant data and articulate a 

satisfactory explanation for its action.’’ 

Motor Vehicle Assn. v. State Farm Mut. 

Auto. Ins. Co., 463 U.S. 29, 43 (1983). 

Another commenter raised additional 

environmental concerns with ONRR’s 

2020 Proposed Rule. This commenter 

requested that ONRR consider 

environmental impacts alongside the 

effects on the oil and gas industry as a 

result of this rule. The commenter stated 

that ONRR is supposed to consider and 

consult with more stakeholders when 

engaging in the rulemaking process. The 

commenter explained that the list of 

stakeholders should include 

government agencies, 

environmentalists, private companies, 

actors in the fossil fuel industries that 

operate on Federal and Indian land, and 

people who consume oil and gas. The 

commenter stated that this type of 

stakeholder engagement would make 

ONRR’s rulemakings more 

comprehensive. 

ONRR Response: The environmental 

impacts of energy and mineral 

development are analyzed at other 

stages in the development process, 

including the land use planning stage, 

the lease sale stage, and the projectspecific development stage when more 

specific details of the potential 

environmental impacts and use on the 

leased area by a proposed project would 

be readily available. Further 

environmental review of these projects 

in the context of this rulemaking is thus 

duplicative and unnecessary. Generally, 

an agency’s promulgation of regulations 

must be based within the agency’s 

specific legal mandate and cannot 

extend beyond the intended reach of the 

agency’s statutory and delegated 

authority. Similarly, an agency’s 

primary rulemaking objective and goal 

must align with the stated purpose of 

the Acts governing the agency’s 

rulemaking. Congress gave the Secretary 

authority to promulgate regulations 

concerning ‘‘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.’’ 30 U.S.C. 1701(a) 

(emphasis added). See also 30 U.S.C. 

1701(b)(2) (‘‘It is the purpose of this 

chapter . . . to clarify, reaffirm, expand 

and define the authorities and 

responsibilities of the Secretary of the 

Interior to implement and maintain a 

royalty management system for oil and 

gas leases on Federal lands, Indian 

lands, and the [OCS]. . . .’’). A similar 

broad grant of authority to promulgate 

regulations is provided to the Secretary 

under the MLA at 30 U.S.C. 189 and 

OCSLA at 43 U.S.C. 1334. ONRR is 

amending its royalty valuation and civil 

penalty regulations, and has considered 

all relevant information within this 

context in accordance with the 

Department’s statutory mandate, as set 

forth under the MLA, OCSLA, and 

FOGRMA. 

Regarding the commenter’s reference 

to FLPMA, that Act governs leasing 

activities primarily carried out by other 

Department bureaus and offices. For 

energy leasing, exploration, and 

development activities to be conducted 

on Federal or Indian land, these 

Department bureaus and offices evaluate 

the environmental impacts by 

conducting NEPA analyses. Thus, 

environmental impacts associated with 

newly proposed projects or operations 

are evaluated during the leasing and 

permitting stages by the appropriate 

bureau or office. If a project or operation 

is significantly modified or expanded 

beyond the initial approvals and 

corresponding NEPA analysis, the 

responsible agency will reevaluate any 

additional environmental impacts and 

conduct the appropriate NEPA analysis. 

This rule does not lessen the obligation 

borne by other Department bureaus and 

offices to perform NEPA analyses at all 

appropriate stages in the leasing and 

lease administration process. 

In response to the commenter’s 

statement pertaining to stakeholder 

involvement, ONRR solicited input from 

all interested persons and stakeholders, 

including environmental organizations, 

as part of this rulemaking. Through the 

publication of the 2020 Proposed Rule 

in the Federal Register on October 1, 

2020, ONRR provided ‘‘interested 

persons an opportunity to participate in 

the rule making through submission of 

written data, views, or arguments’’ as 

required under the APA. 5 U.S.C. 

553(c). The 2020 Proposed Rule 

provided all interested persons with a 

60-day public comment period to 

submit information for ONRR’s 

consideration. 

Public Comment: Another public 

commenter stated that ONRR likely will 

be required to once again change its 

regulations as a result of a change in 

Administrations. The commenter cites 

to statements suggesting that a future 

Administration would modify or reverse 

the E.O.s currently relied upon by 

ONRR for this rulemaking. 

ONRR Response: The commenter 

cited general environmental policy 

objectives of a new Administration, 

which are not in place at the time of this 

rulemaking, and failed to identify any 

specific conflicts between any such 

policies and the proposed amendments. 

ONRR bases its policies on statutory 

dictates and its current priorities, rather 

than speculation about what a future 

administration might do. ONRR, in part, 

based the 2020 Proposed Rule on E.O.s 

and S.O.s in effect at the time of its 

publication, and on the policies 

underlying those directives. Those same 

E.O.s and S.O.s are still in effect for 

ONRR to consider in this final rule. 

Moreover, the underlying policies are 

valid, and deserve weight, aside from 

the particulars of the E.O.s and S.O.s. 

Please refer to Sec. I.A. for a general 

overview of this rule’s objectives and 

the amendment discussion sections for 

additional explanations specific to each 

amendment. 

II. Amendment Discussion—Part 1206 

Product Valuation 

A. Index-Based Valuation Method To 

Value Federal Gas 

General Comments 

Public Comment: ONRR requested 

and received comments on the indexbased valuation method amendments. 

Specifically, ONRR asked for 

alternatives to requiring a lessee to 

evaluate all pricing points where a 

lessee’s gas may flow. Several 

commenters from or representing the 

regulated community suggested that 

ONRR use the pricing point where a 

lessee’s gas actually flows, rather than 

evaluate all possible pricing points. 

These commenters suggested this would 

lessen the burden on a lessee to research 

all possible index points and create 

greater certainty that a lessee did not 

overlook any possible index points. 

ONRR Response: As ONRR monitors 

reporting and payments under the 

index-based valuation methods adopted 

in the 2016 Valuation Rule and in this 

final rule, and systematically examines 

actual transaction data, ONRR will 

continue to look for alternatives to 

evaluating all accessible index pricing 

points, including alternatives that 

require tracing production to determine 

the actual index pricing point. However, 

4618 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

at this time, ONRR does not have the 

data to support the suggested change. 

Accordingly, ONRR is not making the 

change in this final rule. 

Public Comment: ONRR received 

several comments requesting ONRR 

update the transportation and 

fractionation (‘‘T&F’’), and processing 

adjustments, published at https://

www.ONRR.gov, for the NGL indexbased valuation method. These 

commenters stated that the values are 

outdated and do not reflect current 

markets or FERC published rates. The 

commenters also expressed concerns 

that the NGL index-based method does 

not allow for deductions for pre-plant 

transportation and the transportation 

deductions for unprocessed and residue 

gas should apply to NGLs. 

ONRR Response: ONRR did not 

propose amendments to the adjustments 

to the NGL index-based valuation 

method. While these comments are 

beyond the scope of this rulemaking, 

ONRR regulations state the T&F 

adjustments will be periodically 

updated (§ 1206.142(d)(2)(ii)), as 

outlined in the preamble to the 2016 

Valuation Rule. ONRR will continue to 

periodically review and update these 

adjustments, as necessary. However, at 

this time, ONRR is not amending the 

proposed unprocessed and residue gas 

transportation deductions to apply to 

NGLs. 

Public Comments: A commenter 

requested that ONRR develop a 

valuation method for areas that do not 

have access to index-pricing points, 

specifically for gas produced in Alaska. 

ONRR Response: Currently, ONRR is 

not incorporating a specific valuation 

method for areas that do not have access 

to index-pricing points. A lessee cannot 

elect to use an index-based method in 

these areas, and the lessee must 

continue using the first arm’s-length 

sale to value Federal gas. 

Public Comments: Some commenters 

requested that ONRR modify the indexbased valuation method, and some 

commenters specifically submitted 

comments for consideration during 

future rulemakings. These comments 

include: (1) ONRR should consider 

extending the election period to value 

Federal gas, under the index-based 

valuation method, from two years to a 

minimum of three years; (2) ONRR 

should require or mandate a lessee 

value Federal gas using the index-based 

valuation method; (3) ONRR should 

develop an index-based method to value 

gas at the wellhead; and (4) ONRR 

should allow a lessee to propose an 

alternative valuation method under 

certain situations that force a lessee to 

value gas under the index-based 

valuation method (e.g. gas sold under a 

keepwhole contract with no arm’slength gross proceeds sales from the 

same lease, flared gas). 

ONRR Response: In this final rule, 

ONRR will not adopt these suggested 

changes as these changes are outside of 

the scope of this rulemaking. 

Additionally, ONRR will not act to 

implement suggestions for an extended 

election period or mandatory use of 

index-based valuation methods. At this 

time, both ONRR and lessees are best 

served in implementation of new 

valuation methods by shorter 

commitments and optional use. 

1. Expansion of the Federal Gas Index 

Pricing Valuation Method Under a NonArm’s-Length Contract to Federal Gas 

Sold Under Arm’s-Length Contracts 

(§§ 1206.141(c) and 1206.142(d)) 

The 2016 Valuation Rule amended 30 

CFR part 1206 to allow a lessee two 

valuation methods to value its nonarm’s-length Federal gas sales. The first 

valuation method was to value Federal 

gas based on the first arm’s-length sale 

occurring after a non-arm’s-length sale 

or transfer of the gas to the lessee’s 

affiliate. The second valuation method 

was to elect to use an index-based 

valuation method. This index-based 

valuation method aligns with a 

provision from the 2000 Federal Oil 

Valuation Rule, ‘‘Establishing Oil Value 

for Royalty Due on Federal Leases’’ (65 

FR 14022, March 15, 2000), that allowed 

a lessee to elect to value Federal oil 

using index prices when it sells or 

transfers oil to an affiliate that, in turn, 

then sells the oil at arm’s-length. The 

2020 Proposed Rule would extend 

optional use of the index-based 

valuation method to arm’s-length sales 

of Federal gas. 

Comments on the Proposed Amendment 

Public Comment: Several commenters 

supported the expansion of the indexbased valuation method for Federal gas 

sold under an arm’s-length contract. 

Commenters agreed that having the 

option to elect an index-based method 

lessens the burden and provides early 

certainty for all payors. Commenters 

noted that a lessee is more likely to use 

the index-based method if it is 

applicable to all its Federal gas sales 

and that this valuation method will 

truly lessen the administrative burden 

by allowing a lessee to use one approach 

to value gas sold under multiple 

contracts. The commenters reiterated 

that extending the index-based method 

to all Federal gas sales will further 

eliminate the burden to unbundle and 

comply with marketable condition 

regulations. One commenter stated that 

the index-based valuation method 

should be mandatory instead of being a 

method that gas producers can select for 

non-arm’s-length sales for two-year 

periods. 

ONRR Response: Many commenters 

were in favor of the proposed changes 

published in the 2020 Proposed Rule. In 

this final rulemaking, ONRR is adopting 

the amendment as proposed in the 2020 

Proposed Rule to allow a lessee with an 

arm’s-length sale to elect to value its gas 

production under the index-based 

valuation method. Regarding the 

commenter’s statement that the indexbased valuation method should be 

mandatory, ONRR is not choosing to 

make it mandatory at this time for all 

sales, but will collect data based on 

optional use to inform possible future 

rulemaking. 

Public Comment: Some commenters 

opposed the extension of the indexbased method, and stated that ONRR 

has not provided enough data to modify 

the position it took in the 2016 

Valuation Rule, including that arm’slength sales are the best indicator of 

value. 

ONRR Response: ONRR maintains 

that arm’s-length sales are generally the 

best indicator of value. Index prices are 

derived from arm’s-length sales reported 

to index pricing publications. The 

index-based valuation method 

simplifies the current valuation method 

and, in addition, provides transparency 

and early certainty to a lessee. The 

index-based method provides early 

certainty because the elements of the 

index-based formula are all known at 

the time royalty reports are first due, 

which is the end of the month following 

the month of production, and not 

subject to subsequent adjustment. In 

contrast, when royalty value is based on 

actual sales prices, transportation costs, 

and, for gas, processing costs, 

adjustments to those prices and costs in 

subsequent months change royalty 

values and require re-reporting. Also, 

the sales prices, transportation costs, 

and processing costs may be disputed 

through an ONRR audit or other ONRR 

compliance activity. 

The index-based method, in contrast, 

uses transparent, certain prices 

published prior to the royalty due date, 

and a fixed percentage of those 

published prices as an ‘‘allowance’’ to 

cover the costs of transportation. ONRR 

recognizes that ONRR and all Federal 

lessees can benefit from the certainty 

and transparency that the index-based 

valuation method provides. 

Additionally, complex valuation 

situations are not limited to non-arm’slength dispositions. In arm’s-length 

transactions, many third-party pipeline 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4619 

and service providers now charge 

lessees ‘‘bundled’’ fees that include 

costs to place production into 

marketable condition. Both ONRR and 

lessees with arm’s-length sales, 

transportation, and/or processing 

contracts have found allocating the costs 

between allowed and disallowed costs 

is necessary for valuation based on gross 

proceeds, but administratively costly 

and time consuming. These are not 

required with index-based royalty 

reporting and payment cost allocations. 

Public Comment: A commenter 

suggested that ONRR require a lessee to 

pay on whichever value is higher 

between gross proceeds and the indexbased valuation method to eliminate the 

temptation to manipulate index prices. 

ONRR Response: Requiring a lessee 

each and every month to value gas by 

both gross proceeds and the index-based 

valuation method forces a lessee to use 

two valuation methods and increases 

the burden of either method 

individually. This would not achieve 

the mutual goal of a simple or certain 

valuation method for ONRR or a lessee. 

While there have been instances of 

traders attempting to manipulate index 

prices in recent years, these have been 

infrequent and involve limited volumes. 

ONRR believes that index prices are an 

acceptable method to value royalties for 

the following reasons: (1) The FERC 

must approve pricing publications used 

as the source of index prices for Federal 

gas royalty reporting and payments; (2) 

index publishers have protections to 

prevent and discourage price 

manipulation; (3) ONRR maintains 

discretion to disallow the use of an 

index point; and (4) index prices 

already influence royalty valuation, as 

they are used as the sales price or as part 

of a sales price formula in many arm’slength sales contracts. Further, as 

discussed in the preamble to the 2020 

Proposed Rule, even when a lessee 

elects to use the index-based valuation 

method to report and pay royalties, 

ONRR retains the right and ability to 

from time to time examine, review, 

analyze, and audit the lessee’s actual 

transaction data—including sales, 

transportation, processing, and contracts 

for services required to place production 

in marketable condition. By periodically 

examining actual transaction data, 

ONRR will be well positioned to 

ascertain the continuing validity of both 

the index prices and ONRR’s continued 

use of an index-based valuation method. 

If ONRR finds an index price unreliable, 

ONRR will have the opportunity to stop 

using that index price. And if ONRR 

finds that its index-based valuation 

method needs adjustment, ONRR will 

have the opportunity to change the 

method through future rulemaking. 

ONRR appreciates the comments 

supporting, seeking modification to, and 

opposing the proposed amendments to 

§§ 1206.141(c) and 1206.142(d). After 

careful consideration, and for the 

reasons explained in the 2020 Proposed 

Rule and this final rule, ONRR is 

adopting the proposed changes to 

§§ 1206.141(c) and 1206.142(d) as part 

of this final rule. 

2. Published Average Bidweek Price 

(§§ 1206.141(c)(1)(i) and (ii); and 

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

For unprocessed gas and residue gas, 

the 2016 Valuation Rule’s index-based 

valuation method requires use of the 

highest monthly bidweek price for the 

index pricing points that a lessee’s gas 

can flow to, whether or not there is a 

constraint for that production month, 

less a specified deduction. The 2020 

Proposed Rule proposed to amend the 

2016 Valuation Rule to use the highest 

of the monthly bidweek average prices 

for the index pricing points that a 

lessee’s gas can flow to, whether or not 

there is a constraint for that production 

month, instead of the highest of the 

monthly bidweek high prices. See 85 FR 

62058. 

When ONRR uses the term in the 

2020 Proposed Rule, ‘‘published average 

bidweek price,’’ or ‘‘bidweek average’’ 

for short, it refers to what many 

publications call the ‘‘index’’ or 

‘‘average’’ price. For example, the Platts 

Inside FERC’s Gas Market Report labels 

this price as the ‘‘index,’’ while the 

Natural Gas Intelligence’s (‘‘NGI’’) 

Bidweek Survey labels this price as the 

‘‘average.’’ 

An index-based valuation method 

using bidweek average prices still 

results in a royalty value comparable to 

the fair market value a lessee could 

receive under the typical arm’s-length 

contract, and ONRR anticipates this 

method will be used by more lessees, 

because it better reflects the average 

price the average lessee receives, rather 

than the high price only one lessee 

receives. Greater use of the index-based 

valuation method will ease both the 

lessee’s administrative burden and 

ONRR’s. 

Lastly, using the bidweek average 

price for unprocessed gas and residue 

gas aligns with the use of average prices 

used in the NGL index-based valuation 

method (§ 1206.142(d)(2)(i)) and the 

Federal oil regulations (§ 1206.102). 

Using average prices for all the indexbased valuation methods provides 

consistency and transparency, increases 

accuracy, and avoids confusion and 

potential errors. 

Comments on the Proposed Amendment 

Public Comment: ONRR received 

several comments that support using the 

bidweek average price rather than the 

bidweek high price in the index-based 

valuation method. Commenters stated 

that the bidweek average price more 

closely reflects the price a lessee could 

obtain and is closer to the value of gross 

proceeds. Commenters stated the 

bidweek average price results in a more 

reasonable value for royalty purposes 

and that a lessee is more likely to elect 

the index-based valuation method. 

Another commenter stated that bidweek 

average prices are more certain and 

reliable because they represent many 

transactions at the same pricing point. 

On the contrary, the highest bidweek 

price may only represent a single 

transaction, which may or may not 

reflect normal market dynamics. 

ONRR Response: The bidweek high 

price is the highest price reported for 

any transaction that qualifies for 

reporting, which may or may not reflect 

usual market dynamics. The bidweek 

average price is just that—an average 

price from many arm’s-length 

transactions at the same pricing point. 

For the reasons discussed above, ONRR 

is adopting the use of the bidweek 

average price in this final rule. 

Public Comment: A commenter 

supported using the bidweek average 

prices since a lessee could more easily 

access the bidweek average price based 

on its own contract pricing but would 

have to pay a third-party publication to 

access the high bidweek prices. 

ONRR Response: If a lessee chooses to 

use contract prices that reference an 

index price, rather than a price found in 

a subscription or publication, it is up to 

the lessee to verify that the contract 

price is accurate, and that it reflects all 

possible index pricing-points. ONRR 

will rely on ONRR’s subscriptions to 

verify pricing in any compliance 

activity. ONRR is not aware of any 

difference in subscription costs between 

publications identifying the bidweek 

average and the bidweek high prices. 

Public Comment: Several commenters 

stated that ONRR should require the 

highest of the bidweek high prices, 

because it better protects the interests of 

the taxpayers and States. Additionally, 

commenters opposed adopting any 

amendment that would decrease 

royalties paid to ONRR. 

ONRR Response: ONRR disagrees that 

using the bidweek high price better 

protects the lessor’s interest than using 

the bidweek average price. While the 

bidweek average price is lower than the 

bidweek high price, the bidweek 

average more closely reflects the gross 

4620 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

proceeds that a lessee would typically 

receive in an arm’s-length transaction, 

and therefore is more likely to actually 

be used by lessees. ONRR maintains that 

other protections are still in place, such 

as requiring the lessee to choose this 

option for a minimum of two years and 

requiring the lessee to use the highest 

bidweek average price to which the gas 

could flow when multiple pricing 

points are involved. 

Furthermore, in the context of the 

overall rulemaking, it is possible that 

the index-based valuation method (if 

actually used) may increase royalties 

paid under this method. As outlined in 

the Procedural Matters section, overall 

royalty values under the 2020 Valuation 

Rule’s index-based valuation method 

are around $0.04/MMBtu higher than 

the prices reported to ONRR for arm’slength sales, even with the use of 

average rather than high bidweek prices. 

ONRR appreciates the comments 

supporting, seeking the modification to, 

and opposing the proposed amendments 

to §§ 1206.141(c)(1)(i) and (ii) and 

1206.142(d)(1)(i) and (ii). After careful 

consideration, and for the reasons stated 

in the 2020 Proposed Rule and this final 

rule, this final rule adopts the proposed 

amendment in full. 

3. Transportation Deductions 

(§§ 1206.141(c)(1)(iv) and 

1206.142(d)(1)(iv)) 

The 2016 Valuation Rule amended 

ONRR’s regulations to allow a lessee 

that elects to use the index-based 

valuation method to include an 

adjustment for transportation based on 

the location of its lease (e.g., OCS, GOM, 

or all other areas). The rule further 

constrained the transportation 

adjustment to a specified range 

measured in cents per MMbtu. The 2016 

Valuation Rule adjustments and 

minimum-to-maximum ranges were as 

follows: 

Location 

Transportation 

adjustment 

(%) 

Minimum rate 

(cents per 

MMbtu) 

Maximum rate 

(cents per 

MMbtu) 

OCS, GOM .................................................................................................................................. 5 $0.10 $0.30 

All Other Areas ............................................................................................................................ 10 0.10 0.30 

ONRR based the transportation 

adjustment and minimum-to-maximum 

constraint on its analysis of 

transportation allowances reported to 

ONRR for production months in 

calendar years 2007 to 2010 (proposed 

2016 Valuation Rule, 80 FR 618, January 

6, 2015). 

In the 2020 Proposed Rule, ONRR 

performed the same analysis for 

production months in calendar years 

2014 through 2018. Based on this 

analysis of more recent time periods, 

ONRR proposed to revise the allowed 

transportation adjustments and 

minimum-to-maximum constraints as 

follows: 

Location 

Transportation 

adjustment 

(%) 

Minimum rate 

(cents per 

MMbtu) 

Maximum rate 

(cents per 

MMbtu) 

OCS, GOM .................................................................................................................................. 10 $0.10 $0.40 

All Other Areas ............................................................................................................................ 15 0.10 0.50 

The 2020 Proposed Rule explained 

that these values more closely reflect the 

actual costs a lessee will incur to 

transport gas to an index-pricing point. 

See 85 FR 62058. ONRR will continue 

to monitor reported transportation 

allowances to ensure that the 

adjustments under its regulations for the 

index-based valuation method continue 

to be representative of the actual costs 

that lessees report to ONRR. 

Comments on the Proposed Amendment 

Public Comment: ONRR received 

comments supporting the proposal to 

update the transportation adjustment 

values in order to more accurately 

reflect the current markets and rates 

charged for arm’s-length transportation. 

ONRR Response: ONRR agrees with 

these comments that the transportation 

adjustment amounts should more 

closely reflect the average cost a lessee 

incurs to transport gas to an index 

pricing point. ONRR will continue to 

monitor transportation allowances 

reported by lessees, including those 

who have not elected to report under 

the index price valuation method but 

under gross proceeds, and will 

periodically review, examine, analyze, 

or audit actual transportation 

transactions and the costs of placing gas 

into marketable condition to ensure that 

the adjustments under these regulations 

remains representative of the costs a 

lessee incurs on average. 

Public Comment: Commenters stated 

that ONRR should not update the 

transportation adjustments for the 

index-based valuation method. These 

commenters opposed any amendment 

that will result in lower royalties paid 

to the Federal Government and 

disbursed to State and local 

governments. 

ONRR Response: While ONRR 

understands these concerns, ONRR’s 

analysis of data supports modifying the 

adjustments to more closely reflect the 

average costs a lessee incurs to transport 

gas to an index pricing point. ONRR 

will continue to monitor transportation 

adjustments, and will periodically 

review, examine, analyze, or audit 

actual transportation contracts and the 

costs of placing gas into marketable 

condition to ensure that the adjustments 

remain reflective of the average cost 

lessees incur. 

Public Comment: An industry 

commenter stated that because the 

transportation adjustments were 

calculated using data from calendar 

years 2014 through 2018, they are 

already outdated. Most transportation 

contracts have moved to fixed-fee rates 

since that time and with lower 

commodity prices, transportation can 

exceed the updated adjustments. The 

commenter suggested ONRR find 

alternatives to a set percentage or 

evaluate transportation adjustments 

more frequently. 

ONRR Response: ONRR will monitor 

and review the transportation 

adjustments. If ONRR finds that the 

transportation adjustments cease to 

reflect typical costs, ONRR can take 

action to update the transportation 

adjustment to ensure that its indexbased valuation method captures a 

reasonable value for royalty purposes. 

Public Comment: A commenter 

expressed concern that ONRR failed to 

document and explain its calculations 

of the revised index-based 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4621 

transportation adjustments. The 

commenter expressed a need for greater 

transparency to ensure that ONRR is 

accountable to the public for its 

decisions. 

ONRR Response: ONRR identified the 

weighted per unit transportation rate 

and imputed the transportation 

percentage from the data reported on the 

form ONRR–2014 for the months in the 

noted calendar years for properties 

reporting a transportation allowance. 

Using this method, ONRR identified a 

maximum, minimum, and average range 

for both OCS and all other properties. 

ONRR used these values to establish the 

updated transportation deductions in 

the 2020 Proposed Rule. 

ONRR appreciates the comments 

supporting, seeking the modification to, 

and opposing the proposed amendments 

to §§ 1206.141(c)(1)(iv) and 

1206.142(d)(1)(iv). After careful 

consideration, and for the reasons set 

out in the 2020 Proposed Rule and this 

final rule, this final rule will adopt the 

proposed amendment in full. 

4. Zero Value (§§ 1206.141(f) and 

1206.142(g)) 

In the 2020 Proposed Rule, ONRR 

proposed to add language to the 

unprocessed (§ 1206.141(f)) and 

processed (§ 1206.142(g)) gas regulations 

clarifying ONRR’s long-standing policy 

that the value of any product cannot be 

reported as less than zero. Consistent 

with language included in lease 

documents, including a lessee’s duty to 

market gas at no cost to the Federal 

Government, lessees have never been 

permitted to report negative royalty 

values. Adding this to the regulatory 

language promotes consistent and clear 

regulations. 

When ONRR published the 2020 

Proposed Rule, its systems were unable 

to accept a reporting line with a $0.00 

royalty value. In instances where the 

royalty value would correctly be $0.00, 

ONRR instructed reporters to code the 

reporting line using Transaction Code 

20 and report a royalty value less 

allowances of $0.01. The 2020 Proposed 

Rule’s proposed regulatory text reflected 

this constraint by including language 

that, for example, prevented a lessee 

from reducing ‘‘the royalty value of any 

production to zero.’’ Emphasis added. 

ONRR now has the system capability 

to accept a report with a $0.00 royalty 

value, and no longer has a need to 

include a workaround for that constraint 

in this final rule. Thus, in the example 

above, this final rule will modify the 

proposed amendment to §§ 1206.141(f) 

and 1206.142(g) to state that ‘‘Under no 

circumstances may your gas be valued 

for royalty purposes at less than zero.’’ 

Emphasis added. 

Comments on the Proposed Amendment 

Public Comment: A commenter 

requested ONRR clarify this provision. 

The commenter stated that payors 

received guidance from ONRR stating, 

‘‘for those situations where your value 

for royalty purposes, plus any 

disallowed costs or additional 

consideration under your sales contract, 

is less than or equal to $0.00, ONRR’s 

regulations and your Federal lease 

require you to report and value any 

Federal gas production removed or sold 

from your lease, even if the value is zero 

or less than zero.’’ The guidance further 

instructed reporters to report those zero 

royalty values, where the proposed rule 

does not allow a zero-royalty value. The 

inconsistency in guidance and the 

proposed rule changes create confusion 

and uncertainty, the commenter said. 

ONRR Response: ONRR acknowledges 

that its guidance and the proposed 

amendment may be inconsistent. 

However, the purpose of the 

amendment is to resolve any confusion 

that may have arisen under ONRR’s 

prior regulations and guidance. If there 

is an inconsistency between the 

amendments adopted in this final rule 

and any prior guidance, this final rule 

will control. ONRR recognizes that, in 

the absence of the clarifying language in 

this final rule, a lessee might seek to 

report a royalty value of zero in 

instances where gross proceeds or index 

prices are at or below zero, after adding 

back any disallowed costs or additional 

considerations. However, this final rule 

clarifies that products cannot be valued, 

for royalty purposes, less than zero, but 

can be valued at zero. This regulatory 

change is consistent with language 

included in most lease documents, 

including a lessee’s duty to market gas 

at no cost to the Federal Government. 

Lessees have never had the ability to 

report negative royalty values. 

ONRR appreciates the comments 

supporting, seeking the modification to, 

and opposing the proposed amendments 

to §§ 1206.141(f) and 1206.142(g). After 

careful consideration, and for the 

reasons stated in the 2020 Proposed 

Rule and this final rule, this final rule 

adopts the proposed amendment with 

the modification described above to 

clarify that a lessee can report a $0.00 

royalty value. This modification 

between the 2020 Proposed Rule and 

this final rule impacts a limited number 

of instances to change the reported 

royalty value from $0.01 to $0.00. As 

such, ONRR finds there will be no 

material change to the royalties it 

collects, and it does not further 

distinguish the modification in this 

rule’s economic analysis. 

5. Providing Sales Records 

(§§ 1206.141(g) and 1206.142(h)) 

The 2020 Proposed Rule proposed to 

add new regulation language to 

reinforce ONRR’s statutory authority 

under 30 U.S.C. 1713(a), which 

expressly requires ‘‘a lessee, operator, or 

other person directly involved in 

developing, producing, transporting, 

purchasing, or selling oil or gas . . . 

through the point of first sale or the 

point of royalty computation, whichever 

is later, establish and maintain any 

records, . . . and provide any 

information’’ required by rule to ONRR 

when it is ‘‘conducting an audit or 

investigation.’’ ONRR proposed the 

addition of regulatory language to 

clarify that it may continue to request 

and receive a lessee’s and its affiliate’s 

sales and expense records, even when a 

lessee pays royalties under an indexbased valuation method. 

The ability to continue to evaluate 

sale and expense records will ensure the 

index-based valuation method remains a 

fair market value for Federal oil and gas 

lessees’ production. ONRR has the 

authority to request this information 

when conducting an audit or 

investigation, and the new regulatory 

text will preserve the ability to obtain a 

lessee’s records in order to evaluate 

whether the index-based valuation 

method remains a fair value for royalty 

purposes. 

Comments on the Proposed Amendment 

Public Comment: Several commenters 

acknowledge ONRR already has the 

authority to collect records from a lessee 

during the normal course of audit and 

compliance activity. However, the 

commenters expressed concern that 

frequent and persistent requests for data 

will create an unnecessary burden. The 

commenters referenced the preamble 

language in the 2020 Proposed Rule and 

ONRR’s suggestion that the index-based 

method should create simplicity and 

early certainty when reporting royalties. 

Commenters expressed concern that 

ONRR will continue to request and 

audit these records and eliminate any of 

the simplicity that the index-based 

method affords. 

ONRR Response: ONRR does not 

believe that adding this language to 

regulatory text will create an 

unnecessary burden on a lessee that 

elects to use the index-based method. 

Further, any burden to a lessee is 

outweighed by the certainty of knowing 

that ONRR will have access to 

information needed to periodically 

evaluate the reliability of individual 

4622 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

index prices. Finally, if ONRR requires 

a lessee to provide information under 

this section, and that information 

establishes that the index-based method 

is no longer representative of fair market 

value, any change to or repeal of the 

method would be done through 

rulemaking, and would only have 

prospective application. 

ONRR appreciates the comments 

supporting, seeking the modification to, 

or opposing the proposed amendments 

to §§ 1206.141(g) and 1206.142(h). After 

careful consideration, and for the 

reasons explained in the 2020 Proposed 

Rule and this final rule, ONRR is 

adopting the proposed changes to 

§§ 1206.141(g) and 1206.142(h) as part 

of this final rule. 

B. Transportation Allowance for Certain 

Offshore Federal Oil and Gas Gathering 

Costs 

In the 2020 Proposed Rule, ONRR 

explained the origins of its current 

‘‘gathering’’ definition and how ONRR 

and MMS have considered over the 

years whether to allow the cost of 

certain offshore gathering activities to be 

included in a lessee’s transportation 

allowance. See 85 FR 62054. Central to 

this amendment’s discussion are the 

Deepwater Policy (https://

www.onrr.gov/Laws_R_D/pubcomm/ 

PDFDocs/990520.pdf) and the 2016 

Valuation Rule, which rescinded the 

Deepwater Policy. See 81 FR 43338. 

Because of the unique nature of the 

OCS, particularly in the deepwater OCS, 

the 2020 Proposed Rule proposed to 

amend ONRR’s regulations to permit the 

same deductions previously taken under 

the Deepwater Policy. Under the 

Deepwater Policy, a lessee could claim 

certain gathering costs in its 

transportation allowance if certain 

criteria were met, including: 

• A part of the lease must lie in 

waters deeper than 200 meters. 

• The transportation allowance must 

otherwise be determined in accordance 

with ONRR’s regulations. 

• The costs must be allocated 

between the royalty bearing and nonroyalty bearing substances (for example, 

water or production subject to a zero 

royalty rate). 

• The leases and units must be 

treated similarly. 

• Movement prior to a central 

accumulation point is still disallowed 

from a transportation allowance. A 

central accumulation point, for 

purposes of the Deepwater Policy, may 

be a single well, a subsea manifold, the 

last well in a group of wells connected 

in series, or a platform extending above 

the water’s surface. 

• The movement must be to a facility 

not located on a lease adjacent to the 

lease on which the production 

originated. An adjacent lease is defined 

as a lease with at least one point of 

contact with the producing lease or unit. 

The 2020 Proposed Rule proposed to 

permit a lessee to request, and ONRR to 

approve, an application of the 

deepwater gathering-as-transportation 

principles in shallow waters under 

certain circumstances. 

The 2020 Proposed Rule also 

proposed to remove certain language 

that the 2016 Valuation Rule added to 

ONRR regulations. Specifically, through 

the 2020 Proposed Rule, ONRR removed 

(1) the language under 

§§ 1206.110(a)(2)(ii) and 

1206.152(a)(2)(ii), which provided ‘‘[f]or 

[production from] the OCS, the 

movement of [production] from the 

wellhead to the first platform is not 

transportation,’’ and (2) the portion of 

the ‘‘gathering’’ definition at § 1206.20, 

which stated that ‘‘any movement of 

bulk production from the wellhead to a 

platform offshore.’’ 

While the 2020 Proposed Rule’s 

preamble fully explained ONRR’s intent 

behind its proposal to adopt regulatory 

text that is consistent with the former 

Deepwater Policy, the proposed 

regulatory text failed to include all of 

the Deepwater Policy’s requirements. 

Specifically, the proposed regulatory 

text was not consistent across the oil 

and gas sections and did not include the 

adjacency limitation or the requirement 

for a lessee to identify a central 

accumulation point at or near the subsea 

wellheads (explained in the 6th and 5th 

bulleted points respectively, supra.). 

Comments on the Proposed Amendment 

Public Comment: Industry 

commenters endorsed ONRR’s attempt 

to adopt regulations consistent with the 

Deepwater Policy. These commenters 

argued that the Deepwater Policy 

supported innovative technology 

development that minimized surface 

facilities, reduced environmental risks, 

and increased ultimate recovery. They 

also argued that adopting regulations 

consistent with the Deepwater Policy 

would return a longstanding ONRR 

practice that lessees relied on to inform 

their business decisions. 

ONRR Response: Based on public 

comments such as these, adoption of 

regulations consistent with the 

Deepwater Policy 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 resource. Additionally, consistent 

and transparent regulations reduce 

uncertainty for investors, which 

provides a competitive advantage for 

development of domestic production. 

Recent Executive and Secretarial Orders 

call on Federal agencies to appropriately 

promote and unburden domestic energy 

production, especially OCS resources. 

See E.O. 13783, ‘‘Promoting Energy 

Independence and Economic Growth,’’ 

E.O. 13795, ‘‘Implementing an AmericaFirst Offshore Energy Strategy,’’ and 

S.O. 3350, which promotes the AmericaFirst Offshore Energy Strategy. 

Public Comment: One industry 

commenter, while supportive of the 

Deepwater Policy, argued that adoption 

of regulations consistent with the 

Deepwater Policy is moot. This 

commenter suggested that ONRR 

intends to disallow deductions for any 

movement of production that is not 

fully in marketable condition, and cited 

DCOR, LLC, ONRR–17–0074–OCS (FE), 

2019 WL 6127405 (Aug. 26, 2019) 

(‘‘DCOR’’). 

ONRR Response: The fact pattern and 

analysis in DCOR are distinguishable 

from the amendments in this rule to 

allow a lessee to claim certain OCS 

gathering costs. For example, no part of 

the leases in DCOR were located in 

water depths deeper than 200 meters. 

These amendments provide a specific 

exception to the general principle that a 

lessee may not include gathering costs 

in its transportation allowance. 

Public Comment: Several commenters 

noted the inconsistency between the oil 

and gas sections of the proposed rule. 

The oil section at § 1206.110 included 

the following language: ‘‘For oil 

produced on the OCS in waters deeper 

than 200 meters, the movement of oil 

from the wellhead to the first platform 

is transportation for which a 

transportation allowance may be 

claimed’’ and ‘‘On a case-by-case basis, 

you may apply to ONRR to have your 

actual, reasonable and necessary costs of 

the movement of oil produced on the 

OCS in waters shallower than 200 

meters from the wellhead to the first 

platform to be treated as transportation 

for which a transportation allowance 

may be claimed.’’ See 85 FR 62080. The 

gas section of the proposed rule, 

however, included no such language. 

See 85 FR 62084. 

ONRR Response: In the final rule, 

ONRR is correcting for the omissions in 

its proposed regulation text at 

§ 1206.110 to clearly adopt regulations 

consistent with the Deepwater Policy, 

except for the provision that would have 

allowed a lessee to apply for treatment 

of shallow water gathering as deductible 

transportation. ONRR is inserting 

parallel language in the gas regulations 

at § 1206.152. 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4623 

Public Comment: One commenter 

suggested that the language at 

§ 1206.110(a)(1)(i) should end with 

‘‘including’’ instead of ‘‘except.’’ 

ONRR Response: In the final rule, 

ONRR restructured the regulation text. 

The movement of bulk production from 

or near subsea wellheads to the first 

platform is gathering. However, this 

regulatory amendment provides an 

exception to the general application of 

the gathering and transportation 

regulations, allowing subsea gathering 

costs to be included in a transportation 

allowance when the regulatory 

requirements are met. 

Public Comment: One commenter 

requested that, when a lessee submits a 

request to apply the deepwater 

gathering-as-transportation principles to 

a lease in shallow waters, the regulation 

include a time limit for ONRR to 

respond and require ONRR to provide 

an explanation if the request is denied. 

ONRR Response: This final rule does 

not allow a lessee to apply for treatment 

of shallow water gathering as deductible 

transportation. A lessee may not submit, 

nor may ONRR approve, such a request 

under this final rule. Accordingly, there 

is no need for ONRR to adopt a time 

limit for its action on a shallow water 

request. However, ONRR intends to 

continue studying any need for, and the 

economic impact of, a shallow water 

gathering allowance, and may propose a 

future rulemaking on this subject. 

Public Comment: Public interest 

groups opposed the effort, arguing the 

policy permitted, in the form of a 

transportation allowance, is an 

improper deduction under ONRR’s 

regulatory scheme. A commenter argued 

that ONRR does not have the authority 

to incentivize production and should 

not attempt to do so using a policy like 

this to minimize a lessee’s royalty 

obligations. Another commenter stated 

that the oil and gas industry has 

received several royalty relief measures 

for offshore production and that the 

government should not be further 

helping industry at the taxpayers’ 

expense. 

ONRR Response: Although ONRR’s 

primary focus is the collection, 

verification, and disbursement of 

natural resources revenues, it shares the 

Department’s policy goals to promote 

the development of natural resources 

and to obtain for the public a reasonable 

financial return on assets that belong to 

the public. See S.O. 3350 and S.O. 3360. 

ONRR has the statutory authority to 

promulgate regulations and to carry out 

the stated purposes of the Acts as 

explained further in the introduction of 

this final rule. The mineral leasing 

authorities granted to the Secretary by 

Congress provide broad authorities to 

‘‘prescribe necessary and proper rules 

and regulations and to do any and all 

things necessary to carry out and 

accomplish the purposes of [the leasing 

statutes]’’, including the collection of all 

revenues associated with such activities, 

including the OCS. 30 U.S.C. 189 

(MLA); 30 U.S.C. 1751 (FOGRMA); 43 

U.S.C. 1334(a) (OCSLA). 

Public Comment: The States of 

California and New Mexico opposed 

this change, arguing it will cause 

companies to improperly deduct costs 

that should be considered gathering and 

is inconsistent with the definition of 

gathering clarified in conjunction with 

the rescission of the Deepwater Policy 

in the 2016 Valuation Rule. These States 

asserted the 2016 Valuation Rule 

allowed for a more consistent and 

reliable application of the regulations. 

ONRR Response: Historically, the 

regulatory framework for gathering and 

transportation did not recognize the 

unique technology and development 

model, higher risk and substantial cost 

of developing and producing oil and gas 

in unique environments, like the 

deepwater OCS. However, by practice 

from 1999 until the 2016 Valuation 

Rule, these types of developments were 

allowed as part of a lessee’s 

transportation deduction. 

The commenters are correct that 

subsea movement of bulk production 

before the royalty measurement point 

would be defined, under the 2016 

Valuation Rule and this final rule, as 

gathering. However, in this final rule, 

pursuant to the Secretary’s authority to 

create rules and definitions for royalty 

collection purposes and to provide for 

the expeditious and orderly 

development of the OCS, ONRR is 

creating a new regulatory exception to 

the rules for gathering and 

transportation in order to provide a 

deduction for a lessee that carries the 

higher risk and cost of production in the 

deepwater OCS. 

This change from the 2016 Valuation 

Rule is being made at this time because 

the GOM is currently viewed as a 

mature hydrocarbon province; most of 

the acreage available for leasing has 

received multiple seismic surveys, has 

been offered for lease a number of times, 

or is under lease. Many of the remaining 

reserves are located in smaller fields 

that do not warrant stand-alone 

development and are unlikely to be 

developed, unless using subsea 

completions with tiebacks to existing 

platforms. The risks and costs of subsea 

tiebacks are significant, especially when 

developing a resource within a high 

pressure and high temperature reservoir, 

and many of the remaining 

undiscovered technically recoverable 

resources in the GOM are within this 

type of reservoir. The actual discovery, 

development, and production of oil and 

natural gas results not from the 

inventory and data compiled by the 

government, but from efforts by a 

diverse set of companies working to 

identify oil and gas prospects that 

warrant investment. When examining 

alternative investment opportunities, 

companies will consider not only the oil 

and gas potential of an area, but also the 

expected costs of development, as 

compared to alternative investments. 

The expected profitability of specific 

projects will be affected by a company’s 

determinations of geologic and 

economic risk. 

Public Comment: A few public 

interest groups and States noted that in 

the 2016 Valuation Rule, ONRR 

explained the Deepwater Policy had 

served its purpose and is no longer 

necessary. These commenters argued 

that ONRR has not sufficiently 

explained the reason for adopting 

regulations consistent with the 

Deepwater Policy. 

ONRR Response: When the Deepwater 

Policy was written in 1999, the 

Department’s intent was to acknowledge 

that: ‘‘new technologies involved in 

deepwater development were not 

specifically contemplated’’ in the 

regulations at that time. See 63 FR 

56217. In the 2016 Valuation Rule, 

based on the significant deepwater 

development that had occurred since 

1999, and consistently high commodity 

prices during the years the 2016 

Valuation Rule was in development, the 

Department determined that the 

Deepwater Policy had served its 

purpose and was no longer needed. 

More recently, however, commodity 

prices have once again significantly 

changed. Rather than make policy 

decisions based on commodity prices 

that are nearly impossible to predict, the 

Department has reassessed the statutory 

direction provided clearly in the OCSLA 

which states that: ‘‘the [OCS] 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,’’ (see 43 U.S.C. 1332), 

and has assessed concrete data provided 

by BOEM and BSEE on permitting 

activity as well as geologic prospects on 

the OCS. Consequently, the decision to 

adopt regulations consistent with the 

Deepwater Policy has been made for 

several reasons. 

4624 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

First, from 2010–2014, the average 

NYMEX oil price was approximately 

$92/bbl and the average natural gas 

price was approximately $3.85/ 

MMBTU, while over the last five years 

(July 2015 to June 2020), the average 

NYMEX oil price was approximately 

$51/bbl and the average natural gas 

price was approximately $2.67/ 

MMBTU. 

In addition to the decreases in 

commodity prices, APDs in the GOM 

have declined, from an average of 173 

in FY 2016 through FY 2019 to 140 in 

FY 2020. During the same time period, 

onshore APDs have significantly 

increased, from an average of 3,548 in 

FY 2016 through FY 2019 to 6,234 in FY 

2020. 

Also, when ONRR’s 2016 Valuation 

Rule was promulgated, BOEM had 

published its 2011 National Assessment 

of Undiscovered Oil and Gas Resources 

of the U.S. Outer Continental Shelf. 

BOEM’s 2016 version of the same 

assessment—which was not available 

when the 2016 Valuation Rule was 

promulgated—showed declines in the 

GOM’s economically recoverable oil 

resources and significant declines in the 

economically recoverable natural gas 

resources. Information from BOEM 

shows the remaining economically and 

technically recoverable oil and gas 

resources are all significantly lower than 

the 2016 estimates. The estimated 

number of large GOM oil pools has been 

reduced and the estimated remaining 

natural gas resources has been further 

scaled back. 

Regarding other input on this topic, in 

the 2020 Proposed Rule, ONRR sought 

comments on how its regulations could 

be revised to address deductions for 

other remote areas, like Alaska’s North 

Slope. ONRR thanks several 

commenters for their helpful responses. 

ONRR did not include provisions 

specific to remote areas in this final rule 

but will continue examining the issue. 

In this final rule, ONRR retains the 

provision allowing lessees to deduct 

certain offshore deepwater gathering 

costs in its transportation allowance 

when certain criteria are met. Certain 

production environments, like the 

deepwater OCS, require unique 

technology and carry more risk and 

costs than onshore environments, 

resulting in a deepwater OCS 

development model that is drastically 

different from onshore counterparts. 

Additionally, the GOM is currently 

viewed as a maturing hydrocarbon 

province; most of the acreage available 

for leasing has received multiple 

seismic surveys and has been leased. 

Many of the remaining reserves are 

located in smaller fields that do not 

warrant stand-alone development and 

will be developed, if at all, using subsea 

completions with tiebacks to existing 

platforms. However, the risks and costs 

of subsea tiebacks are significant, 

especially when developing a resource 

within a high pressure and high 

temperature reservoir. Many of the 

remaining undiscovered technically 

recoverable resources in the GOM are 

within this type of reservoir. See https:// 

www.boem.gov/sites/default/files/oiland-gas-energy-program/EnergyEconomics/Fair-Market-Value/2018- 

GOM-International-Comparison.pdf. 

The regulations adopting language 

consistent with the deepwater policy 

recognize the benefits that offshore 

production offers the American public 

in meeting U.S. demand for oil and gas 

when compared to onshore U.S. 

production by allowing for a smaller 

surface footprint with increased well 

productivity and longer lifespans. See 

https://www.nap.edu/read/25439/ 

chapter/4#14. Additionally, deepwater 

economic limits are expected to be 

greater than shallow water economic 

limits because deepwater structures are 

larger, more complex, further from 

shore, and almost all structures are 

manned. This further emphasizes the 

impact that granting an allowance for 

deepwater gathering costs, when 

applied over the life of a facility, offers 

by increasing net revenue to shift the 

break-even cost curve and extend the 

life of the reservoir. See Mark J. Kaiser, 

in Decommissioning Forecasting and 

Operating Cost Estimation, 2019. 

Offshore oil and gas production is of 

strategic national importance, as it has 

accounted for between 15–20 percent of 

domestic oil production over the past 

decade and generates billions of dollars 

in revenue for the U.S. Treasury, various 

conservation initiatives, and revenue 

sharing for four Gulf states. Crude oil 

produced from the OCS is generally of 

heavier quality and refined in the Gulf 

Coast for use throughout the country to 

meet U.S. national energy needs. 

ONRR and its predecessor, MMS, 

recognized the increased risk, cost, and 

national importance of producing in the 

deepwater OCS, but historically did not 

provide a regulatory mechanism for a 

lessee to deduct appropriate expenses. 

In 1999, MMS adopted the Deepwater 

Policy, which granted deductions for 

the higher costs of moving production 

in the deepwater OCS while also 

creating some confusion about the 

authority of the policy (provided 

through Departmental memorandum) 

and its relationship to MMS’ valuation 

regulations. This final rule resolves that 

confusion by clearly articulating the 

elements of the Deepwater Policy in the 

regulatory text. 

ONRR’s current regulations prohibit a 

lessee from including gathering costs in 

its transportation allowance for all 

Federal oil and gas production. See 

§§ 1206.110(a) and 1206.152(a). The 

regulations define gathering as ‘‘the 

movement of lease production to a 

central accumulation or treatment point 

on the lease, unit, or communitized 

area, or to a central accumulation or 

treatment point off of the lease, unit, or 

communitized area that BLM or BSEE 

approves for onshore and offshore 

leases, respectively, including any 

movement of bulk production from the 

wellhead to a platform offshore.’’ See 30 

CFR 1206.20. Gathering does not end 

and transportation does not begin before 

a lessee moves production to the point 

where it is measured for royalty 

purposes. 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. In 

adopting regulations consistent with the 

Deepwater Policy, ONRR is amending 

§ 1206.110(a) and § 1206.152(a) to 

permit a lessee to include, in its 

transportation allowance, costs incurred 

in moving offshore production upstream 

of the royalty measurement point when 

certain requirements are satisfied. 

Solely for purposes of this amendment, 

ONRR is defining central accumulation 

point to include a single well, a subsea 

manifold, the last well in a group of 

wells connected in a series, or a 

platform extending above the surface of 

the water, even when prior to the 

royalty measurement point, and only to 

the extent all other regulation 

requirements are met. See, infra., 

§§ 1206.110(a)(2)(ii) and 

1206.152(a)(2)(ii). In all other situations, 

the central accumulation point remains 

at or downstream of the royalty 

measurement point. 

The 2020 Proposed Rule included a 

provision allowing a lessee to request, 

and ONRR to approve, an application of 

the deepwater gathering-astransportation principles in water 

depths of 200 meters and shallower. 

ONRR is not adopting the specific 

provision relating to shallow water 

gathering in the final rule. While there 

was such a provision in ONRR’s 

Deepwater Policy in effect from 1999 

through 2016, no lessee ever requested 

an allowance for its shallow water 

gathering. The fact lessees did not 

request such relief shows the provision 

did not effectively incentivize shallow 

water production, nor did it provide 

ONRR with a foundation for estimating 

the economic impact of a shallow water 

gathering allowance. While ONRR 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4625 

invited public comment on a possible 

shallow water gathering allowance in 

the 2020 Proposed Rule, the public 

comments received also did not provide 

sufficient information to justify or 

quantify the impact of such an 

allowance. ONRR intends to further 

examine the matter and, if determined 

to be appropriate, may make shallow 

water gathering the subject of a future 

rulemaking. 

In this final rule, ONRR removed the 

proposed language at § 1206.110. In its 

place, ONRR is adding regulatory text 

that is largely consistent with the 

Deepwater Policy except for the shallow 

water provision. This language is 

included in the final rule under both 

§§ 1206.110(a) and 1206.152(a), and 

references thereto in the definition of 

‘‘gathering’’ under § 1206.20. 

C. Allowance Limits for Federal Oil and 

Gas 

The MLA requires a lessee to pay 

royalties at a minimum of 12.5 percent 

in amount or value of production 

removed or sold from the leased lands. 

30 U.S.C. 226(b)(1)(A). OCSLA requires 

a royalty of not less than 12.5 percent 

in amount or value of production saved, 

removed, or sold from the leases. 43 

U.S.C. 1337(a)(1)(A). Although the MLA 

and OCSLA do not define the term 

‘‘value,’’ it is well-established that the 

Secretary has the authority and 

considerable discretion to establish the 

value for royalty purposes of production 

from Federal oil and gas leases. United 

States v. Ohio Oil Co., 163 F.2d 633 

(10th Cir. 1947); Cont’l Oil Co. v. United 

States, 184 F.2d 804 (9th Cir. 1950); 

Marathon Oil Co. v. United States, 604 

F. Supp. 1375 (D. Alaska 1985); Amoco 

Prod. Co., 29 IBLA 234 (1977). 

The regulations at 30 CFR part 1206 

govern value and, under these 

regulations, the Secretary allows 

deductions for transportation and 

processing. See, e.g., 30 CFR 1206.110, 

1206.152, and 1206.159. Secretarial 

discretion, augmented by case law, 

supports the Federal lessor sharing in 

the increased value to the royalty share 

and costs of the royalty share when a 

lessee transports production to a market 

off the lease or processes natural gas 

into gas plant products. 

From the late 1980s to December 30, 

2016, ONRR regulations permitted a 

lessee to request that ONRR allow it to 

exceed the regulatory limits for 

transportation allowances (50 percent 

limit for Federal oil and Federal gas) or 

processing allowances (662⁄3 percent 

limit for Federal gas) (‘‘request to 

exceed’’). Under a different process, a 

lessee could provide data and 

documentation to support its request to 

claim an extraordinary processing 

allowance (‘‘request to claim’’). The 

2016 Valuation Rule converted the prior 

regulatory limits from a soft cap (that is, 

one that could be exceeded upon 

application to and approval by ONRR) 

to a hard cap (one that could not be 

exceeded) and terminated all currentlyexisting approvals. At that time, a 

significant number of companies had 

received approvals to exceed the 

transportation and processing allowance 

limits and ONRR had approved two 

applications for extraordinary 

processing allowances. 

In the 2020 Proposed Rule, ONRR 

proposed to remove the hard caps on 

transportation and processing costs and 

revert to soft caps, and also to allow a 

lessee to once again request an 

extraordinary processing allowance. As 

before the 2016 Valuation Rule, the 

lessee would submit to ONRR a request 

to exceed form (form ONRR–4393) and 

ONRR would review and approve the 

request before the lessee could properly 

report allowances in excess of soft 

regulatory limits. Similarly, a lessee 

requesting ONRR approval for an 

extraordinary processing allowance 

would submit documentation 

supporting its claim for ONRR to review 

and either approve or deny. 

Based on comments ONRR received 

on the 2020 Proposed Rule and the 

economic analysis in this final rule, 

ONRR finds that this final rule should 

retain the hard caps on transportation 

and processing allowances but reinstate 

the provision allowing a lessee to 

request approval for an extraordinary 

processing allowance. ONRR’s 

economic analysis shows that the 

financial impact to the Federal lessor, 

states, and industry arising from the 

retention of the hard caps is less than 

$500,000 per year. This represents a 

significant change from ONRR’s 

economic analysis in the 2020 Proposed 

Rule, and the benefit to lessees and 

financial impact to states is 

considerably less than ONRR originally 

estimated. In broad terms, the updated 

royalty impact associated with changing 

the hard caps to soft caps is insufficient 

to support making the change when 

considered in combination with public 

comments on this issue and, to a lesser 

extent, the potential increased 

administrative burden on ONRR and 

lessees. Section VII, entitled 

‘‘Procedural Matters,’’ of this final rule 

describes a breakdown of the royalty 

impacts associated with gas 

transportation, oil transportation, and 

gas processing. ONRR addresses public 

comments on the 2020 Proposed Rule in 

the Public Comments section of this 

final rule below. 

Finally, with respect to reinstating the 

language allowing a lessee to request an 

extraordinary processing allowance, 

ONRR reviewed comments from 

industry and the State of Wyoming 

where the facilities that were the subject 

of the two prior approvals for 

extraordinary processing allowances 

were located. Both were supportive of 

the proposed change. For the reasons 

outlined in the extraordinary processing 

allowance section below, this final rule 

reinstates a lessee’s ability to request 

approval for an extraordinary processing 

allowance. 

Several commenters provided 

comments on portions of the 2016 

Valuation Rule that were beyond the 

scope of the 2020 Proposed Rule. The 

comments ranged in support of 

continuing to value arm’s-length 

percent-of-proceeds contracts as 

processed gas, to supporting the 

requirement that transportation and 

processing pricing factors be reported as 

allowances, instead of being netted from 

the gross sales price or value. Other 

comments related to the 2016 Valuation 

Rule included objection to the removal 

of a provision that allowed a lessee to 

use FERC or state-approved tariffs to 

calculate transportation rates in nonarm’s-length transportation allowances, 

the removal of line fill costs in the 

calculation of arm’s-length 

transportation allowances, and the 

removal of transportation factors in the 

price of the product. Several 

commenters recommended that ONRR 

restore the 1.3 multiplier to the BBB 

bond rate used to calculate non-arm’slength transportation costs. These 

commenters also suggested that, in light 

of Standard and Poor’s decision to no 

longer provide its BBB bond rate free to 

industry, ONRR select a different rate 

and publish the rate on ONRR.gov to 

alleviate confusion and inconsistency 

when calculating non-arm’s-length 

transportation allowances. Lastly, ONRR 

received comments asserting that 

valuing sales of arm’s-length 

unprocessed gas as processed gas, such 

as in the case of percent-of-index and 

percent-of-proceeds contracts, is 

arbitrary. ONRR appreciates the 

comments but does not address the 

comments in the sections below because 

the comments are outside the scope of 

this rulemaking. 

1. Transportation Allowance Limits for 

Federal Oil and Gas (§§ 1206.110(d)(1) 

and (2) and 1206.152(e)(1) and (2)) 

In the 2016 Valuation Rule, ONRR 

eliminated the regulations that allowed 

it to approve oil (§ 1206.110) and gas 

(§ 1206.152) transportation allowances 

4626 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

in excess of 50 percent of the value of 

a lessee’s production. 

In the 2020 Proposed Rule, ONRR 

proposed to revert to the historical 

practice of treating the 50 percent cap as 

a soft cap on oil and gas transportation 

costs. As discussed in the background 

above, ONRR retains the hard caps from 

the 2016 Valuation Rule in this final 

rule. 

Comments on the Proposed Amendment 

Public Comment: Several commenters 

supported ONRR’s authority to approve 

transportation allowances in excess of 

the 50 percent allowance cap. These 

commenters stated that the option to 

request approval to exceed the 50 

percent cap is necessary because it 

allows a lessee to deduct its actual, 

reasonable, and necessary transportation 

costs, even if those costs exceed 50 

percent, which is especially important 

in a low commodity price environment. 

ONRR Response: ONRR agrees that 

the oil and gas markets changed 

between the adoption of the 2016 

Valuation Rule and the 2020 Proposed 

Rule. ONRR understands that market 

volatility and the global pandemic have 

adversely affected the oil and gas 

industry. However, it may be 

counterproductive to make regulatory 

changes based on market volatility 

because frequent regulatory changes 

may decrease early certainty to lessees 

and make Federal leases less attractive 

to current and potential lessees. 

Retaining the hard caps on allowances 

supports a fair return to the public on 

their non-renewable natural resources. 

Public Comment: A commenter 

suggested that ONRR approve 

exceptions to the 50 percent limit 

prospectively for a two-year or threeyear period to reduce the administrative 

burden associated with applying for and 

approving or denying these requests. 

Another commenter stated that ONRR 

could offset the administrative burden 

associated with reviewing and 

approving requests to exceed the 

transportation allowance limits by 

approving allowances for more than a 

single year at a time. 

ONRR Response: ONRR appreciates 

comments and suggestions related to 

reducing administrative burden. ONRR 

is retaining the hard caps in this final 

rule, which eliminates any associated 

increase in administrative burdens. 

Public Comment: A commenter 

suggested that ONRR modify the 

allowance to include a 120-day time 

limit for ONRR to respond to a request 

and that ONRR provide a detailed 

explanation if ONRR denies a request. 

The commenter argues these actions 

provide certainty to the lessee regarding 

their allowance calculations. 

ONRR Response: ONRR appreciates 

these suggestions. However, since 

ONRR is retaining the hard caps rather 

than removing them in this final rule, 

there will not be any application to 

which a 120-day mandate could apply, 

nor will there be a need to provide a 

detailed explanation for a denial. 

Public Comment: A commenter 

recommended that ONRR reinstate any 

approval to exceed the 50 percent 

transportation allowance limits for oil 

and gas that was in place prior to the 

reinstatement of the 2016 Valuation 

Rule. 

ONRR Response: The 2016 Valuation 

Rule terminated all approvals to exceed 

the transportation allowance limits prior 

to its January 1, 2017, effective date. 

ONRR has no authority to grant future 

applications retroactively, and is 

retaining the hard caps in this final rule. 

Public Comment: A commenter 

asserted that ONRR should eliminate 

transportation allowances entirely 

because they amount to an uncapped 

subsidy of the oil, gas, and coal 

industries. 

ONRR Response: Transportation 

allowances are a well-established 

standard supported by case law and 

precedent. See, e.g. 30 CFR 1206.110 

and 1206.152 and United States v. Gen. 

Petroleum Corp. of California, 73 F. 

Supp. 225, 262 (S.D. Cal. 1946). This 

final rule retains the hard caps on 

transportation and processing 

allowances. 

Public Comment: A commenter 

asserted that ONRR should eliminate 

allowances entirely because providing a 

lessee the option to deduct 

transportation or processing allowances 

in excess of the caps disincentivizes 

lessees to reduce their costs. Another 

commenter asserted that allowing 

lessees to request to exceed the limits 

does not incentivize the lessee to lower 

operational costs and negatively impacts 

royalty payments, which in some 

instances support local schools. 

ONRR Response: Transportation and 

processing allowances are intended to 

benefit both a lessee and the Federal 

lessor because of typically higher 

market values found off the lease, or 

from recovering NGLs. Courts have 

upheld the use of allowances to 

calculate the value of Federal oil and 

gas production for royalty purposes. See 

United States v. Gen. Petroleum Corp. of 

California, 73 F. Supp. 225, 262 (S.D. 

Cal. 1946) (stating ‘‘It has been held that 

if there is no open market in the place 

where an article ordinarily would be 

sold, the market value of such article in 

the nearest open market less cost of 

transportation to such open market 

becomes the market value of the article 

in question.’’), aff’d sub nom. Cont’l Oil 

Co. v. United States, 184 F.2d 802 (9th 

Cir. 1950). 

Also, a lessee already has an incentive 

to minimize its transportation and 

processing costs. Typically, the Federal 

Government’s royalty share of 

production is 121⁄2 or 162⁄3 percent. The 

lessee retains the remaining 871⁄2 or 

831⁄3 percent respectively, and has every 

incentive to minimize the transportation 

and processing costs borne by its sizable 

share. The Federal Government benefits 

from the lessee’s incentive to be costconscious on its greater share. ONRR 

does not expect limiting the 

transportation and processing 

allowances on a smaller share of 

production to change lessee behavior in 

incurring transportation and processing 

expenses borne by the lessee’s greater 

share. In this final rule, ONRR retains 

the hard caps on allowances, consistent 

with the commenter’s request. ONRR 

acknowledges that market conditions 

and the global pandemic have 

negatively impacted many budgets, 

including for schools. 

Public Comment: A commenter 

asserted that ONRR did not provide 

justification for incentivizing 

production in low-quality reservoirs, 

which the commenter suggested may 

cause harmful environmental 

externalities. A second commenter 

suggested ONRR did not address any 

environmental consequences associated 

with reinstating the requests to exceed 

the transportation limit. Another 

commenter asserted that ONRR did not 

fully perform its due diligence to ensure 

consistency with multiple use 

management laws. 

ONRR Response: Allowing a lessee to 

request to exceed the hard caps may not 

provide sufficient economic incentive 

for that lessee to continue producing or 

seek additional production from Federal 

lands. The Federal Government’s 

royalty share of production is typically 

121⁄2 or 162⁄3 percent; the lessee’s share 

of production is typically the remaining 

871⁄2 or 831⁄3 percent. Small changes in 

the calculation of the value of the 

Federal Government’s 121⁄2 or 162⁄3

percent share become even smaller 

when spread over the value of the 

lessee’s 871⁄2 or 831⁄3 percent share, 

making it difficult for the Federal 

Government to effectively incentivize 

industry action. While allowing a lessee 

to request to exceed the hard caps could 

provide some economic incentive to the 

lessee, such action would also increase 

the lessee’s administrative cost burden. 

See Section V for ONRR’s economic 

analysis. ONRR has determined that, on 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4627 

balance, removing the hard caps is not 

warranted, and is retaining the hard 

caps in its regulations. 

ONRR addresses public comments 

about environmental considerations in 

the introduction to this rule. As to the 

comment regarding consistency with 

multiple use management laws, the 

commenter failed to specify which 

multiple use management laws ONRR 

failed to consider. While ONRR cannot 

respond directly to this comment, it has 

addressed the specific acts raised by 

other commenters in the introduction. 

Oil: ONRR retained the current 

language in § 1206.110(d)(1) and (2), 

which limits transportation allowances 

to 50 percent of the value of oil 

transported. Despite the current market 

volatility, ONRR believes that it is in the 

public interest to retain the hard cap. 

Gas: ONRR retained the current 

language in § 1206.152(e)(1) and (2), 

which limits transportation allowances 

to 50 percent of the value of 

unprocessed gas, residue gas, or gas 

plant products transported. Despite the 

current market volatility, ONRR believes 

that it is in the public interest to retain 

the hard cap. 

2. Processing Allowance Limits for 

Federal Gas (§ 1206.159(c)(2) and (3)) 

In the 2016 Valuation Rule, ONRR 

eliminated the regulation allowing it to 

approve gas processing allowances in 

excess of 662⁄3 percent of the value of a 

lessee’s gas production. 

In the 2020 Proposed Rule, ONRR 

proposed to revert to historical practices 

by treating the regulatory limit as a ‘‘soft 

cap’’ on gas processing costs (662⁄3

percent regulatory limit). As discussed 

in the background above, ONRR retains 

the hard caps from the 2016 Valuation 

Rule in this final rule. 

Comments on the Proposed Amendment 

Public Comment: Several commenters 

supported the 2020 Proposed Rule’s 

provision for ONRR to approve requests 

to exceed the 662⁄3 percent limit on 

processing allowances. The commenters 

stated that the right to request approval 

to exceed the 662⁄3 percent cap needs to 

be reinstated because its removal denied 

lessees the ability to deduct all of their 

actual, reasonable, and necessary 

processing costs when those costs 

exceed 662⁄3 percent. The commenters 

asserted that this is especially true when 

the physical make-up of the gas 

necessitates complex plant designs 

which result in higher processing costs. 

Last, a commenter took issue with 

ONRR terminating any approval that it 

previously issued for a lessee to exceed 

the 662⁄3 percent limitation. 

ONRR Response: Although the oil and 

gas market clearly changed between the 

drafting of the 2016 Valuation Rule and 

the 2020 Proposed Rule, and ONRR 

understands that the oil and gas 

industry, like many industries, has been 

adversely affected by market volatility 

and the global pandemic, ONRR’s 

regulations are designed to continue to 

function during uncommon or 

unavoidable circumstances affecting 

costs and value. ONRR believes 

retaining the hard caps on allowances 

supports a fair return to the public on 

non-renewable natural resources. 

Public Comment: A commenter 

suggested ONRR reduce administrative 

costs arising from processing the 

requests to exceed by approving the 

exception for periods of two or more 

years for lessees with contracts that 

have been reviewed and which are 

consistently over the limits. 

ONRR Response: ONRR appreciates 

the suggestion. Because ONRR is 

retaining the hard caps in this final rule, 

there are no associated administrative 

costs. 

Public Comment: A commenter 

suggested that ONRR modify the 

allowance to include a 120-day mandate 

for ONRR to respond to a request and 

that ONRR provide a detailed 

explanation if ONRR denies a request. 

ONRR Response: ONRR appreciates 

the suggestions and responded to a 

parallel suggestion in the discussion of 

transportation costs, above. That 

response is applicable here, as well. 

Public Comment: A commenter stated 

they oppose ONRR’s approval to exceed 

the 662⁄3 percent cap on processing 

allowances and allowances in general. 

Another commenter stated that allowing 

a lessee to request to exceed the 662⁄3

percent limitation on processing 

allowances is a savings for industry at 

the expense of taxpayers due to a 

reduction in royalty payments. 

ONRR Response: The comments 

regarding the 662⁄3 percent processing 

allowance mirror the comments that 

ONRR received for the 50 percent 

limitation on transportation allowances 

for oil. Please refer to ONRR’s responses 

regarding the 50 percent transportation 

cap. 

ONRR retained the current language 

in § 1206.159(c)(2) and (3), which limits 

processing allowances to 662⁄3 percent 

of the value of the gas plant products 

recovered. Despite the current volatile 

market conditions, ONRR believes that 

it is in the public interest to retain the 

hard cap on processing allowances. 

3. Extraordinary Processing Allowances 

for Federal Gas (§ 1206.159(c)(4)) 

The 2016 Valuation Rule removed the 

provision that was in place between 

March 1, 1988 (53 FR 1230, January 15, 

1988), and December 31, 2016 (81 FR 

43338, July 1, 2016), under 

§ 1206.158(d)(2), which allowed a lessee 

to request an extraordinary processing 

allowance. Under the prior 

§ 1206.158(d)(2), on application to and 

with ONRR’s approval, a lessee could 

deduct its actual and reasonable 

processing costs up to 99 percent of the 

value of the gas plant products extracted 

and up to 50 percent of the value of the 

residue gas. See 81 FR 43353, July 1, 

2016. For ONRR’s approval, a lessee’s 

application must have demonstrated 

that the gas stream, plant design, and/ 

or unit costs were extraordinary, 

unusual, or unconventional relative to 

standard industry conditions and 

practice. See e.g. Amoco Prod. Co. v. 

Baca, 300 F. Supp. 2d 1, 13–14 (D.D.C. 

2003); see also Exxon Corp., 118 IBLA 

221, n. 7 (1991). In justifying the 

elimination of extraordinary processing 

allowances, ONRR stated in the 2016 

Valuation Rule that ‘‘the markets and 

the technology have changed 

sufficiently such that this provision and 

these approvals are no longer 

necessary.’’ See 81 FR 43353 (July 1, 

2016). 

The 2016 Valuation Rule terminated 

the two existing ONRR-approved 

extraordinary processing allowance 

claims for lessees processing gas at two 

facilities in Wyoming. In response to the 

2020 Proposed Rule, the Governor of 

Wyoming and the members of 

Wyoming’s Congressional delegation 

submitted comments stating that this 

allowance is essential for two major gasprocessing facilities in Wyoming. The 

commenter further explained that this 

process is challenging and expensive. 

According to the commenter, these gas 

processing operations provide an 

important source of valuable gasses, 

including helium, which is relied upon 

by consumers in Wyoming and the rest 

of the country. The commenters 

representing Wyoming argued that 

extraordinary processing allowances are 

warranted because certain Wyoming gas 

processing facilities face a serious 

competitive disadvantage without them, 

which may cause those plants to be 

prematurely retired. 

Upon receipt of those comments, 

ONRR reexamined the facts and the 

assertion in the 2016 Valuation Rule 

that there were technological advances 

that rendered the extraordinary 

processing allowances unnecessary. 

While gas markets have indisputably 

4628 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

changed since MMS added the 

extraordinary processing allowance 

provision to the regulations (53 FR 

1230, January 15, 1988), and gas 

processing technologies have improved 

overall, the technology necessary to 

process these two gas streams, 

characterized by high concentrations of 

nitrogen, carbon dioxide, hydrogen 

sulfide, methane, and almost no 

recoverable NGLs, see Exxon Corp., 118 

IBLA 221, n. 7 (1991), remains 

substantially the same. See, e.g., Eow, 

J.S. (2002), Recovery of sulfur from sour 

acid gas: A review of the technology. 

Environ. Prog., 21: 143–162, https://

doi.org/10.1002/ep.670210312; Reviews 

in Chemical Engineering, Volume 29, 

Issue 6, Pages 449–470, eISSN 2191– 

0235, ISSN 0167–8299, DOI: https://

doi.org/10.1515/revce-2013-0017. 

Therefore, reinstating the provision that 

allowed a lessee to request approval to 

take an extraordinary processing 

allowance is appropriate, as the 

technology to process these unique gas 

streams has not changed, despite 

technological advances in processing 

relevant to many other areas and types 

of gas streams. 

Further, as was noted by the Governor 

of Wyoming and Wyoming’s 

Congressional delegation, one of these 

unique gas streams contains recoverable 

quantities of helium, an element that is 

vital to the Nation’s security and 

economic prosperity. See Final List of 

Critical Minerals 2018, https://

www.usgs.gov/news/interior-releases2018-s-final-list-35-minerals-deemedcritical-us-national-security-and, 

published May 18, 2018 (83 FR 23295). 

Helium production is governed by the 

Helium Stewardship Act of 2013, Public 

Law 113–40, codified at 50 U.S.C. 167– 

167q, and is administered by the BLM. 

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

energy-and-minerals/helium. 

Accordingly, 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. See, e.g., 

https://www.nap.edu/read/9860/ 

chapter/7#41. In instances where a 

lessee might not otherwise choose to 

produce a gas resource containing 

helium, allowing a lessee to apply for an 

extraordinary processing allowance 

approval for the natural gas portion of 

their production stream, may lower 

natural gas production costs and 

incentivize new or continued 

production of helium. However, the 

extraordinary processing allowance 

does not apply to helium and to obtain 

a reduction in helium rates, the helium 

extractor would need to request this 

separately with the BLM Amarillo 

Federal Leased Lands Team. 

In light of the foregoing, and after 

careful consideration of the public 

comments discussed in more detail 

below, this final rule reverts to ONRR’s 

long-standing historical practice and 

reinstates the provision that was in 

place between March 1, 1988 (53 FR 

1230, January 15, 1988), and December 

31, 2016 (81 FR 43338, July 1, 2016), 

under 30 CFR 1206.158(d)(2)(i) to the 

updated § 1206.159(c)(4). Adoption of 

this amendment will allow a lessee to 

apply to ONRR for approval to claim an 

extraordinary processing allowance. 

Comments on the Proposed Amendment 

Public Comment: Several commenters 

stated that ONRR should restore the 

option for lessees to request approval for 

extraordinary processing allowances. 

The commenters argued that ONRR’s 

prior limited approvals were for gas 

streams with unique gas compositions 

that were processed at gas plants with 

complex plant designs and extremely 

high unit costs. The commenters stated 

that the lessees with those approvals 

made investment decisions based on the 

approvals. Without the ability to deduct 

additional, extraordinary processing 

costs against the value of the residue gas 

recovered, the economic viability of 

lease operations was questionable. 

These commenters further asserted that 

ONRR was incorrect in the 2016 

Valuation Rule when it stated that 

technological advancements since the 

1990s meant that these approvals were 

no longer necessary. 

ONRR Response: Reinstating this 

provision may remove the potential 

disincentive for a lessee to develop 

Federal lands disadvantaged by gas 

streams requiring complex and costly 

facilities, which, like the composition of 

the gas streams, are unique, 

extraordinary, or unconventional. 

Receiving an approval under this 

provision may also provide a lessee an 

incentive to continue producing through 

uncommon or unavoidable 

circumstances affecting costs and value. 

As already discussed, ONRR concedes 

that, despite other technological 

advances relevant to processing, the 

technology necessary to process unique 

gas streams such as that used at the two 

Wyoming facilities discussed above has 

not changed appreciably since the prior 

approvals were given in the 1990s. 

Public Comment: Several commenters 

requested that ONRR reinstate the 

extraordinary processing allowance 

approvals terminated by the 2016 

Valuation Rule. 

ONRR Response: The 2016 Valuation 

Rule terminated the prior approvals that 

ONRR granted before January 1, 2017. 

81 FR 43338 (July 1, 2016). This final 

rule will add language allowing a lessee 

to again request an approval. However, 

ONRR will apply this final rule 

prospectively, beginning with its 

effective date. ONRR cannot reinstate 

the two extraordinary processing 

allowance approvals that the 2016 

Valuation Rule terminated, nor can 

ONRR grant such allowances for the 

period between January 1, 2017, and the 

effective date of this final rule. Rather, 

each of the lessees will need to reapply 

to ONRR for approval. And, as before 

the 2016 Valuation Rule, ONRR may 

only approve a lessee’s request after 

reviewing the lessee’s documentation 

for adequacy, reasonableness, and 

accuracy. ONRR anticipates that it will 

again receive few requests and will 

rarely grant approval under this 

provision, as was the case when the 

language was in place between March 1, 

1988, and December 31, 2016. 

Public Comment: A commenter stated 

that ONRR should not restore the ability 

for a lessee to request an extraordinary 

processing allowance approval because 

the 2016 Valuation Rule ensured a fair 

return to the public. 

ONRR Response: ONRR is committed 

to ensuring a fair return to the American 

public for oil and gas produced from 

Federal lands. Allowing a lessee to 

deduct actual, reasonable, extraordinary 

post-production processing costs is part 

of ensuring a fair return. Prior to the 

2016 Valuation Rule, just two approvals 

for extraordinary processing allowances 

were in effect. Both were for leases in 

Wyoming. The State of Wyoming 

receives about half of the royalties 

reported and paid for Federal leases in 

Wyoming, and shares in any reduction 

in those royalties, including reductions 

occasioned by an extraordinary 

processing allowance. Nonetheless, the 

comments submitted by the Governor of 

Wyoming and Wyoming’s Congressional 

delegation urge ONRR to adopt 

regulations restoring a lessee’s ability to 

apply for extraordinary processing 

allowances, and state that the positive 

overall 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. Further, in more 

than 30 years, ONRR has received fewer 

than 10 requests to approve 

extraordinary processing allowances 

(and approved only two), which 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4629 

indicates that such requests are very 

rare. 

Public Comment: One commenter 

stated that, if there is a potential danger 

to local communities if extraction of 

high sulfur gas streams goes wrong, the 

company should pay the taxpayers a fair 

share (and no less) for the resources. 

ONRR Response: As discussed above, 

allowing a lessee to deduct actual, 

reasonable post-production processing 

costs is part of ensuring a fair return for 

the right to produce Federal resources. 

And ‘‘if extraction of high sulfur gas 

streams goes wrong,’’ other laws 

potentially hold the responsible party 

liable for personal, property, and 

environmental damage. ONRR’s 

regulations governing the method of 

calculating the amount of a lessee’s 

royalty payment were never intended to 

compensate for accidental personal, 

property, or environmental damages 

should someone or something suffer 

injury or damage as a result of a failure 

associated with the processing of a 

natural resource. ONRR further 

addressed public comments regarding 

environmental concerns in the General 

Comments section in this rule’s 

introduction. 

ONRR appreciates the comments 

supporting, seeking the modification to, 

or opposing the proposed amendment to 

allow a lessee to apply to ONRR for 

approval to claim an extraordinary 

processing allowance. After careful 

consideration, and for the reasons 

explained in the introduction above, 

this final rule will adopt the proposed 

amendment to § 1206.159(c)(4). In the 

2020 Proposed Rule, this paragraph was 

designated as § 1206.159(c)(4). To 

account for other changes to § 1206.159, 

paragraph (c)(4) is redesignated as 

§ 1206.159(c)(5) in this final rule. 

D. The Default Provision for Federal Oil, 

Gas, and Coal and Indian Coal 

The 2016 Valuation Rule introduced a 

provision on how ONRR will exercise 

the Secretary’s authority to establish 

royalty value when typical valuation 

methods are unavailable, unreliable, or 

unworkable. This provision, which 

appears in several places in the 2016 

Valuation Rule, is generally referred to 

as ‘‘the default provision.’’ ONRR’s 

intent in 2016 was to increase clarity, 

consistency, and predictability on when 

and how ONRR would exercise the 

Secretary’s discretion to determine 

royalty value when other royalty 

valuation methods fail. 

The 2020 Proposed Rule sought to 

amend 30 CFR part 1206 to eliminate 

the default provision from four sections 

and a number of references thereto. The 

amendment, if adopted, would 

effectively revert ONRR’s practices to 

those in place prior to publication of the 

2016 Valuation Rule. ONRR premised 

the proposed change on E.O.s 13783 and 

13795 and the policies reflected in those 

directives, and on ONRR’s consideration 

of continuing concerns from regulated 

entities with respect to how ONRR 

would apply the default provision, as 

most recently expressed by industry 

members in the Petitioners’ Joint 

Opening Brief (ECF No. 89), filed 

December 4, 2020, in API v. U.S. Dept. 

of the Interior, et al, Case No. 19–cv– 

120–S, U.S. District Court for the 

District of Wyoming. 

In the 2016 Valuation Rule and 2020 

Proposed Rule, ONRR determined that 

inserting and subsequently removing 

the default provision will not affect 

royalty values because neither the 

default provision nor its absence 

changes ONRR’s goal, which is to 

determine the value of the produced 

commodity for royalty purposes based 

on the best or a reasonable measure of 

market value. Further, removing the 

default provision does not affect 

ONRR’s ability to establish a royalty 

value in those infrequent instances 

where a typical valuation method is 

unavailable, unreliable, or unworkable 

because the Secretary’s discretion to 

establish a royalty value does not derive 

from ONRR’s regulations. See, e.g., 17 

U.S.C. 1751 and BOEM OCS lease form, 

section 6(b)(‘‘The value of production 

for purposes of computing royalty shall 

be the reasonable value of the 

production as determined by the 

Lessor.’’). 

In this final rule, ONRR amends 30 

CFR part 1206 to eliminate the default 

provision found in §§ 1206.105, 

1206.144, 1206.254, and 1206.454, and 

a number of references thereto, 

effectively returning ONRR’s practices 

to those that were in place for decades 

prior to the adoption of the 2016 

Valuation Rule. 

Comments on the Proposed 

Amendments 

Public Comment: Several commenters 

supported the default provision’s 

elimination because the commenters 

opine that the default provision 

introduces ambiguity as to who within 

ONRR has the authority to invoke the 

default provision. There was also 

concern that the default provision 

would be applied inconsistently. 

Further, commenters expressed 

concerns about the lack of criteria for 

determining ‘‘reasonable’’ sales prices 

and transportation costs, which could 

theoretically result in a lessee not being 

allowed to value royalties based upon 

arm’s-length sales contracts or deduct 

all reasonable, actual transportation, 

and processing costs. These commenters 

assert that the default provision is 

overly broad and open-ended, allowing 

ONRR to determine the value of 

production or the amount of allowance 

in instances where a lessee cannot 

provide documentation requested by 

ONRR the lessee asserts it has no legal 

or practical ability to obtain. These 

commenters support regulations with 

more certainty in valuation, because 

they lead to less risk, efficiency in 

reporting and audits, and improved 

planning for ONRR and lessees. 

ONRR Response: Prior to the adoption 

of the 2016 Valuation Rule, ONRR 

successfully performed compliance 

activities and, when appropriate, 

exercised Secretarial discretion, to 

establish royalty values, even in the 

absence of an express default provision. 

Considering the recent direction given 

by E.O.s 13783 and 13795, which 

promote domestic energy production 

and reduce regulatory burden, together 

with the confusion around when and 

how the default provision would be 

applied, ONRR has reevaluated whether 

the default provision is necessary. 

ONRR intended the provision to be used 

in situations where determination of 

value was unclear, and not to determine 

the value of production in cases where 

reasonable, actual transportation and 

processing costs are well supported. 

ONRR agrees that the default provision 

is unnecessary. Further, the default 

provision invites litigation over what 

are the ‘‘lowest reasonable measures of 

market price,’’ ‘‘highest reasonable 

measure of transportation costs,’’ 

‘‘highest reasonable measure of 

processing costs,’’ and ‘‘highest 

reasonable measure of washing 

allowances.’’ See, e.g., 30 CFR 

1206.104(c)(2), 1206.110(f)(2), 

1206.143(c)(2), 1206.153(g)(2), 

1206.159(e)(2), 1206.253(c)(2) 

1206.260(g)(2), 1206.267(d)(2). Also, 

arguably, the default provision allows a 

lessee in certain circumstances to report 

and pay royalties based on sales prices 

up to ten percent less than the lowest 

reasonable measure of market price; 

transportation costs up to ten percent 

higher than the highest reasonable 

measure of transportation costs; 

processing costs up to ten percent 

higher than the highest reasonable 

measure of processing costs; and 

washing allowances up to ten percent 

higher than the highest reasonable 

measure of washing allowances. See, 

e.g., 30 CFR 1206.104(c)(2), 

1206.110(f)(2), 1206.143(c)(2), 

1206.153(g)(2), 1206.159(e)(2), 

1206.253(c)(2), 1206.260(g)(2), 

4630 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

1206.267(d)(2). The default provision 

does not best protect the United States 

against inadequate royalty payments 

and is being removed from ONRR 

regulations by this final rule. 

Public Comment: Some commenters 

expressed concern over reporting errors 

causing ONRR to ‘‘penalize’’ a lessee 

and impose an entirely different (and 

presumable higher) valuation for royalty 

purposes through the application of the 

default provision without first allowing 

the lessee to correct its reporting to 

conform to the applicable regulations. 

ONRR Response: Where royalty value 

cannot be determined under the 

regulations, such as instances of breach 

of a lessee’s duty to market, ONRR will 

use statutory authority to determine 

Federal oil and gas royalty value in 

accordance with the lease terms, 

statutes, and regulations in the same 

manner as ONRR did prior to adoption 

of the 2016 Valuation Rule. 

Public Comment: Many commenters 

expressed concerns over the ten percent 

variance, arguing that it does not take 

into account arm’s-length sales and 

transportation contracts, particularly 

where the lack of fully-developed 

transportation and processing 

infrastructure could vary by more than 

10 percent from ‘‘reasonable measures.’’ 

The commenters also stated that the ten 

percent test is too broadly written and 

could be triggered by transactions that 

have the same economic effect but are 

structured differently. 

ONRR Response: ONRR is to capture 

a reasonable measure of fair market 

value for production. See, e.g., 43 U.S.C. 

1344(a)(4). Fair market value is 

influenced by sales prices, 

transportation costs, processing costs, 

and the costs of placing production in 

marketable condition. The ten percent 

variance is problematic, but for reasons 

other than expressed in these public 

comments. The ten percent variance is 

from the lowest reasonable sales price 

and the highest reasonable 

transportation and processing costs. For 

this reason, the default provision is in 

conflict with ONRR’s mandate to 

capture full, reasonable fair market 

value, not up to ten percent less. 

Public Comment: Several commenters 

suggested that, if ONRR elects to retain 

the default provision, it should be 

narrowly tailored to address the most 

blatant of reporting discrepancies, and 

defined in such a way that a lessee is 

not left to guess if and when ONRR will 

decide to insert itself into regular 

business transactions and what the 

results of such intervention might be. 

One commenter further asserted that 

ONRR should indicate when its 

judgment will or will not be substituted, 

how such discretion would or would 

not be wielded, and what factors would 

or would not be used. The commenters 

added that ONRR should also clarify 

how the provision would establish 

pricing for misconduct, breach of duty 

to market, or instances where ONRR 

cannot verify value. 

ONRR Response: ONRR appreciates 

the suggestions to tailor and further 

define when and how it would use the 

default provision. However, ONRR 

believes that the default provision has 

created uncertainty and unintended 

consequences in the valuation of 

production, as discussed above. 

Therefore, this final rule eliminates the 

default provision. 

Public Comment: One commenter 

stated that ONRR should give proper 

notice to a payor so that additional 

information or justification as to the 

valuation could be provided first. The 

commenter further asserted that the 

default provision should not be 

triggered by simple or inadvertent 

reporting errors, nor by some arbitrary 

percentage below the lowest 

‘‘reasonable’’ measure of value in arm’slength situations, or above the highest 

‘‘reasonable’’ measure of transportation 

or processing cost as under the 2016 

Valuation Rule. 

ONRR Response: In this final rule, 

ONRR eliminates the default provision 

contained in the 2016 Valuation Rule 

because the default provision created 

uncertainty and a regulatory burden, as 

well as unintended consequences 

adverse to the lessor. The final rule 

reverts to historical practices under 

which MMS and ONRR successfully 

performed compliance activities. Where 

appropriate, ONRR will exercise 

Secretarial discretion to establish 

royalty values in the absence of the 

default provision. ONRR believes that it 

unintentionally increased uncertainty 

due to lessees’ perception that ONRR 

might apply the default provision in 

place of accurate lessee reporting, 

thereby creating a regulatory burden for 

lessees. 

Public Comment: One commenter 

suggested that a lessee should be 

allowed to fix a mis-reported value to 

conform to ONRR’s regulations rather 

than the agency unilaterally setting its 

preferred value. 

ONRR Response: In the future, ONRR 

may request more information and/or 

specific proposals regarding ways to 

address reporting errors. Lessees are 

currently required to correct any 

reporting errors within 30 days of the 

date the lessee learns of the error. See 

30 CFR 1210.30. 

Public Comment: A commenter 

suggested that because several phrases 

relating to the default provision were 

not addressed by the 2020 Proposed 

Rule that ONRR may still exercise 

seemingly unfettered discretion to 

review a lessee’s royalty valuation that 

is based on bona fide arm’s-length 

contract. This commenter requested that 

ONRR issue a separate rulemaking to 

target the remaining default provisions 

to meet the intent of the 2020 Proposed 

Rule. 

ONRR Response: ONRR appreciates 

the suggestions to address the other 

phrases that were not the subject of the 

2020 Proposed Rule. However, it is 

outside of the scope of this rulemaking. 

Public Comment: One commenter 

stated that ONRR did not provide a 

reasoned explanation for removing the 

default provision, and thus creates 

uncertainty surrounding the valuation 

of oil, gas, and coal. The commenter 

went on to say that removal of this 

provision will reintroduce uncertainty 

by leaving a lessee unsure when ONRR 

will exercise the Secretary’s discretion. 

The commenter also stated that ONRR 

fails to recognize the lessee’s right to 

appeal any order issued by or on behalf 

of the Secretary regarding royalty 

valuation, even though those appeals 

create an important check on the 

Secretary’s power. Further, this 

commenter argued that ONRR did not 

consider alternatives and chose to 

repeal the default provision without 

providing justification other than broad 

executive policies. Accordingly, the 

commenter concluded that removing the 

default provision is arbitrary and 

capricious. 

ONRR Response: ONRR disagrees 

with the suggestion that the default 

provision is necessary or that its 

removal will cause uncertainty. ONRR 

used its delegated Secretarial discretion, 

lease terms, statutes, and regulations to 

determine Federal oil and gas royalties 

prior to adoption of the 2016 Valuation 

Rule, and will continue to do so after 

the default provision’s removal from 

ONRR regulations. The default 

provision created uncertainty and 

unintended consequences as discussed 

above, and the regulations did not best 

define the situations when ONRR 

should apply a default provision. 

Public Comment: Another commenter 

stated that the default provision should 

be retained because its removal would 

undermine ONRR’s ability to ensure 

proper royalty collection. 

ONRR Response: ONRR disagrees that 

the default provision is necessary or that 

its removal will adversely affect its 

ability to ensure proper royalty 

collection. In fact, as discussed above, 

the default provision may have 

restricted ONRR’s ability to use 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4631 

Secretarial discretion when a lessee 

reports royalties significantly lower than 

the lowest reasonable value. 

ONRR appreciates the commenters 

supporting, seeking the modification to, 

and opposing the proposed amendment 

to §§ 1206.101, 1206.102, 1206.104, 

1206.105, 1206.110, 1206.141, 1206.142, 

1206.143, 1206.144, 1206.152, 1206.160, 

1206.252, 1206.253, 1206.254, 1206.256, 

1206.260, 1206.267, 1206.451, 1206.452, 

1206.453, 1206.454, 1206.460, 1206.461, 

1206.467, and 1206.468. For the reasons 

explained in the 2020 Proposed Rule 

and this final rule, this final rule will 

adopt the proposed amendments to 

§§ 1206.101, 1206.102, 1206.104, 

1206.105, 1206.110, 1206.141, 1206.142, 

1206.143, 1206.144, 1206.152, 1206.160, 

1206.252, 1206.253, 1206.254, 1206.256, 

1206.260, 1206.267, 1206.451, 1206.452, 

1206.453, 1206.454, 1206.460, 1206.461, 

1206.467, and 1206.468 in full. 

E. ‘‘Misconduct’’ Definition for Federal 

Oil, Gas, and Coal and Indian Coal 

In the 2016 Valuation Rule, ONRR 

added a definition of the term 

‘‘misconduct’’ under § 1206.20 to mean: 

‘‘any failure to perform a duty owed to 

the United States under a statute, 

regulation, or lease, or unlawful or 

improper behavior, regardless of the 

mental state of the lessee or any 

individual employed by or associated 

with the lessee.’’ In the preamble to the 

2016 Valuation Rule, ONRR explained 

that it added the misconduct definition 

in conjunction with the adoption of the 

‘‘default’’ provision. ‘‘This new 

definition will apply to—and in 

conjunction with the—default 

provision. Misconduct, in this subpart, 

is different than—and in addition to— 

any violations subject to civil penalties 

under . . . FOGRMA . . . . Behavior 

that constitutes misconduct under part 

1206 does not need to be willful, 

knowing, voluntary, or intentional. This 

is a valuation mechanism, not an 

enforcement tool.’’ 

ONRR is eliminating the default 

provision from its regulations in this 

final rule. Accordingly, the definition of 

‘‘misconduct’’ added to ONRR 

regulations in conjunction with and for 

the operation of the default provision is 

also being eliminated. 

Comments on the Proposed Amendment 

Public Comment: Some commenters 

stated that the 2016 Valuation Rule 

generated uncertainty for royalty 

reporters by creating a broad definition 

of ‘‘misconduct.’’ The commenters 

argued this definition could be 

misapplied, leading to the imposition of 

civil penalties under the 2016 Civil 

Penalty Rule. The commenters 

explained that they interpreted the 2016 

Valuation Rule’s definition of 

‘‘misconduct’’ to allow ONRR to 

penalize a lessee under the ‘‘default 

provision’’ for reporting an incorrect 

product code, sales type, or other nonvalue-based field on a royalty report 

(form ONRR–2014), without an 

opportunity to correct the error. 

Additionally, penalizing a lessee for 

non-value-based errors is not 

reasonable, the commenters said, 

because there are many fields on form 

ONRR–2014 that do not affect ONRR’s 

ability to ensure that it has collected 

every dollar due. Thus, these 

commenters support the 2020 Proposed 

Valuation Rule’s elimination of the 

definition of ‘‘misconduct.’’ 

One commenter stated that the 

definition of misconduct was expansive 

enough to capture even inadvertent 

paperwork errors. Furthermore, the 

commenter stated that the 2016 

definition of misconduct duplicates 

existing regulations to the extent that a 

lessee is required to correct reporting 

errors under § 1206.30. 

ONRR Response: The definition of 

‘‘misconduct’’ in 30 CFR 1206.20 is no 

longer needed because the default 

provision is being eliminated by this 

final rule. 

Public Comment: Some commenters 

suggested that ONRR amend the 

definition of ‘‘misconduct’’ in § 1206.20 

by including the words ‘‘intentional’’ or 

‘‘knowing or willful’’ before 

‘‘misconduct’’ where it appears in 30 

CFR part 1206. Alternatively, the 

commenters suggested, ONRR could 

insert a provision such as ‘‘ONRR will 

not allege misconduct absent some 

intent by the lessee to lower its royalty 

payments to the government beyond 

what is reasonable’’ to ensure that, for 

example, the failure of the lessee to 

conform to formal or informal agency 

guidance does not establish misconduct, 

while good faith efforts to comply 

constitutes mitigating circumstances 

and should not result in the issuance of 

a penalty. Another commenter said that 

intentional conduct aimed at reducing 

royalties owed should be an aggravating 

factor, while innocent reporting 

mistakes, a favorable compliance record, 

and adherence to ONRR guidance 

should be mitigating factors. 

ONRR Response: ONRR defined 

‘‘misconduct’’ in the 2016 Valuation 

Rule to clarify when ONRR would 

exercise the Secretary’s discretion to 

determine value of production under 

the default provision. Because the 

default provision is being eliminated by 

this final rule, the related definition of 

‘‘misconduct’’ is also being eliminated, 

and thus, it is unnecessary to amend, in 

any manner, the definition of 

misconduct. 

Public Comment: One commenter 

stated that ONRR did not provide a 

reasoned or substantive explanation for 

proposing in the 2020 Proposed Rule to 

remove the misconduct definition. The 

commenter asserted that ONRR’s 

proposal unnecessarily reintroduces 

uncertainty to the application of the 

valuation regulations. Additionally, the 

commenter opined that ONRR directly 

contradicted its earlier position on an 

issue without properly justifying its 

decision. This commenter suggested 

that before removing the definition, 

ONRR must first provide a reasoned 

explanation for the change. 

Accordingly, the commenter stated that 

removing the definition for the term 

‘‘misconduct’’ is arbitrary and 

capricious. 

ONRR Response: This final rule 

provides ONRR’s reasoned explanation 

to remove the definition of 

‘‘misconduct.’’ In summary, this rule 

removes the definition because: (1) 

ONRR originally added the definition in 

conjunction with, and for the operation 

of, the default provision that this rule 

also removes; (2) in light of this rule’s 

objectives, ONRR gives greater weight to 

comments that the definition increased 

uncertainty and undue burdens in the 

regulated community; and (3) ONRR 

maintains and has not eroded its ability 

to ensure and compel accurate reporting 

including, for example, the requirement 

under § 1210.30 for a lessee to ‘‘submit 

accurate, complete, and timely 

information,’’ regardless of whether 

those errors were caused by misconduct. 

ONRR appreciates the comments 

supporting, seeking the modification to, 

and opposing the proposed amendment. 

After careful consideration, and for the 

reasons explained above, ONRR is 

adopting the proposed amendment to 

remove the definition of ‘‘misconduct’’ 

in § 1206.20 as part of this final rule. 

F. Contract Signature Requirement for 

Federal Oil, Gas, and Coal and Indian 

Coal 

The 2016 Valuation Rule required a 

lessee or a lessee’s ‘‘affiliate [to] make 

all contracts, contract revisions, or 

amendments in writing, and all parties 

to the contract must sign the contract, 

contract revisions, or amendments’’ for 

all valuation methods, including gross 

proceeds and index-based options, to 

verify the correctness of royalty reports 

and payments. See §§ 1206.104(g)(1); 

1206.143(g)(1); 1206.253(g)(1); and 

1206.453(g)(1) (2016 Valuation Rule). If 

a written contract was not signed by all 

parties to the contract, the 2016 

Valuation Rule directs that ONRR use 

4632 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

the default provision to determine 

royalty value. 

In the 2020 Proposed Rule, ONRR 

seeks to eliminate the requirement that 

a lessee create and maintain contracts 

signed by all parties where the lessee 

would not do so in the normal course 

of business, except as required by 30 

CFR 1207.5, which states that a lessee 

must place in written form and retain 

any oral sales arrangement negotiated by 

the lessee. The proposed amendment 

also seeks to create greater consistency 

with ONRR’s definition of contract, 

which includes oral contracts and 

written contracts that are not signed by 

all parties. See 30 CFR 1206.20. 

Even with the amendments adopted 

in this final rule, ONRR will still be able 

to evaluate a lessee’s course of 

performance under all contracts, oral 

and written, signed and unsigned, 

consistent with ONRR’s historical 

agency practice. ONRR has long been 

able to request copies of a lessee’s sales 

contracts and all agreements, other 

contracts, and other documents relevant 

to the valuation of production, 

including any written or electronic 

evidence of transportation contracts, 

processing contracts, and contracts for 

services to place production in 

marketable condition. See 30 CFR 

1207.5 (‘‘Copies of all sales contracts 

. . . and copies of all agreements, other 

contracts, or other documents which are 

relevant to the valuation of production 

are to be maintained by the lessee and 

made available upon request . . . to 

. . . ONRR . . . .’’). Given this broad, 

long-standing authority to request all 

lessee’s records that bear on royalty 

value, in the 2020 Proposed Rule ONRR 

sought public comment on whether the 

new requirements imposed by the 2016 

Valuation Rule should be retained. 

ONRR recognizes that contracts may 

be valid and enforceable, as a matter of 

law, despite the absence of writing or 

signatures. See the definition of 

‘‘contract’’ in 30 CFR 1206.20. In this 

final rule, ONRR seeks to resolve the 

ambiguity that exists between its 

definition of contract—which 

recognizes the validity of oral 

agreements and of written agreements 

that have not been signed by all 

parties—and the 2016 Valuation Rule’s 

imposition of a requirement for every 

contract to be in writing and signed by 

all parties, despite a lessee’s normal 

business practices to the contrary. 

ONRR has determined that the 2016 

Valuation Rule’s new requirement does 

not align with contract law, that 

industry operates without signed 

documents as a matter of course without 

issue, and that ONRR can use other 

methods to determine the terms of an 

oral contract or a written contract that 

is not signed by all parties. 

Comments on the Proposed Amendment 

Public Comment: Several industry 

commenters supported removal of the 

contract signature requirement, stating 

that real world practices do not always 

require written contracts and that there 

is no need for signatures to affirm a 

contractual agreement. Additionally, 

commenters noted that the 2016 

Valuation Rule inadvertently 

contradicted the definition of ‘‘contract’’ 

in the regulation itself, which, at 

§ 1206.20, defines ‘‘contract’’ as ‘‘any 

oral or written agreement . . . that is 

enforceable by law,’’ and which does 

not require the contract to be signed by 

the parties. Commenters also noted that 

eliminating the written contract 

requirement would not diminish a 

lessee’s obligation to justify its Federal 

or Indian oil or gas valuation to ONRR, 

and that the mere absence of a written 

contract is not a valid reason for ONRR 

to interject itself and reestablish royalty 

value by using the default provision. 

ONRR Response: ONRR agrees that 

the 2016 Valuation Rule overlooked the 

fact that oral agreements and unsigned 

written agreements may be binding and 

legally enforceable, eliminating the need 

for the agency to implement new 

requirements. Additionally, the 2016 

Valuation Rule’s requirement of contract 

signatures is inconsistent with the 

definition of contract found in 30 CFR 

1206.20. This amendment will more 

readily synchronize ONRR’s regulations 

with the long-standing definition of 

‘‘contract’’ that is found in § 1206.20, 

which acknowledges that a contract may 

be oral or in writing and does not have 

to be signed. ONRR also acknowledges 

that oral contracts are legally 

enforceable, making the signature 

requirement unworkable and potentially 

burdensome upon lessees by creating a 

heightened requirement that may not be 

part of standard business practice. 

ONRR also agrees that eliminating the 

signed contract requirement does not 

diminish the lessee’s obligation to prove 

its contract terms and justify its 

valuation methods to the agency. Longstanding ONRR regulations allow ONRR 

to request a lessee provide all 

documents relevant to the valuation of 

production during the course of its 

compliance and audit efforts. ONRR 

believes this provides it with an 

appropriate mechanism by which to 

verify appropriate valuation. 

Public Comment: One industry 

commenter stated that many current 

agreements among producers and other 

parties active in the market exist 

electronically or via email exchanges, 

renew automatically, or include terms 

that require something not in written 

form. Further, the commenter indicated 

that the signed written contract 

requirement in 2016 Valuation Rule is 

stricter than what is required to 

establish a contract under general 

commercial law. The commenter 

provided an example, stating that a 

course of dealing could not be used to 

satisfy ONRR’s signed contract 

requirement, but could be sufficient to 

establish a binding arrangement in a 

court of law, in the event of a contract 

dispute. This commenter also believes 

that ONRR has decades of experience 

evaluating contracts prior to the 2016 

Valuation Rule, and this broad authority 

and experience should be adequate to 

carry the agency forward. 

ONRR Response: ONRR agrees that 

the 2016 Valuation Rule overlooked the 

fact that many agreements renew 

automatically and include terms that 

require acknowledgement in some 

manner other than a written agreement 

signed by all parties. This amendment 

will eliminate inconsistency between 

this stated industry practice and 

ONRR’s regulatory requirements that 

rely on accurate recordkeeping and how 

those records are to be maintained by 

lessees over time. ONRR also recognizes 

the 2016 Valuation Rule created a more 

stringent standard than what most 

lessees are subject to as part of their 

normal commercial transactions, and by 

adopting the amendment proposed in 

the 2020 Valuation Rule, ONRR hopes 

to more readily align with standard 

commercial practices. ONRR also agrees 

that prior agency practice and expertise 

can inform its audit and compliance 

activities, and that eliminating the 

signed contract provision will not 

negatively impact these efforts. These 

longstanding agency practices include 

ONRR requests to lessees for documents 

bearing on the valuation of production, 

including any written sales, 

transportation, or processing 

agreements, any documentation of an 

oral sales agreement, and any 

documentation that reflects the 

existence of, or pertaining to, an oral or 

written sales, transportation, or 

processing agreement, or agreement for 

services to place production into 

marketable condition. 

Public Comment: One industry 

commenter stated that ONRR’s assertion 

that the contract signature requirement 

is defective is a premature conclusion 

for the agency to make. The commenter 

asserted that ONRR should amend the 

definition so that it is consistent 

throughout all product valuation 

regulations instead of repealing the 

written contract requirement altogether. 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4633 

Alternatively, the commenter stated that 

ONRR should broaden the definition of 

contract to require that all contracts be 

in writing. The commenter also 

expressed concern that ONRR is simply 

returning to an old regimen that, by 

ONRR’s own admission in the preamble 

to the 2016 Valuation Rule, is outdated 

and flawed. 

ONRR Response: The fact that oral 

and unsigned, written agreements may 

be legally binding and enforceable 

between the parties impacted ONRR’s 

decision to revisit this requirement in 

the 2020 Proposed Rule. ONRR is 

adopting the proposed amendment for 

the reasons stated in this final rule. 

Public Comment: Several publicinterest commenters stated that this 

proposed amendment directly 

contradicts the reason ONRR provided 

in the 2016 Valuation Rule for the 

inclusion of contract signatures. These 

commenters also believe that ONRR has 

not properly justified this amendment, 

and that verification activities would 

suffer without written contracts. 

ONRR Response: In terms of ONRR’s 

verification activities, ONRR believes 

that its compliance and audit processes 

will not be negatively impacted by 

eliminating the 2016 Valuation Rule’s 

requirement for written contracts signed 

by all parties. ONRR has several 

methods by which it can confirm 

transaction-based information from a 

lessee without relying solely on written 

contracts signed by all parties. This 

includes ONRR’s ongoing ability to 

request a full array of documents—both 

signed and unsigned, hard-copy and 

electronic—along with its continuing 

use of Generally Accepted Government 

Auditing Standards (‘‘GAGAS’’ or 

‘‘Yellow Book Standards’’) to review and 

audit transactions based on information 

received from a lessee. In using these 

different investigatory methods, ONRR 

ensures compliance and verification 

activities that meet or exceed its 

regulatory mandate. ONRR is adopting 

the proposed amendment for the 

reasons stated in this final rule. 

ONRR is eliminating the requirement 

that a lessee create and maintain 

contracts signed by all parties when the 

lessee would not otherwise do so in the 

normal course of business. Affected 

sections are §§ 1206.104(g)(1), 

1206.143(g)(1), 1206.253(g)(1), and 

1206.453(g)(1). 

G. Citation to Legal Precedent as Part of 

a Valuation Determination Request 

The 2016 Valuation Rule introduced a 

requirement that a lessee provide, along 

with the lessee’s valuation request, any 

citations to legal precedent, including 

adverse precedent, that it believes are 

persuasive as part of its analysis of the 

issues. These requirements are set forth 

in §§ 1206.108(a)(5), 1206.148(a)(5), 

1206.258(a)(5), and 1206.458(a)(5). 

In the 2020 Proposed Rule, ONRR 

proposes to eliminate this requirement. 

More specifically, the 2020 Proposed 

Rule proposed to remove the phrase 

‘‘including citations to all relevant 

precedents (including adverse 

precedents)’’ from §§ 1206.108(a)(5), 

1206.148(a)(5), 1206.258(a)(5), and 

1206.458(a)(5). 

ONRR is familiar with, and commonly 

a party to, matters that generate 

precedent for Federal oil and gas, 

Federal coal, and Indian coal royalty 

valuation issues. Although citations 

might expedite the processing time for 

a lessee’s request for a valuation 

determination, it is not necessary to 

require a lessee to provide citations to 

precedent. Further, ONRR believes that 

it would be unproductive to attempt to 

enforce or litigate such a requirement, 

especially because a failure to include a 

citation to precedent may not, on its 

own, provide a sufficient reason to deny 

an otherwise valid request for a 

valuation determination. Lessees may 

always cite precedent when they wish 

to do so in submitting a valuation 

request, but it is not necessary to require 

lessees to do this. 

Comments on the Proposed Amendment 

Public Comment: One industry 

commenter found the requirement to 

provide legal citations to be problematic 

because the requirement creates an 

undue burden on lessees which 

discourages lessees from seeking formal 

guidance from ONRR. The commenter 

explained that requiring legal citations 

amounts to providing a legal brief to 

ONRR in support of a lessee’s request 

for a valuation determination, which is 

unduly burdensome and out of reach for 

many smaller operators with no legal 

support staff. 

ONRR Response: ONRR agrees with 

this commenter and believes that the 

requirement to provide legal citations 

creates an unnecessary burden on 

lessees. ONRR recognizes that many 

lessees do not employ in-house legal 

counsel or have outside legal counsel on 

retainer who could assist with this 

degree of detailed legal research. 

Because of the significant legal costs 

and operational challenges that result 

from this requirement of the 2016 

Valuation Rule, ONRR agrees that 

eliminating this provision removes a 

significant challenge for lessees who 

seek more formal guidance. 

Public Comment: One industry 

commenter noted that the IBLA 

oftentimes issues valuation 

determinations via Orders, which are 

unpublished and difficult to find using 

traditional electronic search tools. This 

creates an issue for lessees because 

ONRR may be the only entity privy to 

this information. Further, the 

commenter stated that it is ONRR’s 

responsibility to ensure that the agency 

administers its regulations in a 

consistent manner, not industry’s. 

ONRR Response: ONRR recognizes 

this limitation and agrees that the best 

way to eliminate the issue is to remove 

the requirement to cite to legal 

precedent. The IBLA’s issuance of 

unpublished Orders and directives that 

cannot be accessed by the general public 

creates an unanticipated burden on 

lessees that this proposed amendment 

seeks to rectify. Further, ONRR 

conducts its own extensive legal 

research when evaluating the issues in 

a lessee’s request for a valuation 

determination. Because ONRR already 

engages in this level of legal analysis, it 

is unnecessary for a lessee to duplicate 

efforts that the agency is already 

conducting as a matter of course. 

Public Comment: Several industry 

commenters were concerned that ONRR 

will require excessive data and legal 

analysis in order for a lessee to receive 

valuation guidance or a determination. 

ONRR Response: Although citations 

might expedite the processing time for 

a lessee’s request, ONRR does not 

believe that it is necessary to require a 

lessee to provide citations to legal 

precedent or regulatory authority. This 

is particularly true for novel issues for 

which there may be no legal reference 

to cite. Therefore, ONRR is removing 

this requirement. 

Public Comment: One industry 

commenter expressed concern that the 

lack of sufficient legal citation would 

give ONRR a reason to deny a request 

for a valuation determination. 

ONRR Response: A lessee always has 

the option to cite to legal precedent in 

requesting a valuation determination. 

Even with the amendment adopted in 

this final rule, lessees may choose to 

include legal precedent to support or 

substantiate its arguments; but such 

citations are by no means a requisite 

step in the valuation determination or 

valuation guidance process. 

Public Comment: One industry 

commenter stated that many mid-sized 

and smaller independent ‘‘Mom and 

Pop’’ oil and gas oil companies do not 

have access to in-house counsel or 

general counsel to help them research 

case law and legal citations in support 

of their valuation determination. 

ONRR Response: ONRR addressed a 

substantially similar comment, above, 

4634 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

and refers the commenter to the 

responses in the preceding section. 

Public Comment: A public-interest 

commenter stated that the burden 

should remain on the lessee to provide 

ONRR with citation to legal precedent 

that bolster or support the lessee’s 

request for a valuation determination. 

ONRR Response: Although citations 

and reference to legal authority might 

expedite the processing time for a 

lessee’s request, ONRR does not believe 

that it is necessary to require lessees to 

provide citations for this purpose. 

Further, ONRR believes that 

maintaining this requirement may 

disincentivize lessees from seeking a 

valuation determination or valuation 

guidance. ONRR’s position is that all 

requests for guidance and valuation 

determinations are welcome, and ONRR 

should not create a system that 

discourages lessees from contacting 

ONRR for support or assistance. 

Public Comment: A commenter 

indicated that citation to case law and 

other legal precedent may be a good 

barometer for ONRR to use to decide 

whether the lessee’s request has 

sufficient merit, especially since a 

valuation determination may remain in 

effect for decades or longer. 

ONRR Response: ONRR disagrees 

with this commenter. Although legal 

citations may provide support for a 

valuation determination, ONRR must 

still undertake comprehensive factual 

and legal research, and a lessee’s 

citation to precedent will not relieve 

ONRR of the obligation to do so for 

every valuation determination. 

Maintaining the regulation that requires 

citation to legal precedent could 

inadvertently prevent companies from 

seeking a valuation determination. 

ONRR does not want to place 

unnecessary burdens on lessees and 

holds that the amendment eliminating 

the requirement to cite to legal 

precedent should be adopted. 

For the reasons discussed in the 2020 

Proposed Rule and this final rule, ONRR 

is removing the requirements under 

§§ 1206.108(a)(5), 1206.148(a)(5), 

1206.258(a)(5), and 1206.458(a)(5) for a 

lessee to include citations to legal 

precedent when requesting a valuation 

determination. 

H. Coal Valued for Royalty Purposes 

Based on an Electricity Sale 

The 2016 Valuation Rule addressed 

the valuation of coal at 30 CFR 1206.252 

(Federal coal) and 30 CFR 1206.452 

(Indian coal). In general and consistent 

with ONRR’s view that the best 

indicator of value is the gross proceeds 

a lessee receives under an arm’s-length 

contract, these sections, with certain 

exceptions discussed below, value coal 

based on the gross proceeds accruing 

under the first arm’s-length contract, 

less certain allowances. 

In a situation where a lessee or its 

affiliate produces and then uses coal in 

a power plant owned by the lessee or its 

affiliate to generate electricity that is 

sold by the lessee or its affiliate to a 

variety of customers, no coal sales 

contract may exist and no arm’s-length 

sale of the coal would have taken place 

prior to the sale of the electricity. In a 

situation where the electricity is sold 

under an arm’s-length contract, 

§§ 1206.252(b) and 1206.452(b) of the 

2016 Valuation Rule directs a lessee to 

value the coal based on the gross 

proceeds received for the electricity sale 

less certain allowances. If the electricity 

is sold under a non-arm’s-length 

contract, these sections require the 

lessee to propose to ONRR a method to 

value the coal. ONRR may accept the 

lessee’s proposed method or determine 

that the lessee needs to adjust its royalty 

reporting and payment because ONRR’s 

determination resulted in a different 

value. Further, §§ 1206.252(c)(2) and 

1206.452(c)(2) extend these valuation 

requirements to a lessee who sells coal 

to another member of a coal cooperative 

for use in the generation and sale of 

electricity. 

As previously discussed, the United 

States District Court for the District of 

Wyoming entered a preliminary 

injunction which enjoined the 

implementation of the portions of the 

2016 Valuation Rule applicable to 

Federal and Indian coal. The District 

Court stated that electricity sales may 

not be the best or a true indicator of the 

value of the coal produced from Federal 

or Indian properties. See Cloud Peak, 

415 F. Supp. 3d at 1052–53. 

Specifically, the District Court stated, 

inter alia, that ‘‘an electricity utility’s 

power supply portfolio typically 

includes a range of options, from 

nuclear to coal to natural gas to hydro, 

wind, and solar.’’ Id. at 1051 (citation 

omitted). ‘‘Thus, the sales price of the 

electricity is comprised of much more 

than just the cost of coal, and that’s 

ignoring the rabbit hole that is 

electricity sales regulation by both the 

federal and state governments.’’ Id. 

After careful consideration, of the 

pleadings filed and arguments raised in 

the United States District Court for the 

District of Wyoming relating to the coal 

cooperative definition and the 

electricity netback method, and the 

District Court’s rationale underlying the 

preliminary injunction, together with 

the public comments discussed below, 

ONRR concludes that valuing coal on 

the first arm’s-length sale of electricity 

is unworkable and inadvisable. Many 

resources contribute to the generation of 

the electricity. Calculations to 

determine netback rely on the 

availability of information on the 

amount and type of fuels used to 

generate a kilowatt hour of electricity, 

detailed data on the capital costs of the 

plant to include the direct costs of all 

plant, materials, equipment and 

buildings, fixed and variable operating 

costs influenced by the age, efficiency, 

and limitations of all plant equipment 

and including voluntarily-supplied 

labor costs attributable to keeping the 

plant in operation, as well as 

consideration of market dynamics such 

as system load factors and peak-shaving 

capacity. ONRR lacks authority to 

compel a power plant to provide these 

data sources, and, even with the data, it 

is overly burdensome, exceedingly 

complex, and too difficult to accurately 

and meaningfully develop models to 

simulate individual power plant 

operations effectively to isolate the 

contribution of a single non-arm’slength coal source to the value of the 

electricity, let alone assume that it is an 

accurate proxy for the value of coal 

determined based on arm’s-length sales. 

ONRR is removing this unworkable and 

unduly burdensome requirement from 

its valuation regulations. 

Thus, in the 2020 Proposed Rule, 

ONRR proposed to amend 

§§ 1206.252(b) and 1206.452(b) to 

remove coal valuation based on arm’slength electricity sales. See 85 FR 62055 

and 62061. With removal, a lessee will 

be required to propose a method to 

value all coal that it or its affiliate uses 

for the generation and sale of electricity, 

regardless of whether the electricity is 

sold under in an arm’s-length or a nonarm’s-length contract. 

Comments on the Proposed Amendment 

Public Comment: Some industry 

commenters supported the removal of 

provisions that required the valuation of 

certain coal based on the sale of 

electricity. The commenters pointed out 

that it would be impossible to derive a 

meaningful value for coal from the value 

of electricity. One commenter argued 

that ONRR was not upholding its 

responsibility to obtain a fair market 

value for Federal coal since it did not 

provide a method to value coal never 

sold at arm’s-length. Further, these 

commenters focused on the reduced 

complexity of valuation computations 

and reduced administrative burdens 

that would be recognized by removing 

this provision. 

ONRR Response: ONRR agrees that 

valuing coal based on the sales price of 

electricity would result in an overly 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4635 

burdensome series of calculations 

resulting in a value that would be open 

to challenge and would be overly 

burdensome for ONRR to perform 

compliance activities and verify 

accurate reporting and payments. Even 

if ONRR completed such compliance 

activities and issued an order to the 

lessee, these audits would likely result 

in the issuance of orders that would be 

contested by the lessee and, potentially, 

modified or overturned by the IBLA or 

a reviewing court after protracted 

litigation. ONRR agrees that there is no 

universal solution or method that can be 

applied to value all coal used to 

produce electricity. ONRR further agrees 

that it is reasonable and proper for the 

lessee to identify, in the first instance, 

the situation-specific circumstances that 

could impact the appropriate method to 

values royalties. Fortunately, these 

situations are not common, resulting in 

only a handful or fewer cases that ONRR 

will need to review and approve. Even 

after several decades of experience, 

ONRR has not found a better solution 

for instances when coal is converted to 

another commodity without sales. The 

valuation solutions in these cases must 

take into account the lessees’ rights 

under the lease agreements, the MLA, 

and court-established precedents in 

order to establish a reasonable method 

to value this coal. ONRR will work to 

arrive at a just valuation method for 

lessees and the lessor where these nosale situations exist under § 1206.252(b). 

Public Comment: Other commenters 

opposing this change argued that 

generated electricity is a more accurate 

indicator of coal’s value than any 

method allowed under § 1206.252. 

Additionally, some of these commenters 

advocated that coal should be valued 

further downstream including, in some 

cases, the last arm’s-length electricity 

sale. 

ONRR Response: As stated above, 

valuing coal based on the first arm’slength sale of electricity is not a more 

accurate indicator of the value of coal in 

the limited circumstances affected by 

this rule change. Instead, it is a longstanding principle that royalty valuation 

of production from Federal and Indian 

leases typically occurs at or near the 

lease. In addition, ONRR has never 

looked beyond the first arm’s-length sale 

to the last arm’s-length sale. Most coal 

produced from Federal leases is sold at 

arm’s-length at or near the mine 

loadout, where mined coal is loaded for 

shipment to the buyer. Where a lessee 

moves its production away from the 

lease prior to this first sale (where 

ownership of the coal passes from 

producer to buyer), an allowance for 

transportation may be deducted from 

the royalty value. If the lessee sells or 

transfers the coal to an affiliate, the 

point of sale is where the first arm’slength sale of the coal by the affiliate 

occurs. In cases where no coal sale 

occurs prior to the generation of 

electricity, the lessee is required to 

submit a proposed valuation method to 

ONRR. In turn, ONRR will review and 

either approve the lessee’s method or 

ONRR will construct a reasonable value 

using the best information available 

under § 1206.252(b). 

Public Comment: Several industry 

commenters argued that ONRR is acting 

arbitrarily and capriciously when it 

allows lessees the opportunity to 

propose their own valuation method. 

ONRR Response: Over time, ONRR 

has found that the information that 

lessees provide when requesting a 

valuation determination has been 

sufficient to establish a value for coal 

that results in a fair royalty value. The 

proposed amendments will ensure that 

coal used by the lessee or its affiliate in 

a power plant for the generation and 

sale of electricity is fairly valued by 

requiring (1) the lessee to propose to 

ONRR a method that provides a proxy 

for what would be the first arm’s-length 

sale of the coal and (2) to adjust its 

royalty reporting and payment if ONRR 

determines that the proposed method 

does not fairly reflect the coal’s value. 

Public Comment: Two commenters 

offered suggestions as to how to value 

non-arm’s-length coal sales. The 

commenters suggested that ONRR go 

back to the coal valuation regulations in 

effect prior to the 2016 Valuation Rule, 

which used a series of benchmarks to 

value coal sold in non-arm’s-length 

transactions. They also suggested that 

the first benchmark be changed so that 

a lessee could use their own arm’slength sales contracts to establish a 

range to compare their non-arm’s-length 

sales contracts when determining the 

appropriateness of the non-arm’s-length 

sales price. The commenters also 

suggested that ONRR use a published 

index price to establish a value for coal 

sold non-arm’s-length. 

ONRR Response: Typically, the best 

indicator of value is the gross proceeds 

received under an arm’s-length contract 

between independent entities who are 

not affiliates and who have opposing 

economic interests regarding that 

contract. Also, typically the best 

indicator of value under a non-arm’slength sale is the gross proceeds 

accruing to the lessee or its affiliate 

under the first arm’s-length sale, less 

applicable allowances. 

ONRR is not currently aware of any 

published index prices for coal that 

covers a wide array of coal production, 

which indices are both transparent and 

widely traded to yield a reasonable 

value that would represent the true 

market value of coal. 

Public Comment: One commenter also 

suggested that ONRR should consider 

adopting an objectively-determinable 

backstop similar to the major-portion 

concept applicable to valuing oil and 

gas produced from Indian leases. Under 

the major portion process, lessees 

initially pay royalty based on their 

application of the valuation regulations 

(including using benchmarks for certain 

non-arm’s-length transactions). After 

ONRR collects all the sales data in 

particular areas from lessees’ royalty 

reports, ONRR calculates and publishes 

a major-portion price. Any lessee that 

initially paid royalty on a value less 

than the major-portion price must rereport and pay any differential. 

ONRR Response: The proposal to 

construct a major portion comparison 

for coal is not something ONRR is 

prepared to address in this rulemaking. 

ONRR may consider this idea in future 

rulemaking efforts. ONRR applies majorportion pricing based on Secretarial 

discretion. Currently, ONRR only 

applies major portion to certain Indian 

oil and gas leases. 

Public Comment: One commenter 

suggested that ONRR should not 

establish a floor price for coal. The 

commenter argued that lessees should 

be able to sell their coal at below-market 

prices in order to continue operations. 

They also argued that it is inconsistent 

and unreasonable for ONRR to chase the 

actual arm’s-length sale price of coal 

while also suggesting that a floor value 

be established when it is to ONRR’s 

benefit. 

ONRR Response: To be clear, ONRR 

does not set prices for commodities. 

Rather, ONRR ensures royalties are 

reported and paid based on values 

typically best reflected in the price 

received by the lessee in an arm’s-length 

sale of the same or similar commodity. 

ONRR’s regulations require a lessee to 

market coal for the mutual benefit of the 

lessee and the lessor. The regulations 

further provide that the best indicator of 

value is typically the gross proceeds 

received under an arm’s-length contract 

between independent entities that are 

not affiliates and have opposing 

economic interests. Any uplift in gross 

proceeds, an increase in the contract 

sales price, an affiliate of the lessee 

realizes in an arm’s-length sale of the 

same or a similar commodity after 

buying coal non-arm’s-length from the 

lessee should be royalty bearing. Sales 

below market prices ‘‘in order to 

continue operations’’ do not reflect the 

value of the resource but rather 

4636 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

operating conditions experienced by the 

lessee. 

Public Comment: One commenter 

stated that the economic impact of 

removing the electricity netback method 

from the rule for Federal and Indian 

coal would be impossible to measure. 

The commenter also stated that using 

the first arm’s-length sale of coal to 

value coal sold non-arm’s-length for 

Indian leases should have no economic 

impact. 

ONRR Response: ONRR has 

estimated, in past rulemakings, that the 

implementation and now removal of the 

electricity netback method will have no 

impact on royalties. As discussed 

below, ONRR believes, but has not 

estimated, that removing the electricity 

netback method will reduce 

administrative burden for both the 

lessee and ONRR. 

ONRR appreciates comments 

supporting, seeking modification to, and 

opposing the proposed amendment. 

Based on the reasons given in the 2020 

Proposed Rule (see 85 FR 62061) where 

ONRR stated that the valuation method 

was burdensome and controversial, the 

pleadings filed and arguments raised in 

the United States District Court for the 

District of Wyoming, the District Court’s 

rationale for the preliminary injunction, 

and the public comments received, 

ONRR is adopting the amendment as 

proposed. 

I. ‘‘Coal Cooperative’’ Definition 

The 2016 Valuation Rule amended 

ONRR’s regulations to add a definition 

of ‘‘coal cooperative,’’ at 30 CFR 

1206.20, to mean ‘‘an entity organized to 

provide coal or coal-related services to 

the entity’s members (who may or may 

not also be owners of the entity), 

partners, and others. The entity may 

operate as a coal lessee, operator, payor, 

logistics provider, or electricity 

generator, or any of their affiliates, and 

may be organized to be non-profit or forprofit.’’ See also 81 FR 43369. 

The 2016 Valuation Rule also added 

§§ 1206.252(c)(1) (Federal coal) and 

1206.452(c)(1) (Indian coal). Those 

sections require a lessee to value coal 

under §§ 1206.252(a) and 1206.452(a), 

respectively, if the lessee sells the coal 

to another member of a coal cooperative 

and that member, in turn, sells the coal 

under an arm’s-length contract. Sections 

1206.252(a) and 1206.452(a) provide 

that the value of coal is the gross 

proceeds accruing to the lessee or its 

affiliate under the first arm’s-length 

contract, less allowances. 

The 2016 Valuation Rule also added 

§§ 1206.252(c)(2) and 1206.452(c)(2), 

which address the valuation of coal in 

the situation where a lessee sells coal to 

another member of a coal cooperative 

that uses the coal to generate and sell 

electricity. The 2016 Valuation Rule 

also explained that, principally, coal 

cooperatives are formed because of 

some degree of mutual economic or 

other business interest. See 81 FR 

43338, 43354. Thus, transactions 

between members of a coal cooperative 

lack the typical opposing economic 

interests necessary to create an arm’slength sale. 

In the 2020 Proposed Rule, ONRR 

proposed to amend 30 CFR part 1206 to 

remove the ‘‘coal cooperative’’ 

definition under § 1206.20 and the 

requirements of §§ 1206.252(c)(1)–(2) 

and 1206.452(c)(1)–(2). See 85 FR 

62061. By these proposed amendments, 

ONRR attempts to relieve concerns with 

the meaning and effect of the coal 

cooperative amendments while 

maintaining the royalty value of coal. 

Comments on the Proposed Amendment 

Public Comment: Numerous industry 

commenters agreed that ONRR should 

remove the coal cooperative definition 

because its inclusion in ONRR’s 

regulations fails to reflect those entities’ 

corporate structure, would harm small 

producers, and unduly complicates 

coal’s royalty valuation. 

ONRR Response: For the reasons 

discussed above in the preamble and the 

2020 Proposed Rule (see 85 FR 62061), 

ONRR agrees that the definition of coal 

cooperatives is overly broad and 

ambiguous, and would create too much 

confusion to be effective or enforceable. 

ONRR also agrees that the definition is 

unnecessary because ONRR’s longstanding definitions of ‘‘affiliate’’ and 

‘‘non-arm’s length’’ are sufficient to 

protect the lessor’s interest. Under those 

existing definitions, any transfer of coal 

between entities lacking opposing 

economic interest is a non-arm’s-length 

sale. In such cases, the lessee must look 

to either the first arm’s-length sale of the 

coal by its affiliate, or the lessee must 

come to ONRR and request a valuation 

determination. See 81 FR 43369. 

Public Comment: Some commenters 

oppose the amendment to remove the 

‘‘coal cooperative’’ definition as well as 

its recognition that certain sales are not 

arm’s-length transactions. These 

commenters expressed a concern that 

cooperative members could use their 

affiliated status to sell coal to each other 

at less than market prices, which 

improperly lowers royalty payments. 

Some commenters alleged that ONRR 

failed to provide a reasoned explanation 

as to why the removal of the ‘‘coal 

cooperative’’ definition was necessary 

and also stated that ONRR incorrectly 

asserted the Wyoming District Court 

‘‘offered strong criticism’’ of its 

definition. These commenters 

concluded that ONRR’s proposed action 

is arbitrary and capricious. 

ONRR Response: ONRR’s regulations 

require coal to be valued, when 

possible, on the value realized under the 

first arm’s-length sale. Removing the 

‘‘coal cooperative’’ definition does not 

alter that principle or change other 

methods available to evaluate a coal 

transaction’s nature. The overly broad 

definition of ‘‘coal cooperatives’’ draws, 

within its coverage, entities that are not 

affiliated and which have opposing 

economic interests when it comes to 

buying and selling coal. Thus, the 

definition results in the treatment of 

some transactions as if they were nonarm’s-length when they are, in fact, 

more appropriately viewed as arm’slength transactions under traditional 

principles because ONRR’s regulations 

identify what conditions constitute sales 

between affiliates, and treats those 

circumstances as non-arm’s-length sales. 

And sales between entities that lack 

opposing economic interests are also 

treated as non-arm’s-length sales. As 

demonstrated in its recent filing in the 

United States District Court for the 

District of Wyoming, ONRR concurs 

with the ruling set forth in the District 

Court’s preliminary injunction that 

suggested that, upon final briefing, the 

provisions of the 2016 Valuation Rule 

that require some coal cooperatives to 

value coal based on the sales price of 

electricity and the definition of coal 

cooperative are arbitrary and capricious. 

Removing the cited provisions fosters 

the most appropriate treatment of 

transactions as either arm’s-length or 

non-arm’s-length. 

ONRR appreciates comments 

supporting, seeking modification to, and 

opposing the proposed amendment. 

After careful consideration of the 

reasons given in the 2020 Proposed Rule 

(see 85 FR 62061) that the definition 

was confusing and unnecessary, the 

pleadings filed and arguments raised in 

the United States District Court for the 

District of Wyoming, the District Court’s 

rationale for the preliminary injunction, 

and the public comments, ONRR is 

adopting the amendment to remove the 

‘‘coal cooperative’’ definition from 

§ 1206.20 and the valuation 

requirements for coal sold to coal 

cooperatives at §§ 1206.252(c)(1) and (2) 

and 1206.452(c)(1) and (2). 

III. Amendment Discussion—Part 1241 

Penalties 

The first objective of the civil penalty 

provision of this rule is to increase the 

transparency and fairness of ONRR’s 

current civil penalty practices for the 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4637 

benefit of regulated parties and 

interested members of the public. On 

October 9, 2019, the President issued 

E.O. 13892, ‘‘Promoting the Rule of Law 

Through Transparency and Fairness in 

Civil Administrative Enforcement and 

Adjudication,’’ which emphasized the 

importance of transparency in agency 

civil penalty practices. Specifically, E.O. 

13892 directed Federal agencies to ‘‘act 

transparently and fairly with respect to 

all affected parties . . . when engaged 

in civil administrative enforcement or 

adjudication.’’ Further, E.O. 13892 

highlights the need, where feasible, to 

‘‘foster greater private-sector 

cooperation in enforcement, promote 

information sharing with the private 

sector, and establish predictable 

outcomes for private conduct.’’ 

The second objective of the civil 

penalty provision of this rule is to 

address the analysis of the 2016 Civil 

Penalty Rule within a now vacated 

Federal District Court’s decision. 

In the 2020 Proposed Rule, ONRR 

discussed three potential amendments 

to its civil penalty regulations, set forth 

at 30 CFR part 1241. First, for 

transparency, ONRR proposed to amend 

§ 1241.70(b) to explain that—for 

payment violations only—ONRR would 

consider the monetary impact of the 

violator’s conduct when assessing a 

civil penalty. In Section F of the 2020 

Proposed Rule, ONRR specifically 

elicited comments on how the proposed 

amendment to § 1241.70(b) would 

impact lessees that receive a civil 

penalty. ONRR received no comments 

opposing but received several comments 

supporting this amendment. The 

supporting comments generally agreed 

that penalties should be proportionate 

to the unpaid, underpaid, or late paid 

royalty obligation. ONRR received no 

comment describing the specific impact 

this amendment might have on a lessee. 

As this amendment merely clarifies 

ONRR’s current practice, ONRR did not 

anticipate a commenter would identify 

an impact. 

Second, for transparency, ONRR 

proposed an amendment to § 1241.70 to 

add § 1241.70(d) to clarify that ONRR 

may consider aggravating and mitigating 

circumstances in determining the 

appropriate penalty. In the 2020 

Proposed Rule, ONRR specifically 

requested comments on how this 

proposed § 1241.70(d) would impact 

lessees subject to an ONRR-issued civil 

penalty and what facts or situations 

ONRR should treat as aggravating and 

mitigating circumstances. ONRR 

received comments generally supporting 

this amendment and no comments in 

opposition. The supporting comments 

generally agreed that ONRR should be 

more transparent in how it treats 

mitigating and aggravating 

circumstances. There was no comment 

describing any specific impact this 

amendment would have on a lessee. As 

this amendment merely clarifies 

ONRR’s current practice, it did not 

anticipate any impacts. However, ONRR 

did receive comments suggesting 

alternative aggravating and mitigating 

circumstances, which are addressed 

below in Section III.B. 

Third, for fairness, ONRR proposed to 

amend § 1241.11(b)(5) to return to its 

historical practice of guaranteeing an 

appellant the benefit of a stay of the 

accrual of a civil penalty during an 

appeal if granted by the Department’s 

ALJ. ONRR specifically sought 

comments on how eliminating 

§ 1241.11(b)(5) would affect lessees to 

whom a civil penalty was issued. ONRR 

received comments generally supporting 

this amendment and no comments in 

opposition. The comments in support 

generally agreed that ONRR should 

eliminate this provision from its 

regulations. There was no comment 

describing any specific impact this 

amendment would cause on a lessee, 

other than a general concern that the 

provision, if not removed, would deter 

penalized parties from asserting their 

due process rights. 

General Comments 

ONRR did not receive comments 

either supporting, opposing, or seeking 

to modify the proposed amendments to 

§§ 1241.11(b)(5) and 1241.70(b), or to 

the proposed addition of § 1241.70(d). 

Some commenters sought numerous 

other civil penalty policy changes, 

including increasing the number and 

size of civil penalties or modifying other 

portions of ONRR’s civil penalty 

regulations were beyond the scope of 

the 2020 Proposed Rule. One 

commenter requested that ONRR pursue 

civil penalties for environmental crimes. 

Another commenter sought greater 

collaboration with State and Tribal 

Royalty Audit Committee members on 

FOGRMA compliance. This commenter 

also sought greater royalty accuracy in 

compliance activities—audits, 

compliance reviews, and data mining. 

Commenters sought an increase in civil 

penalties to pursue policy goals of 

decreasing emissions and reducing 

climate change. Other commenters 

requested that ONRR reconsider the 

definition of ‘‘knowingly or willfully’’ 

in § 1241.3(b). Commenters also sought 

to amend § 1241.60(c), which allows 

ONRR to consider ‘‘any information’’ 

including informal email 

communications, to evaluate whether 

violations were committed ‘‘knowingly 

or willfully.’’ One commenter requested 

ONRR adopt a regulation regarding the 

posting of civil penalties and 

enforcement actions on social media. 

ONRR appreciates these comments and 

may consider them in the future; 

however, these comments were beyond 

the scope of the 2020 Proposed Rule and 

unrelated to the proposed amendments 

to §§ 1241.11(b)(5), 1241.70(b), and the 

proposed addition of § 1241.70(d). 

Accordingly, ONRR is not implementing 

policies to enact the proposals in these 

out-of-scope comments in this final rule. 

A. Civil Penalties for Payment 

Violations 

The 2016 Civil Penalty Rule added 

§ 1241.70(b) to clarify that, with respect 

to reporting violations or other 

violations arising from a failure to 

provide required data to ONRR, ONRR 

does not consider the monetary impact 

of the violation in the severity analysis 

performed as part of the determination 

of the amount of a penalty. The 2016 

addition of § 1247.70(b) was meant to 

distinguish between how ONRR treats 

non-payment violations from payment 

violations, the latter of which include a 

failure to pay royalties, rent, interest, 

fees, or other demands or obligations. It 

was ONRR’s intent in the 2016 Civil 

Penalty Rule to clarify that ONRR 

considers the monetary impact in its 

severity analysis only when a 

company’s conduct involves a payment 

violation. This is in addition to ONRR’s 

consideration—in all violation types—of 

the company’s history of 

noncompliance and business size. 

Specifically, § 1241.70(b), as added in 

2016, states that ONRR ‘‘will not 

consider the royalty consequence of the 

underlying violation when determining 

the amount of the civil penalty for a 

violation under § 1241.50 or 

§ 1241.60(b)(1)(ii) or (b)(2).’’ The 

clarification was necessary because 

most violations arising under § 1241.50 

(curable violations) are reporting 

violations and require correction 

regardless of amount of money that may 

be owed because of the reporting 

violation. Because of the need to correct 

violations regardless of the monetary 

amount, reporting violations are similar 

to failure to permit audit violations 

under § 1241.60(b)(1)(ii) and knowing or 

willful submission or maintenance 

violations under § 1241.60(b)(2). 

In the 2020 Proposed Rule, ONRR 

attempted to further clarify how it treats 

payment versus non-payment violations 

with the proposed amendment of 

§ 1241.70(b), stating that ONRR will 

consider the unpaid, underpaid, or late 

payment amount in the severity analysis 

for payment violations only. 

4638 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

In the 2020 Proposed Rule, ONRR 

explained that adopting the proposed 

amendment to § 1241.70(b) is consistent 

with E.O. 13892 which, among the 

general goals of transparency and 

fairness in agency civil penalty 

practices, requires agencies to avoid 

‘‘unfair surprise’’ and apply ‘‘standards 

of conduct that have been publicly 

stated.’’ See E.O. 13892, Section 4. 

ONRR further stated that it would not 

consider the monetary amount for nonpayment obligations. To provide more 

clarity, ONRR is expressly stating that it 

considers the monetary impact for all 

payment violations, which includes 

payment violations arising under 

§ 1241.50. In contrast, the 2016 Civil 

Penalty Rule only indicated that ONRR 

could consider the royalty impact for 

the knowing or willful failure to pay 

royalty violations under 

§ 1241.60(b)(1)(i), which was the only 

violation type left once ONRR excluded 

‘‘violation under § 1241.50 or 

§ 1241.60(b)(1)(ii) or (b)(2).’’ 

ONRR believes that the proposed 

amendment furthers the goal of 

clarifying its civil penalty practices in 

order to make those practices 

transparent. Specifically, the proposed 

amendment adds a sentence clarifying 

that ONRR will consider the monetary 

impact of a penalty only when a 

company’s conduct involves a payment 

violation. 

Comments on the Proposed Amendment 

Public Comment: ONRR received 

comments supporting the proposed 

amendment to § 1241.70(b). These 

commenters generally agreed that ONRR 

should consider the monetary 

consequence of payment violations and 

supported the proposed change to 

§ 1241.70(b). Commenters support the 

reasons ONRR outlined in the 2020 

Proposed Rule and noted that the 

proposed amendment would ensure 

proportionality of the penalty when 

compared to the amount of the unpaid, 

underpaid, or late paid royalty 

obligation at issue. Generally, the 

commenters supported the amendment, 

arguing that penalties issued for 

payment violations should not be 

excessive in comparison to the 

monetary impact of the underlying 

payment violation. To be clear, as stated 

above, ONRR considers the unpaid, 

underpaid, or late-paid amount when it 

considers penalties for payment 

violations arising under § 1241.50 and 

for knowing or willful failure to pay 

royalty violations under 

§ 1241.60(b)(1)(i). 

ONRR Response: ONRR appreciates 

the comments supporting the proposed 

amendment to 30 CFR 1241.70(b). 

ONRR agrees that the 2020 Proposed 

Rule provides greater transparency in 

ONRR’s civil penalty practice. 

After careful consideration, including 

for the reasons explained above, ONRR 

is adopting the proposed amendment to 

§ 1241.70(b) in full. 

B. Consideration of Aggravating and 

Mitigating Circumstances When ONRR 

Assesses a Civil Penalty 

Section 1241.70(a) identifies three 

factors that ONRR must consider in 

assessing the amount of a civil penalty. 

However, this section, as currently 

written, does not include language 

permitting ONRR to consider 

aggravating and mitigating 

circumstances. In the 2020 Proposed 

Rule, ONRR proposed to add new 

paragraph (d) to § 1241.70 stating that 

ONRR may adjust the penalty amount 

upward or downward in a failure to 

correct civil penalty (‘‘FCCP’’) or 

immediate liability civil penalty 

(‘‘ILCP’’) if ONRR finds aggravating or 

mitigating circumstances to exist. 

Consistent with E.O. 13892’s 

transparency and fairness directives, the 

proposed addition of § 1241.70(d) 

explains that ONRR may consider 

aggravating and mitigating 

circumstances when calculating the 

amount of a civil penalty. The 

amendment also aims to reduce or 

eliminate any undue surprise for 

companies in instances where ONRR 

deviates from the standard penalty 

assessment because of those 

circumstances. Additionally, the 

proposed addition of § 1241.70(d) 

accomplishes the implementation of the 

approach directed by E.O. 13924 and 

E.O. 13892. 

Comments on the Proposed Amendment 

Public Comment: ONRR received 

comments supporting the proposed 

amendment to add § 1241.70(d). The 

commenters generally supported greater 

transparency in ONRR’s assessment of 

penalties. The commenters agreed that 

ONRR should consider aggravating or 

mitigating circumstances in certain 

cases and therefore support the addition 

of § 1241.70(d). Some commenters who 

supported this amendment did so 

because it establishes flexibility in 

ONRR’s civil penalty calculations in 

order to arrive at penalty amounts that 

are proportionate to the underlying 

monetary violation. 

Some commenters responded to 

ONRR’s request for comment on 

circumstances that ONRR should 

consider to be aggravating and 

mitigating. Some commenters supported 

the inclusion of an aggravating 

circumstance to consider ‘‘intentional 

misconduct to reduce royalties 

otherwise due.’’ Some commenters 

suggested including additional 

mitigating factors, such as innocent 

reporting mistakes, lack of a history of 

prior violations of the same or more 

severe violations, and actions that 

adhere to guidance from ONRR. One 

commenter suggested that the proposed 

provision under § 1241.70(d)(iii), which 

considers good faith efforts to comply 

with formal or informal agency 

guidance, should constitute grounds for 

eliminating any civil penalty from being 

assessed. Lastly, another commenter 

suggested that the list of aggravating and 

mitigating circumstances is not 

exhaustive and may lend to ambiguity 

and agency burden in making case-bycase determinations. 

ONRR Response: ONRR appreciates 

and agrees with the comments 

supporting the proposed amendment to 

§ 1241.70(d). ONRR acknowledges that 

the list of circumstances in the proposed 

regulatory language is not all-inclusive. 

Although the list is not exhaustive, it 

provides further transparency and 

predictability with respect to existing 

practices. ONRR possesses both the 

authority and expertise to consider 

aggravating or mitigating circumstances 

outside of the list proposed under 

§ 1241.70(d). These considerations do 

not create an undue or excessive burden 

to the agency, as one commenter 

suggested. 

Some commenters recommended the 

inclusion of additional aggravating or 

mitigating circumstances. ONRR 

disagrees with the suggestion to include 

an aggravating circumstance of 

intentional misconduct to reduce 

royalties otherwise due, because that 

circumstance is considered in the 

standard penalty amount for noncurable violations described under 30 

U.S.C. 1719(c) and (d) and 30 CFR 

1241.60. ONRR also disagrees with the 

suggestion to include a mitigating 

circumstance of innocent reporting 

mistakes, because that circumstance is 

considered in the standard penalty 

amount of curable violations described 

under 30 U.S.C. 1719(a) and (b) and 30 

CFR 1241.50. Consideration of innocent 

reporting mistakes as a mitigating 

circumstance would de-emphasize and 

undermine the importance of correcting 

the mistakes promptly as required by an 

ONRR notice of noncompliance 

(‘‘NONC’’). And receipt of an ONRR 

NONC is a condition precedent to 

ONRR’s assessment of a penalty for a 

failure to correct an innocent reporting 

mistake. ONRR also disagrees with the 

suggestion to include a mitigating 

circumstance of a lack of a prior 

violation. ONRR’s standard penalty 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4639 

amounts already account for a lack of a 

history of noncompliance. Finally, 

ONRR is making no change in response 

to the suggestion to modify the language 

that no penalties are appropriate when 

a violator makes a good faith effort to 

comply with formal or informal agency 

guidance. Consistent with its exercise of 

prosecutorial discretion, ONRR retains 

the discretion to evaluate mitigating 

circumstances on a case-by-case basis 

and conclude that the presence of 

mitigating circumstances can justify 

resolving a matter without penalty. See 

Heckler v. Chaney, 470 U.S. 821 (1985). 

In exercising its prosecutorial 

discretion, ONRR will be guided by the 

principles reflected in E.O. 13924, 

‘‘Regulatory Relief to Support Economic 

Recovery,’’ E.O. 13892, ‘‘Promoting the 

Rule of Law Through Transparency and 

Fairness in Civil Administrative 

Enforcement and Adjudication,’’ E.O. 

13891, ‘‘Promoting the Rule of Law 

Through Improved Agency Guidance 

Documents,’’ and S.O. 3385, 

‘‘Enforcement Priorities.’’ Thus, ONRR 

already has the discretion to determine 

that no penalties are appropriate when 

sufficient mitigating circumstances are 

present, including a good faith effort to 

comply with formal or informal agency 

guidance. Because ONRR intended for 

the proposed amendment to provide 

transparency in how it calculates 

penalty amounts and did not intend to 

address when it would exercise its 

prosecutorial discretion, ONRR finds 

the language regarding guidance in the 

proposed provision under 

§ 1241.70(d)(2)(iii) sufficient. 

ONRR appreciates the comments 

supporting and seeking the modification 

to the proposed amendment to 

§ 1241.70(d). After careful 

consideration, and for the reasons 

explained above, ONRR is adopting the 

proposed addition at § 1241.70(d) in 

full. 

C. Forfeiture of a Stay of the Civil 

Penalty Accrual Under Limited 

Circumstances 

ONRR’s 2016 Civil Penalty Rule 

added § 1241.11(b)(5) to give an ALJ the 

ability to conclude that a petitioner had 

raised a frivolous defense and therefore 

should forfeit the benefit of a 

previously-granted stay of the accrual of 

the amount of the civil penalty. 

Specifically, the 2016 Civil Penalty Rule 

states that ‘‘[n]otwithstanding 

paragraphs (b)(1), (2), (3), and (4) of this 

section, if the ALJ determines that your 

defense to a Notice is frivolous, and a 

civil penalty is owed, you will forfeit 

the benefit of the stay, and penalties 

will be calculated as if no stay had been 

granted.’’ 

In the 2020 Proposed Rule, ONRR 

proposed to amend § 1241.11 by 

removing paragraph (b)(5). The 

proposed amendment followed the U.S. 

District Court for the District of 

Wyoming’s decision to vacate 

§ 1241.11(b)(5). See API, 366 F. Supp. 

3d at 1309–1311. Although the Tenth 

Circuit subsequently vacated the District 

Court’s decision on other grounds, 

ONRR finds the District Court’s analysis 

relevant in its determination to remove 

paragraph (b)(5) and the mission of 

ONRR’s overall civil penalty program. 

The District Court found 

‘‘unpersuasive’’ the argument that due 

process rights are implicated by 

§ 1241.11(b)(5), but still found the 

provision ‘‘an abuse of discretion and 

not in accordance with law.’’ API, 366 

F. Supp. 3d at 1310. Most problematic 

to the District Court was the fact that it 

provided ONRR with ‘‘a second bite’’ to 

argue a defense was frivolous after an 

optional chance to oppose the stay and 

‘‘the potential loss’’ if a stay were 

nullified was significant. Id. This 

analysis is relevant because if a person 

obtains standing to challenge this 

provision in the future, ONRR expects it 

will be invalidated if challenged in the 

District of Wyoming. 

The IBLA, Office of Hearings and 

Appeals Division’s procedural 

requirements under 43 CFR 4.21(b) 

establish that ‘‘the appellant requesting 

the stay bears the burden of proof to 

demonstrate that a stay should be 

granted.’’ If the ALJ grants a stay, the 

accrual of additional penalty amounts 

would be paused until there is an ALJ 

decision in ONRR’s favor, coupled with 

a determination that the violation is 

ongoing. See 30 CFR 1241.11(a) and (b). 

By adopting the amendment, ONRR 

returns to its pre-2016 Civil Penalty 

Rule practice whereby penalties would 

not accrue during the period of a stay, 

even if an ALJ subsequently finds a 

petitioner’s defense to the penalty to be 

frivolous. 

ONRR believes § 1241.11(b)(5) is 

duplicative because ONRR may still 

safeguard against a frivolous defense by 

opposing a petition for a stay under 

§ 1241.11(b)(2)(i). As the District Court 

stated, ‘‘If ONRR believes a stay is not 

warranted, including the argument that 

the defense is frivolous, ONRR has the 

right to, and should file a response to 

the stay petition rather than wait on an 

outcome at some undetermined later 

date and then assert frivolity.’’ API, 366 

F. Supp. 3d at 1310. ONRR concurs with 

the District Court that ONRR has the 

right to oppose a frivolous stay petition 

and that it should do so. Additionally, 

removing § 1241.11(b)(5) would be 

consistent with executive orders seeking 

to increase transparency and reduce 

undue surprise in penalty assessments. 

Further, by removing § 1241.11(b)(5), 

ONRR still retains a remedy against 

frivolous cases, while eliminating 

unnecessary regulations. 

ONRR anticipates that it will be rare 

that a frivolous defense is both more 

persuasive than ONRR’s response to a 

petition for stay and ultimately 

sufficient to convince the ALJ that the 

petitioner’s defense to the penalty was 

frivolous. ONRR believes that removing 

§ 1241.11(b)(5), in light of the District 

Court’s analysis, remains consistent 

with the purpose of assessing civil 

penalties, which is to encourage 

compliance and discourage 

noncompliance, and also is consistent 

with E.O. 13892 and the policies 

reflected in that order. 

Comments on the Proposed Amendment 

Public Comment: Some commenters 

supported the removal of 

§ 1241.11(b)(5). The commenters that 

supported the amendment fell into two 

general categories. First, commenters 

generally supported the reasons 

described in the 2020 Proposed Rule. 

Second, commenters supported the 

amendment because of due process 

concerns, including the possibility that 

§ 1241.11(b)(5) may discourage a 

petitioner from exercising its due 

process rights. ONRR also received one 

comment suggesting that the 2020 

Proposed Rule did not provide 

sufficient reasons for its repeal of an 

ALJ’s ability to revoke a stay of accrual 

upon determination of a frivolous claim. 

The commenters did not advocate for 

rejecting or modifying the amended 

regulations as proposed. However, the 

commenter asserted that the Tenth 

Circuit’s vacatur of the District Court of 

Wyoming’s decision is an insufficient 

rationale to remove the provisions 

found in § 1241.11(b)(5). 

ONRR Response: ONRR appreciates 

and agrees with the comments 

supporting the proposed amendment to 

§ 1241.11(b)(5). ONRR also appreciates 

this opportunity to afford additional 

clarity and rationale in the proposed 

removal of this provision, which is to 

increase transparency, reduce undue 

surprise, remove an unnecessary 

regulation, and still have sufficient 

protection from frivolous defenses to 

civil penalties, as further discussed 

above. 

ONRR appreciates the comments 

supporting the proposed amendment to 

§ 1241.11(b)(5) and the comment 

indicating that additional rationale is 

needed to remove this provision. After 

careful consideration, and for the 

reasons and additional rationale 

4640 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

explained above, ONRR is adopting the 

proposed amendment to remove 

§ 1241.11(b)(5). 

IV. Non-Substantive Corrections 

Through this final rule, ONRR is also 

making non-substantive corrections to 

the following sections: §§ 1206.108, 

1206.148, 1206.252, 1206.258, 1206.261, 

1206.268, 1206.452, 1206.458, 1206.460, 

1206.461, 1206.467, and 1206.468. 

Corrections include: 

1. ONRR reports to the Assistant 

Secretary for Policy, Management, and 

Budget. This final rule replaces 

instances of the words ‘‘Assistant 

Secretary’’ with ‘‘Assistant Secretary for 

Policy, Management and Budget’’ to 

clarify and specify the correct Assistant 

Secretary within the Department. 

2. 30 CFR 1206.252 and 1206.452 are 

titled ‘‘How do I calculate royalty value 

for coal that I or my affiliate sell(s) 

under an arm’s-length or non-arm’slength contract?’’ In addition to 

addressing the valuation of coal that is 

sold, these sections also address the 

valuation of coal that a lessee or its 

affiliate uses for the generation and sale 

of electricity. See §§ 1206.252(b) and 

1206.452(b). This final rule eliminates 

any requirement that coal be based on 

the price received through electricity 

sales. Even after that amendment, both 

sections still address the valuation of 

coal that is used for the generation and 

sale of electricity, and thus not sold. 

Specifically, the sections require the 

lessee to propose a method to ONRR for 

the valuation of the coal and further 

require the lessee to use its proposed 

valuation method until ONRR makes a 

determination. Id. Since both sections 

also address situations when coal is not 

sold, ONRR is amending the title of 

§§ 1206.252 and 1206.452 as part of this 

final rule to read: ‘‘How do I calculate 

royalty value for coal?’’ This 

amendment conforms the title of the 

sections to the content thereof. 

3. 30 CFR 1206.252(a) and 1206.452(a) 

provide that the value of coal generally 

is the ‘‘gross proceeds accruing to you 

or your affiliate under the first arm’slength contract’’ less certain allowances. 

Sections 1206.252(a)(1)–(2) and 

1206.452(a)(1)–(2) state that this 

requirement to use gross proceeds to 

value the coal applies when a lessee 

sells the coal under an arm’s-length 

contract or the lessee sells or transfers 

the coal to its ‘‘affiliate or another 

person under a non-arm’s-length 

contract, and that affiliate or person, or 

another affiliate of either of them, then 

sells the coal under an arm’s-length 

contract.’’ Since the first arm’s-length 

sale of the coal may be by a person other 

than the lessee or its affiliate under 

§§ 1206.252(a)(1)–(2) and 

1206.452(a)(1)–(2), ONRR is amending 

§§ 1206.252(a) and 1206.452(a) to reflect 

that the gross proceeds used to value the 

coal is the ‘‘gross proceeds accruing to 

you, your affiliate, or another person 

under the first arm’s-length contract’’ 

less allowances. 

4. The 2020 Proposed Rule also 

proposed amendments to change certain 

instances of ‘‘may’’ to ‘‘must’’ in 

§§ 1206.252(b)(2) and 1206.452(b)(2). 

The paragraphs apply when a lessee has 

proposed a valuation method to ONRR 

for consideration and instruct that the 

lessee ‘‘may’’ use the method it 

proposed until ONRR issues a 

determination. ONRR intended that the 

lessee would use its proposed method 

while its proposal was pending with 

ONRR. A change from ‘‘may’’ to ‘‘must’’ 

better reflects that intent. For the same 

reasons, ONRR is making the same 

change from ‘‘may’’ to ‘‘must’’ in 

§§ 1206.111(d)(2); 1206.141(e)(2)(ii); 

1206.142(f)(2)(ii); 1206.153(d)(1); 

1206.160(c)(1); 1206.261(c)(1); 

1206.268(c)(1); 1206.461(c)(1); and 

1206.468(c)(1) (reporting a washing 

allowance using a proposed method). 

5. This final rule corrects the 2020 

Proposed Rule’s description of some 

leases as ‘‘Federal’’ when they should 

have been identified as ‘‘Indian’’ in 

§§ 1206.460 and 1206.467. 

6. ONRR is correcting a crossreference in § 1206.458(h) to properly 

refer to ‘‘§ 1206.459’’ rather than 

‘‘§ 1206.259,’’ as was initially published 

in the 2020 Proposed Rule. 

V. Economic Analysis 

ONRR shares the Department’s 

statutory mandate to conserve and 

encourage domestic production of 

natural resources and develop 

regulations to achieve these goals. 

BOEM and BLM have provided 

information and documentation to 

ONRR demonstrating that the dynamics 

of the domestic energy markets have 

changed since the 2016 Valuation Rule 

was published. In the years leading up 

to the 2016 Valuation Rule, domestic 

energy commodity prices were nearly 

double those leading up to this rule. 

Given this, GOM assets have lost value 

and leasing is less attractive than 

previously. BOEM information shows 

reserves in the GOM are declining and 

GOM bidding, active leases, rig counts, 

and wells spud have declined 

significantly since ONRR’s Economic 

Analysis in the 2016 Valuation Rule. 

In the 2020 Proposed Rule, ONRR 

summarized the estimated changes to 

royalties and regulatory costs that the 

proposed rule may have on potentially 

affected groups, including industry, the 

Federal Government, and State and 

local governments. 

ONRR notes that changes to royalties 

are transfers that are distinguishable 

from regulatory costs (or cost savings). 

The estimated changes in royalties will 

change both the private cost to the 

lessee and the amount of revenue 

collected by the Federal Government 

and disbursed to State and local 

governments. The net impact of the 

amendments adopted by this final rule 

is an estimated $28.9 million annual 

decrease in royalty collections. This 

represents a decrease of less than onehalf of one percent of the total Federal 

oil and gas royalties ONRR collected in 

2018. The royalty impact, as evident in 

the total annual estimate reflected 

above, does impact the disbursements 

for the Treasury and for States that are 

stakeholders and recipients of ONRR’s 

distributions. 

ONRR also estimates that the Federal 

oil and gas industry will face increased 

annual administrative costs of $2.58 

million under this final rule. As 

discussed below, this is the net impact 

of various cost increasing and cost 

saving measures. 

ONRR estimates that this rule will 

have no economic impact on Federal 

and Indian coal. 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. 

General Comments on the Economic 

Analysis 

Public Comment: Some commenters 

suggested that the economic analysis is 

incorrect because it compared the 

proposed amendments relative to 

ONRR’s current regulations which 

include the 2016 Valuation Rule 

amendments, which commenters 

suggest should have never happened. 

ONRR Response: ONRR’s current 

regulations include the 2016 Valuation 

Rule’s amendments. The appropriate 

baseline for this rule is the rules that are 

currently in effect. Any change that 

would be affected by the rule will be 

measured relative to that baseline. 

1. Federal Oil and Gas Industry 

This table shows the change in 

royalties by provision for the first year 

and each year thereafter: 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4641 

SUMMARY OF CHANGES TO OIL & GAS ROYALTIES PAID

[Annual] 

Rule provision 

Net change 

in royalties 

paid by 

lessees 

Index-Based Valuation Method Extended to Arm’s-Length Gas Sales .............................................................................................. $5,620,000 

Index-Based Valuation Method Extended to Arm’s-Length NGL Sales ............................................................................................. 21,141,000 

High to Midpoint Index Price for Non-Arm’s-Length Gas Sales ......................................................................................................... (4,488,000) 

Transportation Deduction Non-Arm’s-Length Index-Based Valuation Method ................................................................................... (7,121,000) 

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

Allowances for Certain OCS Deepwater Gathering Costs .................................................................................................................. (32,900,000) 

Total .............................................................................................................................................................................................. (28,879,000) 

ONRR estimated the administrative 

cost savings from optional use of the 

index-based valuation method for arm’slength gas and NGL sales and 

administrative costs from the 

calculation of allowances for certain 

OCS deepwater gathering. These 

administrative costs to industry totaled 

approximately $2.58 million annually. 

SUMMARY OF ANNUAL ADMINISTRATIVE IMPACTS TO INDUSTRY

Rule provision Cost 

(cost savings) 

Administrative Cost Savings for Index-Based Valuation Method for Gas & NGLs ............................................................................ (1,354,000) 

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

Total .............................................................................................................................................................................................. 2,577,000 

ONRR also estimated industry will 

incur a one-time administrative cost 

savings of $4.5 million from the 

simplification of reporting processing 

and transportation allowances 

associated with the optional use of the 

index-based valuation method. These 

costs are only calculated by a lessee 

once to break out allowed from 

disallowed costs in reported processing 

and transportation allowances. Unless 

there is a significant change in 

processing and transportation costs, this 

ratio of allowed to disallowed costs 

should not change from year to year. 

ONE-TIME ADMINISTRATIVE IMPACTS TO INDUSTRY

Rule provision Cost savings 

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

To perform this economic analysis on 

all the provisions adopted in this final 

rule, 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 the five calendar years, 2014– 

2018. ONRR believes the majority of the 

reporting used in this analysis was 

made in compliance with the 

regulations in place prior to the 2016 

Valuation Rule. ONRR used five 

calendar years of royalty data because 

this longer time period helped reduce 

volatility caused by fluctuations in 

commodity pricing and volume swings. 

ONRR used this data without adjusting 

for previous rulemakings because at the 

time of this analysis, a significant 

number of lessees and operators had not 

yet complied with the 2016 Valuation 

Rule’s provisions due to its 

implementation delays, including the 

2017 Repeal Rule, the subsequent 2019 

Vacatur, and ONRR’s two dear reporter 

letters providing industry with 

additional time to come into compliance 

with the 2016 Valuation Rule following 

its reinstatement. 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. Lessees report those sales and 

dispositions using the ‘‘POOL’’ sales 

type code. Only a small portion of these 

gas sales are non-arm’s-length. ONRR 

used estimates of 10 percent of the 

POOL volumes in the economic analysis 

of non-arm’s-length sales and 90 percent 

of the POOL volumes in the economic 

analysis of arm’s-length sales. 

Change in Royalty 1: Using Index-Based 

Valuation Method To Value Arm’sLength Federal Unprocessed Gas, 

Residue Gas, Fuel Gas, and Coalbed 

Methane 

To estimate the royalty impact of the 

option to pay royalties using the indexbased valuation method, ONRR 

reviewed the reported royalty data for 

all Federal gas sales except for nonarm’s-length (discussed below), future 

valuation agreements, and percentage of 

proceeds (‘‘POP’’) sales. 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 assumes 

the remaining five percent of Federal 

gas lessees will not elect the indexVerDate Sep<11>2014 06:10 Jan 15, 2021 Jkt 253001 PO 00000 Frm 00031 Fmt 4701 Sfmt 4700 E:\FR\FM\15JAR6.SGM 15JAR6
4642 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

based method because areas outside of 

major producing basins may have 

infrastructure limitations or limited 

access to index pricing. The 10 

geographic areas are: 

Offshore Gulf of Mexico Big Horn Basin Green River 

Basin Permian Basin Piceance Basin 

Powder River Basin .......................................................................... San Juan Basin Uinta Basin ....... Williston Basin .. Wind River Basin. 

To calculate the estimated impact, 

ONRR: 

(1) Identified the monthly bidweek 

price index, published by Platts Inside 

FERC, 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 

GOM. ONRR determined the price index 

applicability based on proximity to the 

producing area and the frequency by 

which ONRR’s audit and compliance 

staff verify these index prices in sales 

contracts. 

(2) Subtracted the transportation 

deduction as modified by this rule 

(detailed in the transportation section 

below) from the midpoint index price 

identified in step (1). 

(3) Multiplied the royalty volume by 

the index price identified per region, 

less the transportation deduction 

calculated in step (2). 

(4) Totaled the reported royalties less 

allowances reported on the monthly 

royalty report (form ONRR–2014) and 

the estimated royalties based on the 

index-based valuation method 

calculated in step (3). 

(5) Calculated the annual average of 

reported royalties and estimated indexbased royalties calculated in step (4) by 

dividing by five (number of years of 

reported data in the analysis). 

(6) Subtracted the difference between 

the totals calculated in step (5). 

ONRR anticipates that some lessees 

will choose to value their royalties on 

natural gas sales reported to ONRR 

using this index-based valuation 

method, saving administrative costs 

(described in detail below in Cost 

Savings 1 and Cost Savings 2), while 

other lessees will continue to calculate 

and deduct the actual costs they incur. 

As discussed above in response to a 

comment, ONRR cannot precisely 

estimate how many lessees will elect to 

use the index-based valuation method 

since many factors, that are currently 

unquantifiable, will drive a lessee’s 

decision. For the purposes of this 

analysis and for consistency with 

previous similar analyses, ONRR 

assumed that half of lessees would 

choose the index-based valuation 

method to value sales and dispositions 

eligible for the election. ONRR’s 

assumption that half of lessees will 

choose this method is an attempt to 

simplify the countless number of factors 

such as, unpredictable natural gas price 

changes, simpler accounting methods 

for lessees, company-specific break-even 

analysis in producing regions, and 

unbundling administrative calculations. 

ONRR also isolated the GOM from the 

onshore basins listed above because it 

accounts for approximately 30 percent 

of the total Federal gas sales used in this 

analysis, as well as having different 

complexities, when compared to 

onshore areas. 

ONRR estimates that the index-based 

valuation method will increase annual 

royalty payments on arm’s-length 

unprocessed gas, residue gas, fuel gas, 

and coalbed methane by approximately 

$5.6 million. This estimate represents 

an average increase of approximately 

one percent, or $0.04 per MMBtu, based 

on an annualized royalty volume of 

296,440,024 MMBtu. ONRR chose not to 

include POP sales in the above method 

because the sales are reported inclusive 

of the NGL value and net of 

transportation and processing costs. To 

capture the change in value associated 

with POP contracts, ONRR applied the 

$0.04 per MMBtu calculated above to 

the annualized royalty volume for 

arm’s-length percent of proceeds 

(‘‘APOP’’) sales of 158,772,452 MMBtu. 

ONRR recognizes that it is not 

accounting for the value of APOP NGLs, 

however ONRR does not have a 

reasonable method to break out those 

components from the available data. 

ANNUAL NET CHANGE IN ROYALTIES PAID USING INDEX-BASED METHOD FOR ARM’S-LENGTH GAS SALES

Gulf of Mexico Onshore 

basins Total 

Annualized Reported Royalties ................................................................................................... $235,065,000 $541,124,000 $776,189,000 

Royalties Estimated using Index-Based Valuation Method ........................................................ $250,183,000 $536,564,000 $786,747,000 

Difference ..................................................................................................................................... $15,118,000 ($4,560,000) $10,558,000 

Change per MMBtu ..................................................................................................................... $0.18 ($0.02) $0.04 

% Change .................................................................................................................................... 6% (1%) 1% 

Annualized POP Royalties using Index-Based Valuation Method .............................................. ........................ ........................ $682,000 

Annual Net Change in Royalties Paid using Index-Based Valuation Method ............................ ........................ ........................ $11,240,000 

50% of Lessees Choose Index-Based Valuation Method ........................................................... ........................ ........................ $5,620,000 

Comments on the Analysis of this 

Amendment 

Public Comment: A commenter stated 

that ONRR’s assumption that half of 

lessees will choose to use the indexbased valuation method is unreasonable 

and incorrectly overstates the estimated 

change in royalties. 

ONRR Response: ONRR acknowledges 

the uncertainty associated with 

predicting the number of lessees who 

may elect to use the index-based 

valuation methods as the commenter 

suggests. One major factor a lessee must 

look at when deciding whether to elect 

the index-based valuation method for 

two consecutive years is a prediction of 

future natural gas pricing. It is difficult 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4643 

to accurately predict natural gas prices 

two years into the future at the precise 

levels required when so many market 

dynamics are at play. Current domestic 

natural gas prices have changed 

compared to recent years and fluctuate 

up and down regularly. Because of these 

unknowns and for consistency with 

previous similar analysis, including the 

2016 Valuation Rule, ONRR will 

continue to use the assumption that half 

of lessees will adopt this method to 

provide a baseline of understanding for 

the impacts of the provision. 

Public Comment: ONRR received a 

comment that claimed in the 2016 

Valuation Rule’s Preamble, valuing gas 

transactions based on the first arm’slength sale would result in 

administrative cost savings of $247,000 

for industry. The commenter claims 

ONRR ignored these 2016 Valuation 

Rule calculations in the proposed rule 

when claiming that extending the indexbased valuation method to all 

transactions reduces administrative 

burden. 

ONRR Response: ONRR believes the 

commenter misunderstood the 2016 

Valuation Rule analyses. In both the 

2016 Valuation Rule and the 2020 

Proposed Rule, using the index-based 

valuation method creates an 

administrative cost savings for lessees 

compared to using the first arm’s-length 

sale made by an affiliate of the lessee. 

Change in Royalties 2: Using the IndexBased Valuation Method To Value 

Arm’s-Length Sales of Federal NGLs 

Similar to the changes to Federal 

unprocessed gas, residue gas, pipeline 

fuel, and coalbed methane, a lessee will 

have the option to pay royalties on 

Federal NGLs using an index-based 

value less a processing allowance 

defined by regulation and be allowed an 

adjustment for transportation costs and 

fractionation costs, which account for 

the prices realized at the various NGL 

hubs. ONRR used the same 2014–2018 

calendar years for all NGL sales except 

for non-arm’s-length 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 

Federal NGLs, 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 price (a 

weighted average price to group the 

individual NGL components to a 

weighted price), which were compared 

to the imputed price from the monthly 

royalty report. The baskets illustrate the 

difference in the gas composition 

between Conway, Kansas and Mont 

Belvieu, Texas. The NGL basket 

hydrocarbon allocations are: 

Platts Conway Basket 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 the current regulations 

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) Multiplied the royalty volume by 

the index price identified for each 

region, less the NGL deduction 

calculated in step (3). 

(5) Totaled the royalty value less 

allowances reported on the monthly 

royalty report, and the estimated 

royalties based off the index-based 

valuation method calculated in step (4). 

(6) Calculated the annual average of 

reported royalties and estimated indexbased royalties calculated in step (5) by 

dividing by five (number of years in this 

analysis). 

(7) Subtracted the difference between 

the totals calculated in step (6). 

Because ONRR assumed that half of 

lessees would choose this option for 

eligible dispositions, ONRR reduced the 

total estimate by 50 percent in the 

following table. ONRR estimates that 

this change will increase annual royalty 

payments by approximately $21.1 

million. This estimate represents an 

average increase of approximately 17 

percent or $0.0894 per gallon, based on 

an annualized royalty volume of 

475,257,250 gallons [($42,281,000/ 

475,257,250 gal) = $0.0894/gal]. 

4644 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

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

Gulf of Mexico New Mexico Other areas Total 

Annualized Reported Royalties ....................................................................... $74,438,000 $67,637,000 $70,072,000 $212,147,000 

Royalties Estimated using Index-Based Valuation Method ............................. $77,068,000 $66,397,000 $110,962,000 $254,428,000 

Annual Net change in Royalties Paid using Index-Based Valuation Method 

for NGLs ....................................................................................................... $2,630,000 ($1,240,000) $40,891,000 $42,281,000 

Change per Gallon .......................................................................................... $0.0174 ($0.0081) $0.2439 $0.0894 

% Change ........................................................................................................ 3% (2%) 37% 17%

50% of Lessees Choose the Index-Based Valuation Method ................. ........................ ........................ ........................ $21,141,000 

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 

As noted above, the index-based 

valuation method will change from 

using the highest published price for a 

specific index-pricing point to using the 

average published bidweek price for the 

index-pricing point. To estimate the 

royalty impact of this change from the 

highest published index price to the 

average published bidweek price for the 

index-based valuation method, ONRR 

used reported royalty data using nonarm’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). 

(5) Subtracted the difference between 

the totals calculated in step (4). 

As explained in response to a 

comment above, ONRR assumes that 

half of lessees would choose this 

method, and ONRR therefore reduced 

the total estimate by 50 percent in the 

following table. ONRR estimates that the 

result of this change is a decrease in 

annual royalty payments of 

approximately $4.5 million. This 

estimate represents an average decrease 

of approximately three percent or ten 

cents ($0.10) per MMBtu, based on an 

annualized royalty volume of 

93,301,478 MMBtu (for NARM and 10 

percent POOL reported sales type 

codes). 

ANNUAL CHANGE IN ROYALTIES PAID DUE TO 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) 

Change per MMBtu ..................................................................................................................... (0.01) (0.14) (0.10) 

% Change .................................................................................................................................... 0% (5%) (3%) 

50% of Lessees Choose the Index-Based Method ............................................................. ........................ ........................ (4,488,000) 

Change in Royalties 4: Modifying the 

Index-Based Valuation Method 

Transportation Deduction Used To 

Value Non-Arm’s-Length Federal 

Unprocessed Gas, Residue Gas, Coalbed 

Methane, and NGLs 

This rulemaking updates the 

transportation deductions applicable to 

the non-arm’s-length index-based 

valuation method to reflect changes in 

industry’s transportation contracts terms 

and more recent allowance data 

reported to ONRR. To estimate the 

royalty impact of the modification to the 

transportation deduction, ONRR used 

reported royalty data using NARM and 

10 percent of the POOL sales type codes 

from the same 10 major geographic areas 

with active index-pricing points listed 

above. 

To calculate the estimated impact, 

ONRR: 

(1) Identified appropriate areas using 

Platts Inside FERC index prices (see list 

above). 

(2) Calculated the transportation 

deduction as published in the current 

regulations and the deduction outlined 

in the table below for each area 

identified in step (1). 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4645 

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

[$/MMBtu] 

Element 2016 

valuation rule 

2020 

valuation 

reform and 

civil penalty 

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). 

(6) Subtracted the difference between 

the totals calculated in step (5). 

Because ONRR estimates that half of 

lessees will choose this option, ONRR 

reduced the total estimate by 50 percent. 

Please note that the figures in the table 

below represent the difference between 

the current transportation adjustment 

percentage found in the 2016 Valuation 

Rule and the percentage under the 

index-based valuation method in the 

2020 Proposed Rule. ONRR estimates 

the change will result in a decrease in 

annual royalty payments of 

approximately $7.1 million. This 

estimate represents an average decrease 

in royalties paid of approximately 65 

percent or 15 cents per MMBtu, based 

on an annualized royalty volume of 

93,301,478 MMBtu (for NARM and 10 

percent POOL reported sales type 

codes). 

ANNUAL CHANGE IN ROYALTIES DUE TO TRANSPORTATION DEDUCTION MODIFICATION FOR NON-ARM’S-LENGTH SALES OF

NATURAL GAS

Gulf of Mexico Other areas Total 

Current Regulations Transport Deduction ................................................................................... $5,387,000 $16,375,000 $21,762,000 

Estimate using new Transport Deduction ................................................................................... 10,346,000 25,659,000 36,005,000 

Difference ..................................................................................................................................... 4,959,000 9,284,000 14,243,000 

Change per MMBtu ..................................................................................................................... 0.15 0.15 0.15 

50% of Lessees Choose the Index-Based Valuation Method ............................................. ........................ ........................ 7,121,000 

Annual Change in Royalties Due to Transportation Deduction Modification ............... ........................ ........................ (7,121,000) 

Clarifying the description of the 

$0.04/MMBtu and $0.09/MMBtu: In the 

2020 Proposed Rule, ONRR noted the 

estimated changes in royalties under the 

proposed index-based valuation 

method. Specifically, the preamble of 

the 2020 Proposed Rule (85 FR 62054, 

at 62058) provided, ‘‘As we outline in 

the Procedural Matters section, overall 

royalty values under the 2016 Valuation 

Rule’s index-based valuation method 

are still around $0.04/MMBtu higher 

than the prices reported to ONRR for 

arm’s-length sales. In the 2020 Proposed 

Rule, the average bidweek price would 

result in around $0.09 less per MMBtu.’’ 

This section was unclear, and should 

have provided, ‘‘As outlined in the 

Procedural Matters section, overall 

royalty values under the 2020 Valuation 

Rule’s index-based valuation method 

are around $0.04/MMBtu higher than 

the prices reported to ONRR for arm’slength sales. For non-arm’s-length 

dispositions valued under the proposed 

rule’s index-based valuation method, 

using the average bidweek price instead 

of the bidweek high price would result 

in around $0.09 less per MMBtu’’ 

(emphasis added). This clarification 

does not affect the economic analyses 

conducted in the 2020 Proposed Rule 

and this final rule. 

No Change in Royalties 1: 

Transportation Allowances in Excess of 

50 Percent of the Royalty Value Prior to 

Allowances for Federal Gas 

In certain scenarios, a lessee may 

incur costs to transport Federal gas at a 

cost that exceeds the regulatory limit of 

50 percent of the gas’s royalty value 

prior to allowances. This rule does not 

provide a lessee the ability to submit a 

request to ONRR to exceed the 50 

percent limit. The annual number of 

requests to exceed allowance limits 

submitted by lessees to ONRR has 

decreased since the similar analysis was 

performed for the 2016 Valuation Rule. 

To estimate the change in royalties 

associated with the proposed 

amendment, ONRR first identified all 

gas transportation allowances reported 

on the monthly royalty reports 

exceeding the 50 percent limit for 

calendar years 2014–2018. Next, ONRR 

calculated the transportation allowance 

claimed for each royalty line compared 

to what the transportation allowance 

would have been at the 50 percent limit. 

ONRR then calculated annual totals and 

averaged them over 5 years. The result 

in the proposed rule was an estimated 

annual decrease in royalties paid by 

industry of approximately $279,000 per 

year. ONRR is not adopting this 

regulation change. There is no change in 

estimated royalties. 

No Change in Royalties 2: 

Transportation Allowances in Excess of 

50 Percent of the Royalty Value Prior to 

Allowances for Federal Oil 

Similar to the section above, a lessee 

may incur costs to transport Federal oil 

that exceed the regulatory limit of 50 

percent of the oil’s royalty value prior 

4646 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

to allowances. This rule does not 

provide a lessee the ability to request to 

exceed that limit. The annual number of 

requests to exceed allowance limits 

submitted by lessees to ONRR has 

decreased since the similar analysis was 

performed for the 2016 Valuation Rule. 

To estimate the change in royalties 

associated with the proposed 

amendment, ONRR first identified all 

oil transportation allowances reported 

on the monthly royalty report that 

exceeded the 50 percent limit for 

calendar years 2014–2018. As above, 

ONRR calculated the transportation 

allowance claimed for each royalty line 

compared to what the transportation 

allowance would have been at the 50 

percent limit. ONRR then calculated 

annual totals and averaged them over 

five years. The result in the proposed 

rule was an annual estimated decrease 

in royalties paid by industry of 

approximately $11,000 per year. ONRR 

is not adopting this regulation change. 

There is no change in estimated 

royalties. 

No Change in Royalties 3: Processing 

Allowances in Excess of 662⁄3 Percent of 

the Royalty Value of Federal NGLs Prior 

to Allowances 

Similar to the transportation 

allowance amendments, a lessee may 

incur costs required to process gas that 

exceed the regulatory limit of 662⁄3

percent of the royalty value of the NGLs 

prior to allowances. This rule does not 

provide a lessee the ability to request to 

exceed that limit. The annual number of 

requests to exceed allowance limits 

submitted by lessees to ONRR has 

decreased since a similar analysis was 

performed for the 2016 Valuation Rule. 

To estimate the change in royalties 

associated with the proposed 

amendment, ONRR completed two 

separate calculations. 

First ONRR identified all NGL 

processing allowances reported on the 

monthly royalty report that exceeded 

the 662⁄3 percent limit for calendar years 

2014–2018. Next, ONRR calculated the 

processing allowance claimed for each 

royalty line compared to what the 

processing allowance would have been 

at the 662⁄3 percent limit. ONRR then 

calculated annual totals and averaged 

them over five years. The result in the 

proposed rule was an annual estimated 

decrease in royalties paid by industry of 

approximately $135,000 per year. 

ONRR then calculated the estimated 

impact for processing allowances 

exceeding the 662⁄3 percent limit for 

POP contract sales. ONRR assumed the 

lessee retains 85 percent of the value of 

the residue and NGLs and the processor 

retains 15 percent. ONRR then assumed 

that 60 percent of the processor’s 

portion was allocable to transportation 

and the remaining 40 percent was 

processing. The total estimated 

processing allowance attributable to 

POP sales was $62,390,000. The 

estimated processing allowance limit 

attributable to POP sales was 

$137,316,000. ONRR found the potential 

processing allowances did not exceed 

the 662⁄3 percent limit and there would 

be no additional change in royalties 

from POP contract sales. ONRR is not 

adopting this regulation change. There 

is no change in estimated royalties. 

Comments on the Analysis of This 

Amendment 

Public Comment: One commenter 

identified to ONRR that its assumption 

to use a 70/30 split to represent POP 

contracts when estimating processing 

allowances in excess of 662⁄3 percent 

limit contradicted other ONRR materials 

and examples used in trainings and on 

the ONRR website. 

ONRR Response: ONRR reviewed 

several reference documents and further 

researched the appropriate split for 

these POP contracts and ONRR agrees 

with the commenter. ONRR 

acknowledges that its previous analysis 

did not adequately account for POP 

contracts and breaking out 

transportation and allowances from the 

fee in ONRR’s assumptions. ONRR 

revised its POP contract analysis of this 

impact in this provision. After using the 

85/15 POP contract split, as well as 

applying the 60/40 split for the 

processor’s portion being allocable to 

processing versus transportation, the 

estimated allowances no longer exceed 

the 662⁄3 percent threshold and the 

estimated royalty impact is eliminated. 

This change is reflected below. 

Change in Royalties 5: Extraordinary 

Gas Processing Cost Allowances for 

Federal Gas 

This rule allows a lessee to request an 

extraordinary processing cost 

allowance. Using the approvals ONRR 

granted prior to the 2016 Valuation 

Rule, ONRR identified the 127 leases 

claiming an extraordinary processing 

allowance for residue gas, sulfur, and 

CO2 for calendar years 2014–2018. The 

total processing costs are reported 

across all three products for these 

unique situations. For these leases, 

ONRR 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 in the 

analysis showed that the total 

allowances 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 for those same leases for residue 

gas. Based on these calculations, ONRR 

estimates this change will result in a 

decrease in annual royalty payments of 

approximately $11.1 million. 

ESTIMATED ANNUAL CHANGE IN ROYALTIES PAID

Annual Average Sulfur allowances in excess of 662⁄3% ..................................................................................................................... ($348,000) 

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

Estimated Impact on Royalties ............................................................................................................................................................ (11,131,000) 

Change in Royalties 6: Transportation 

Allowances for Certain OCS Gathering 

for Federal Oil and Gas 

The Deepwater Policy was in effect 

from 1999 until January 1, 2017. Under 

the Deepwater Policy, ONRR allowed a 

lessee to treat certain expenses for 

subsea gathering as transportation 

expenses and to deduct a portion of 

those costs from its royalty payments. 

The 2016 Valuation Rule rescinded the 

Deepwater Policy. To analyze the 

impact to industry of this regulation 

amendment, ONRR used data from the 

BSEE’s Technical Information 

Management System database to 

identify 113 current subsea pipeline 

segments, and potentially 169 eligible 

leases, which may qualify for an 

allowance under the Deepwater Policy. 

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 in active status and 

supporting leases in producing status. 

To determine the range (shown in the 

tables at the end of this section as low, 

mid, and high estimates) of changes to 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4647 

royalties, ONRR estimates 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. 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 return on 

investment using the average BBB Bond 

rate (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) for January 2018. 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 much be excluded from 

any calculation of a permissible 

deduction. ONRR chose these two 

percentages based on knowledge and 

information gathered during audits in 

the GOM. Finally, ONRR used an 

average royalty rate of 14 percent, which 

is the volume-weighted-average royalty 

rate for the non-Section 6 (See 43 U.S.C. 

1335(a)(9)) leases in the Gulf of Mexico. 

Based on these calculations, the average 

annual allowance per pipeline segment 

during the period when ONRR’s audit 

data was collected 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 represents the estimated 

amount per lease that ONRR would 

allow a lessee to take as a transportation 

allowance based on the Deepwater 

Policy. 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 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, will qualify for a 

deduction under the proposed 

amendment. 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. ONRR chose to 

estimate half of lessees for consistency 

with previous rulemaking analyses and 

to provide a basis for understanding of 

this change. ONRR decreased the low, 

mid, and high annual cost-to-industry 

estimates by 20 percent. The table below 

shows this section’s estimated royalty 

impact. 

ANNUAL ESTIMATED COST SAVINGS TO ALLOW DEEPWATER GATHERING

Low Mid High 

Royalty Impact ............................................................................................................................. $28,000,000 $32,900,000 $37,900,000 

The 2020 Proposed Rule proposed to 

allow a lessee to request, and ONRR to 

approve, applications for gathering-astransportation principles in water 

depths of 200 meters and shallower, if 

there is a subsea completion and the 

other requirements of the regulations are 

met. This provision was a part of the 

Deepwater Policy from its inception in 

1999 until expressly revoked by the 

2016 Valuation Rule. Neither MMS nor 

ONRR received any application to apply 

the Deepwater Policy to leases 

producing from OCS shallow waters. 

ONRR is not adopting this regulation 

change. There is no change in estimated 

royalties associated with gathering in 

depths 200 meters or shallower. 

Comments on the Analysis of This 

Amendment 

Public Comment: ONRR received a 

comment identifying what the 

commenter believed was an error in the 

calculation of the change in royalties 

related to transportation allowances for 

Deepwater gathering. 

ONRR Response: ONRR appreciates 

this comment and investigated potential 

errors in the formulas and data used for 

the calculation. ONRR revised the 

analysis for deepwater gathering. During 

the review of the proposed rule, ONRR 

found that calculation steps were not 

explained fully and identified that 

ONRR’s per segment value was 

overstated by nine percent attributable 

to the water content. ONRR also 

identified a miscalculation in the 2020 

Proposed Rule that did not accurately 

incorporate a reduction to account for 

the 20 percent of leases that were 

eligible and receiving royalty relief. 

ONRR revised the explanation of the 

formula and the calculations 

accordingly and it is reflected in the 

section below. 

Cost 1: Transportation Allowances for 

Certain OCS Gathering Costs for 

Offshore Federal Oil and Gas 

This rule, by allowing transportation 

allowances for deepwater gathering 

systems, will result in an administrative 

cost to industry because it requires 

qualified lessees to monitor their costs 

and perform calculations. The cost to 

perform these calculations is significant 

because industry often hires outside 

consultants to calculate their subsea 

transportation allowances. ONRR 

estimates that each lessee with leases 

eligible for transportation allowances for 

deepwater gathering systems will 

allocate one full-time employee 

annually to perform the calculation. 

ONRR used data from the BLS to 

estimate the hourly cost for industry 

accountants in a metropolitan area 

[$42.33 mean hourly wage] with a 

multiplier of 1.4 for industry benefits to 

equal approximately $59.26 per hour 

[$42.33 × 1.4 = $59.26]. Using this fullyburdened labor cost per hour, ONRR 

estimates that the annual administrative 

cost to industry would be approximately 

$3.9 million. 

4648 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

ANNUAL ADMINISTRATIVE COST TO INDUSTRY TO CALCULATE DEEPWATER TRANSPORTATION

Annual 

burden hours 

per company 

Industry 

labor cost/ 

hour 

Companies 

reporting 

eligible 

leases 

Estimated 

cost to 

industry 

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

No Administrative Cost 1: Request To 

Exceed Regulatory Allowance 

Limitation for Transportation and 

Processing 

In the proposed rule ONRR 

recognized the opportunity for a lessee 

to request to exceed the regulatory 

allowance limitation would result in an 

administrative cost to industry because 

qualified lessees will spend labor hours 

filling out the necessary form (form 

ONRR–4393). ONRR previously 

completed an Information Collection 

Request that included review of this 

ONRR form and identified the number 

of annual requests ONRR received and 

the estimated burden hours attributed to 

those requests each year. Using this 

information, ONRR calculated the cost 

to be: [$42.33 × 1.4 (including employee 

benefits) = $59.26 calculated mean 

hourly wage] × [19 average annual 

requests] × [57.68 labor hours to 

complete and submit form ONRR–4393]. 

In the proposed rule, ONRR estimated 

annual administrative costs to industry 

of approximately $65,000 but those 

costs will not be realized as ONRR is not 

adopting this regulation change. 

ANNUAL ADMINISTRATIVE COST TO INDUSTRY TO SUBMIT REQUESTS TO EXCEED ALLOWANCE LIMITS

Annual 

burden hours 

per company 

Industry 

labor cost/ 

hour 

Annual 

number of 

requests to 

exceed 

Estimated 

cost to 

industry 

Requests to Exceed Allowances ..................................................................... 58 $59.26 19 $65,000 

Cost Savings 1: Administrative Cost 

Savings From Using Index-Based 

Valuation Method To Value Federal 

Unprocessed Gas, Residue Gas, Fuel 

Gas, Coalbed Methane, and NGLs 

ONRR expects that industry will 

realize administrative-cost savings if 

lessees choose to use the index-based 

valuation method to value sales of 

Federal unprocessed gas, residue gas, 

fuel gas, coalbed methane, and NGLs. A 

lessee will have price certainty when 

calculating its royalties—saving time it 

currently spends on verifying gross 

proceeds. ONRR estimates that half of 

lessees will use the index-based 

valuation method. Further, ONRR 

estimates that it 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 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 savings to 

industry will be approximately $1.4 

million. 

ANNUAL ADMINISTRATIVE COST SAVINGS FOR INDUSTRY

Time burden 

per line 

reported 

Estimated 

lines 

reported 

using indexbased 

valuation 

method 

(50%) 

Annual 

burden hours 

Electronic Reporting (99%) .......................................................................................................... 1.5 min 892,620 22,315 

Manual Reporting (1%) ................................................................................................................ 3.5 min 9,016 526 

Industry Labor Cost/hour ............................................................................................................. ........................ ........................ $59.26 

Total Benefit to Industry ....................................................................................................... ........................ ........................ $1,354,000 

Cost Savings 2: Administrative Cost 

Savings Using Index-Based Valuation 

Method To Value Residue Gas and 

NGLs Simplifying Processing and 

Transportation Cost Calculations 

ONRR expects industry will realize an 

additional one-time administrative-cost 

savings if they choose to use the indexbased valuation method to value sales of 

Federal residue gas and NGLs, as this 

method eliminates the need to unbundle 

and calculate specific cost allocations 

related to processing and transportation. 

These cost allocations, referred to as 

‘‘unbundling,’’ are segregated portions 

of a transportation or processing 

expense or fee attributable to placing 

production in marketable condition. 

Industry would unbundle their 

applicable plants and transportation 

systems one time in the absence of this 

rule and then use those unbundled cost 

allocations for subsequent royalty 

calculations. Industry is responsible for 

calculating these costs, however ONRR 

has published and calculated a limited 

number of unbundling cost allocations. 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4649 

In ONRR’s experience, it takes 

approximately 100 hours per gas plant. 

ONRR calculated the average number of 

gas plants reported per payor is 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 this 

results in a one-time cost savings to 

industry of $4.5 million dollars. 

Change 1: Eliminate Reference To 

Default Provision Requirements for 

Federal Oil and Gas 

ONRR proposed to remove 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 will 

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. 

ONRR does not believe there is any 

overall royalty impact from removing 

the default provision. 

State and Local Governments 

ONRR estimates that States and 

certain local governments would receive 

an overall decrease in royalty share 

(which, in part, was a reason for 

California’s and New Mexico’s 

challenges to the 2017 Repeal Rule) 

based on the category the leases falls 

under, including offshore OCSLA 

section 8(g) leases (See 43 U.S.C. 

1337(g)), Gulf of Mexico Energy Security 

Act leases (‘‘GOMESA’’) ((43 U.S.C. 

1337(g))), and onshore Federal lands. 

ONRR disburses royalties based on 

where the oil, gas, or coal was 

produced. 

Except for Federal Alaskan 

production (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 

Please visit https://

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

on ONRR’s disbursements to any 

specific State or local government. 

The next table in this section 

summarizes the State and local 

government royalty decreases. 

Indian Lessors 

The provisions affecting royalties in 

this rule only apply to Federal oil and 

gas leases and are not expected to affect 

Indian lessors. 

Federal Government 

The impact of this rule to the Federal 

Government will be a net decrease in 

royalty collections. ONRR estimates the 

net yearly impact on the Federal 

Government (detailed in the next table 

of this section) would be a loss of 

$22,728,000 in royalties and the net 

effect to the Federal Government and 

the States would be a loss of 

$28,879,000 in combined royalties. 

Summary of Royalty Impacts and Costs 

to Industry, State and Local 

Governments, Indian Lessors, and the 

Federal Government 

In the table below, ONRR presents the 

net change in royalties by this 

rulemaking provision. Changes to 

royalties are neither costs nor benefits, 

but transfers. The estimated changes in 

royalties assessed will change both the 

costs incurred by an operator/lessee and 

the amount of revenue collected by the 

Federal Government and the States. 

ANNUAL ECONOMIC IMPACTS FOR INDUSTRY, THE FEDERAL GOVERNMENT, AND STATES

Rule provision Net change 

in royalties 

Federal 

portion 

State 

portion 

Index-Based Valuation Method Extended to Arm’s-Length Gas Sales ...................................... $5,620,000 $3,562,000 $2,058,000 

Index-Based Valuation Method Extended to Arm’s-Length NGL Sales ..................................... 21,141,000 14,248,000 6,893,000 

High to Midpoint Index Price for Non-Arm’s-Length Gas Sales ................................................. (4,488,000) (2,844,000) (1,644,000) 

Transportation Deduction Non-Arm’s-Length Index-Based Valuation Method ........................... (7,121,000) (4,513,000) (2,608,000) 

Extraordinary Processing Allowance ........................................................................................... (11,131,000) (7,054,000) (4,077,000) 

Allowance for Certain OCS Gathering Costs .............................................................................. (32,900,000) (26,127,000) (6,773,000) 

Total ......................................................................................................................................... (28,879,000) (22,728,000) (6,151,000) 

Note: Totals may not add due to rounding. 

Federal and Indian Coal 

ONRR estimates that there will be no 

economic impact in terms of royalties to 

ONRR, Tribes, individual Indian 

mineral owners, States, or industry from 

the changes to coal valuation in this 

rule. The changes outlined in this rule 

should result in coal values for royalty 

purposes similar to those reported and 

paid to ONRR under the regulations in 

effect since 1989. Further, as of this 

writing, lessees have not submitted coal 

reporting under the 2016 Valuation 

Rule, so ONRR lacks data showing any 

changes resulting from implementation 

of the provisions of the 2016 Valuation 

Rule. 

Change 2: Eliminating the Use of Arm’sLength Electricity Sales To Value NonArm’s-Length Dispositions of Federal 

Coal 

Comments on the Analysis of This 

Amendment 

Public Comment: ONRR received 

comments on this amendment 

expressing concerns about a potential 

4650 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

loophole where companies may be able 

to pay royalties on prices below fair 

market value. 

ONRR Response: ONRR appreciates 

the comment on this amendment but the 

commenter does not provide ONRR 

with enough information or evidence to 

calculate an economic impact of the 

loophole mentioned. 

In the 2016 Valuation Rule, ONRR 

estimated no impacts to industry for this 

provision. Further, because lessees have 

not submitted reporting under the 2016 

Valuation Rule, ONRR lacks data 

showing any changes that may have 

been attributable to this provision. 

Change 3: Using the First Arm’s-Length 

Sale To Value Non-Arm’s-Length Sales 

of Indian Coal 

ONRR did not estimate any impacts to 

industry for the proposed change from 

this provision. Currently, lessees of 

Indian coal sell their entire production 

at arm’s-length, so this proposed change 

would have no royalty impact on lessees 

or lessors of Indian coal. 

Change 4: Eliminating the Sales of 

Electricity To Value Non-Arm’s-Length 

Sales of Indian Coal 

ONRR did not estimate any impacts to 

industry for the proposed change for 

this provision. Currently, lessees of 

Indian coal sell their entire production 

at arm’s-length so this proposed change 

would have no royalty impact on lessees 

or lessors of Indian coal. 

Change 5: Using First Arm’s-Length Sale 

To Value Sales of Indian Coal Between 

Parties That Lack Opposing Economic 

Interests 

At the present time, all producers of 

Indian coal sell the produced coal under 

arm’s-length transactions. Accordingly, 

ONRR does not anticipate any impact to 

royalty collections from the proposed 

change. 

Change 6: Elimination of the Default 

Provision To Value Federal Oil, Gas, 

and Coal and Indian Coal 

ONRR estimates that the royalty 

impact would be insignificant because 

the default provision established a 

reasonable value of production using 

market-based transaction data, which 

has always been, and continues to be, 

the basis for ONRR’s royalty valuation 

rules. 

VI. Severability Statement 

If any provision, or portion of a 

provision, of this rule is found, by a 

court or tribunal of competent 

jurisdiction, to be invalid under the law, 

it shall be regarded as stricken while the 

remainder of this rule shall continue to 

be in full effect. 

VII. 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 the Office of Management 

and Budget (‘‘OMB’’) will review all 

significant rulemakings. OIRA has 

determined that this final rule is 

significant. Because the primary effect is 

on royalty payments, ONRR expects this 

final rule will largely result in transfers, 

which are described in the table below. 

ONRR also anticipates that this rule will 

result in $2.58 million in annual 

administrative costs and $4.52 million 

in one-time administrative cost savings. 

SUMMARY OF PROPOSED CHANGES TO

OIL & GAS ROYALTIES PAID

[Annual] 

Rule provision 

Net change in 

royalties 

paid by 

lessees 

Index-Based Valuation Method Extended to Arm’sLength Gas Sales ............. $5,620,000 

SUMMARY OF PROPOSED CHANGES TO

OIL & GAS ROYALTIES PAID—Continued 

[Annual] 

Rule provision 

Net change in 

royalties 

paid by 

lessees 

Index-Based Valuation Method Extended to Arm’sLength NGL Sales ............ 21,141,000 

High to Midpoint Index Price 

for Non-Arm’s-Length Gas 

Sales ................................. (4,488,000) 

Transportation Deduction 

Non-Arm’s-Length IndexBased Valuation Method ... (7,121,000) 

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

Allowance for Certain OCS 

Gathering Costs ................ (32,900,000) 

Total ............................... (28,879,000) 

SUMMARY OF ANNUAL ADMINISTRATIVE

IMPACTS TO INDUSTRY

Rule provision Cost 

(Cost savings) 

Administrative Cost Savings 

for Index-Based Valuation 

Method for Arm’s-Length 

Gas & NGL Sales ............. ($1,354,000) 

Administrative Cost for Allowances for Certain OCS 

Gathering .......................... 3,931,000 

Total ............................... 2,577,000 

ONE-TIME ADMINISTRATIVE IMPACTS

TO INDUSTRY

Rule provision (Cost savings) 

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

Time horizon 3% Discount 

rate 

7% Discount 

rate 

Administrative Costs over 10 years ......................................................................................................................... $18,100,000 $14,800,000 

Administrative Costs over 20 years ......................................................................................................................... 35,000,000 24,700,000 

To estimate the present value of 

potential future administrative cost to 

industry, ONRR looked at two different 

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 savings to industry in 

the first year this regulation is in effect 

and administrative costs each year 

thereafter. 

E.O. 13563 reaffirms the principles of 

E.O. 12866, while calling for 

improvements in the nation’s regulatory 

system to promote predictability, to 

reduce uncertainty, and to use the best, 

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 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4651 

freedom of choice for the public where 

these approaches are relevant, feasible, 

and consistent with regulatory 

objectives. E.O. 13563 emphasizes 

further 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 

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 211111, which includes 

companies that extract crude petroleum 

and natural gas; 

• Code 212111, which includes 

companies that extract surface coal; and 

• Code 212112, which includes 

companies that extract underground 

coal. 

Under NAICS code classifications, a 

small company is one with fewer than 

500 employees. ONNR updated its 

count since the 2020 Proposed Rule to 

estimate that approximately 1,208 

different companies submit royalty 

reports from 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 established for small 

businesses. ONRR estimated that the 

remaining 1,102 companies affected by 

this rule are small businesses. 

Accordingly, ONRR has not changed its 

initial determination from the 2020 

Proposed Rule that this rule will have 

an impact on a substantial number of 

small entities, but the economic impact 

on those small entities will not be 

significant. 

As stated in the Summary of Royalty 

Impacts and Costs Table, shown above, 

this rule would benefit industry through 

a reduction in royalties of 

approximately $28.9 million per year. 

Small businesses account for about 8 

percent of the royalties. Applying that 

percentage to industry costs, ONRR 

estimated that the changes in the final 

rule would result in a private cost 

savings to small business lessees of 

approximately $2.3 million per year, or 

$2,087 per small business, on average. 

The extent of an economic impact, if 

any, would vary between companies 

due to, for example, differences in the 

volume of production that the small 

business produces and sells each year. 

Furthermore, this rule does not require 

any business to incur new costs. 

Instead, this rule provides businesses 

with more flexibility as each entity, 

including small businesses, are able to 

determine whether it is economically 

advantageous to incur increases in 

administrative costs to reduce the 

royalties paid, based on an entity’s 

individual circumstances. ONRR 

believes that the economic impact to 

small businesses, if any, will be 

minimal. Accordingly, this rule will not 

result in a significant economic impact 

on those small businesses. 

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

ONRR hereby certifies that this rule will 

not have a significant economic impact 

on a substantial number of small entities 

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 

This final rule is not a major rule 

under 5 U.S.C. 804(2), the Small 

Business Regulatory Enforcement 

Fairness Act. This rule: 

(a) Does not have an annual effect on 

the economy of $100 million or more. 

ONRR estimates that the cumulative 

effect on all of industry will be a 

reduction in private cost of nearly 

$26.32 million per year, which is the 

sum of $28.9 million in decreased 

royalty payments and $2.58 million in 

additional costs due to increased 

administrative burdens. The net change 

in royalty payments is a transfer rather 

than a cost or cost savings. The 

Summary of Royalty Impacts and Costs 

Table, as shown above, demonstrates 

that the cumulative economic impact on 

industry, State and local governments, 

and the Federal Government will be 

well below the $100 million threshold 

that the Federal Government uses to 

define a rule as having a significant 

impact on the economy. 

(b) Will not cause a major increase in 

costs or prices for consumers, 

individual industries, Federal, State, or 

local government agencies, or 

geographic regions. Please see the data 

tables in the Regulatory Planning and 

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

above. 

(c) Does not have significant adverse 

effects on competition, employment, 

investment, productivity, innovation, or 

the ability of United States-based 

enterprises to compete with foreignbased enterprises. This rule is, in part, 

meant to incentivize domestic energy 

production. ONRR has estimated no 

significant adverse impacts to small 

business. 

D. Unfunded Mandates Reform Act 

The final rule does not impose an 

unfunded mandate on State, local, or 

Tribal governments, or the private sector 

of more than $100 million per year. This 

rule does not have a significant or 

unique effect on State, local, or Tribal 

governments, or the private sector. 

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 this rule is not an 

unfunded mandate. 

E. Takings (E.O. 12630) 

Under the criteria in section 2 of E.O. 

12630, the final rule does not have any 

significant takings implications. This 

rule does not impose conditions or 

limitations on the use of any private 

property. This rule applies to the 

valuation of Federal oil and gas and 

Federal and Indian coal only. The final 

rule only makes minor technical 

changes to ONRR’s civil penalty 

regulations that have no expected 

economic impact. The final rule does 

not require a takings implication 

assessment. 

F. Federalism (E.O. 13132) 

Under the criteria in section 1 of E.O. 

13132, the final rule does not have 

sufficient Federalism implications to 

warrant the preparation of a Federalism 

summary impact statement. The 

management of Federal oil and gas is 

the responsibility of the Secretary, and 

ONRR distributes all of the royalties that 

it collects under Federal oil and gas 

leases as directed by the relevant 

disbursement statutes. This rule does 

not impose administrative costs on 

States or local governments. This rule 

also does not substantially and directly 

affect the relationship between the 

Federal and State governments. Because 

this rule does not alter that relationship, 

it does not require a Federalism 

summary impact statement. 

4652 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

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

The final rule complies with the 

requirements of E.O. 12988. 

Specifically, this rule: 

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

which requires that ONRR review all 

regulations to eliminate errors and 

ambiguity and write them to minimize 

litigation. 

(b) 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) 

The Department strives to strengthen 

its government-to-government 

relationship with Indian tribes through 

a commitment to consultation with 

Indian tribes and recognition of their 

right to self-governance and tribal 

sovereignty. ONRR evaluated this final 

rule under the Department’s 

consultation policy and under the 

criteria in E.O. 13175 and have 

determined that it has no substantial 

direct effects on Federally-recognized 

Indian tribes. Thus, consultation under 

the Department’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 have no 

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 this 

rulemaking concludes that there is no 

substantial impact to the three tribes. 

Further, this rule estimates no impact to 

the royalty value of Indian coal. 

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

3501 et seq.) 

Certain collections of information 

require OMB’s approval under the 

Paperwork Reduction Act. This final 

rule does not require any new 

information collections subject to 

OMB’s approval. Thus, ONRR has not 

submitted any new information 

collection requests to OMB related to 

this rule. 

The final rule leaves 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 

This final rule does not constitute a 

major Federal action significantly 

affecting the quality of the human 

environment. ONRR is not required to 

provide a detailed statement under the 

National Environmental Policy Act of 

1969 (‘‘NEPA’’) because this rule 

qualifies for a categorical exclusion 

under 43 CFR 46.210(c) and (i) and the 

Department’s Departmental Manual, 

part 516, section 15.4.D: ‘‘(c) Routine 

financial transactions including such 

things as . . . audits, fees, bonds, and 

royalties . . . [and] (i) [p]olicies, 

directives, regulations, and guidelines 

. . . [t]hat are of an administrative, 

financial, legal, technical, or procedural 

nature.’’ ONRR also determined that this 

rule does not involved in 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) 

This final rule is not a significant 

energy action under the definition in 

E.O. 13211. It is not likely to have a 

significant adverse effect on the supply, 

distribution, or use of energy. Moreover, 

the Administrator of OIRA has not 

otherwise designated this 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.s 12866 (section 1(b)(12)), 12988 

(section 3(b)(1)(B)), and 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: 

(a) Logical organization. 

(b) Active voice to address readers 

directly. 

(c) Clear language rather than jargon. 

(d) Short sections and sentences. 

(e) Lists and tables wherever possible. 

If you believe that ONRR has not met 

these requirements, send your 

comments to Dane.Templin@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. 

M. Congressional Review Act 

Pursuant to the Congressional Review 

Act, 5 U.S.C. 801 et seq., OIRA has 

determined that this rulemaking is not 

a major rulemaking, as defined by 5 

U.S.C. 804(2), because this rulemaking 

has not resulted in, and is unlikely to 

result in: (1) An annual effect on the 

economy of $100,000,000 or more; (2) a 

major increase in costs or prices for 

consumers, individual industries, 

Federal, State, or local government, or 

geographic regions; or (3) significant 

adverse effects on competition, 

employment, investment, productivity, 

innovation, or on the ability of United 

States-based enterprises to compete 

with foreign-based enterprises in 

domestic and export markets. 

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. 

Kimbra G. Davis, 

Director for Office of Natural Resources 

Revenue. 

Authority and Issuance 

For the reasons discussed in the 

preamble, the Office of Natural 

Resources Revenue is amending 30 CFR 

parts 1206 and 1241 as set forth below: 

PART 1206—PRODUCT VALUATION 

■ 1. The authority citation for part 1206 

continues to read as follows: 

Authority: 5 U.S.C. 301 et seq., 25 U.S.C. 

396 et seq., 396a et seq., 2101 et seq.; 30 

U.S.C. 181 et seq., 351 et seq., 1001 et seq., 

1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 

et seq., 1331 et seq., and 1801 et seq. 

Subpart A—General Provisions and 

Definitions 

■ 2. Amend § 1206.20 by: 

■ a. Removing the definition of ‘‘coal 

cooperative’’; 

■ b. Revising the definition of 

‘‘gathering’’; and 

■ c. Removing the definition of 

‘‘misconduct’’. 

The revision reads as follows: 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4653 

§ 1206.20 What definitions apply to this 

part? 

* * * * * 

Gathering means the movement of 

lease production to a central 

accumulation or treatment point on the 

lease, unit, or communitized area, or to 

a central accumulation or treatment 

point off of the lease, unit, or 

communitized area that BLM or BSEE 

approves for onshore and offshore 

leases, respectively. Excluded from this 

definition is the movement of bulk 

production from a wellhead to an 

offshore platform which may, for 

valuation purposes, be considered a 

function for which a Transportation 

Allowance is properly taken pursuant to 

§§ 1206.110(a)(1) and 1206.152(a)(1). 

* * * * * 

Subpart C—Federal Oil 

■ 3. Amend § 1206.101 by: 

■ a. Revising paragraphs (a) 

introductory text, (c)(1) introductory 

text, and (c)(1)(i); and 

■ b. Adding paragraph (d). 

The revisions and addition read as 

follows: 

§ 1206.101 How do I calculate royalty value 

for oil I or my affiliate sell(s) under an 

arm’s-length contract? 

(a) The value of oil under this section 

for royalty purposes is the gross 

proceeds accruing to you or your 

affiliate under the arm’s-length contract 

less applicable allowances determined 

under § 1206.111 or 1206.112. This 

value does not apply if you exercise an 

option to use a different value provided 

in paragraph (c)(1) or (c)(2)(i) of this 

section, or if one of the exceptions in 

paragraph (d) of this section applies. 

You must use this paragraph (a) to value 

oil when: 

* * * * * 

(c)(1) If you enter into an arm’s-length 

exchange agreement, or multiple 

sequential arm’s-length exchange 

agreements, and following the 

exchange(s) that you or your affiliate 

sell(s) the oil received in the 

exchange(s) under an arm’s-length 

contract, then you may use either 

paragraph (a) of this section or 

§ 1206.102 to value your production for 

royalty purposes. If you fail to make the 

election required under this paragraph, 

you may not make a retroactive election. 

(i) If you use paragraph (a) of this 

section, your gross proceeds are the 

gross proceeds under your or your 

affiliate’s arm’s-length sales contract 

after the exchange(s) occur(s). You must 

adjust your gross proceeds for any 

location or quality differential, or other 

adjustments, that you received or paid 

under the arm’s-length exchange 

agreement(s). If ONRR determines that 

any arm’s-length exchange agreement 

does not reflect reasonable location or 

quality differentials, ONRR may require 

you to value the oil under § 1206.102. 

You may not otherwise use the price or 

differential specified in an arm’s-length 

exchange agreement to value your 

production. 

* * * * * 

(d) This paragraph contains 

exceptions to the valuation rule in 

paragraph (a) of this section. Apply 

these exceptions on an individual 

contract basis. 

(1) In conducting reviews and audits, 

if ONRR determines that any arm’slength sales contract does not reflect the 

total consideration actually transferred 

either directly or indirectly from the 

buyer to the seller, ONRR may require 

that you value the oil sold under that 

contract either under § 1206.102 or at 

the total consideration received. 

(2) You must value the oil under 

§ 1206.102 if ONRR determines that the 

value under paragraph (a) of this section 

does not reflect the reasonable value of 

the production due to either: 

(i) Misconduct by or between the 

parties to the arm’s-length contract; or 

(ii) Breach of your duty to market the 

oil for the mutual benefit of yourself and 

the lessor. 

■ 4. Amend § 1206.102 by revising the 

introductory text and paragraphs (d) and 

(e) to read as follows: 

§ 1206.102 How do I value oil not sold 

under an arm’s-length contract? 

This section explains how to value oil 

that you may not value under 

§ 1206.101 or that you elect under 

§ 1206.101(c)(1) to value under this 

section. First, determine if paragraph 

(a), (b), or (c) of this section applies to 

production from your lease, or if you 

may apply paragraph (d) or (e) with 

ONRR’s approval. 

* * * * * 

(d) Unreasonable value. If ONRR 

determines that the NYMEX price or 

ANS spot price does not represent a 

reasonable royalty value in any 

particular case, ONRR may establish a 

reasonable royalty value based on other 

relevant matters. 

(e) Production delivered to your 

refinery and the NYMEX price or ANS 

spot price is an unreasonable value. (1) 

Instead of valuing your production 

under paragraph (a), (b), or (c) of this 

section, you may apply to ONRR to 

establish a value representing the 

market at the refinery if: 

(i) You transport your oil directly to 

your or your affiliate’s refinery, or 

exchange your oil for oil delivered to 

your or your affiliate’s refinery; and 

(ii) You must value your oil under 

this section at the NYMEX price or ANS 

spot price; and 

(iii) You believe that use of the 

NYMEX price or ANS spot price results 

in an unreasonable royalty value. 

(2) You must provide adequate 

documentation and evidence 

demonstrating the market value at the 

refinery. That evidence may include, 

but is not limited to: 

(i) Costs of acquiring other crude oil 

at or for the refinery; 

(ii) How adjustments for quality, 

location, and transportation were 

factored into the price paid for other oil; 

(iii) Volumes acquired for and refined 

at the refinery; and 

(iv) Any other appropriate evidence or 

documentation that ONRR requires. 

(3) If ONRR establishes a value 

representing market value at the 

refinery, you may not take an allowance 

against that value under § 1206.113(b) 

unless it is included in ONRR’s 

approval. 

■ 5. Amend § 1206.104 by revising 

paragraphs (a)(1), (b), (c) introductory 

text, (c)(2), (g)(1), and (2) to read as 

follows: 

§ 1206.104 How will ONRR determine if my 

royalty payments are correct? 

(a)(1) ONRR may monitor, review, and 

audit the royalties that you report, and, 

if ONRR determines that your reported 

value is inconsistent with the 

requirements of this subpart, ONRR may 

establish a reasonable royalty value 

based on other relevant matters. 

* * * * * 

(b) ONRR may examine whether your 

or your affiliate’s contract reflects the 

total consideration transferred for 

Federal oil, either directly or indirectly, 

from the buyer to you or your affiliate. 

If ONRR determines that additional 

consideration beyond that reflected in 

the contract was transferred, or that any 

portion of the consideration was not 

included in gross proceeds reported, 

ONRR may establish a reasonable 

royalty value based on other relevant 

matters. 

(c) ONRR may establish a reasonable 

royalty value based on other relevant 

matters if ONRR determines that the 

gross proceeds accruing to you or your 

affiliate under a contract do not reflect 

reasonable consideration because: 

* * * * * 

(2) You have breached your duty to 

market the oil for the mutual benefit of 

yourself and the lessor; or 

* * * * * 

4654 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

(g)(1) You or your affiliate must make 

all contracts, contract revisions, or 

amendments in writing. 

(2) If you or your affiliate fail(s) to 

comply with paragraph (g)(1) of this 

section, ONRR may establish a 

reasonable royalty value based on other 

relevant matters. 

* * * * * 

§ 1206.105 [Removed and Reserved] 

■ 6. Remove and reserve § 1206.105. 

■ 7. Amend § 1206.108 by: 

■ a. Revising paragraphs (a) 

introductory text and (a)(5); and 

■ b. Removing the words ‘‘Assistant 

Secretary’’ in paragraphs (c)(2), (c)(3), 

(d)(1), (e), (f), and (g) and adding in their 

place the words ‘‘Assistant Secretary for 

Policy, Management and Budget’’. 

The revisions read as follows: 

§ 1206.108 How do I request a valuation 

determination? 

(a) You may request a valuation 

determination from ONRR regarding any 

oil produced. Your request must comply 

with all of the following: 

* * * * * 

(5) Provide your analysis of the 

issue(s); 

* * * * * 

■ 8. Amend § 1206.110 by revising 

paragraphs (a), (f) introductory text and 

(f)(2) to read as follows: 

§ 1206.110 What general transportation 

allowance requirements apply to me? 

(a)(1) ONRR will allow a deduction 

for the reasonable, actual costs to 

transport oil from the lease to the point 

off of the lease under § 1206.110, 

1206.111, or 1206.112, as applicable. 

You may not deduct transportation costs 

that you incur to move a particular 

volume of production to reduce 

royalties that you owe on production for 

which you did not incur those costs. 

This paragraph applies when: 

(i) You value oil under § 1206.101 

based on a sale at a point off of the lease, 

unit, or communitized area from which 

the oil is produced; or 

(ii) You do not value your oil under 

§ 1206.102(a)(3) or (b)(3). 

(2) You may not include any gathering 

costs in your transportation allowance 

under § 1206.110, 1206.111, or 

1206.112, as applicable, except those 

reasonable, actual gathering costs you 

incur for oil produced from a lease or 

unit on the OCS, any part of which lies 

in waters deeper than 200 meters, that 

meet all of the following criteria: 

(i) The gathering costs are for oil for 

which you are entitled to take a 

transportation allowance under 

paragraph (a)(1) of this section; 

(ii) The gathering costs are for 

movement of oil beyond a central 

accumulation point. For purposes of 

paragraph (a)(2) of this section, a central 

accumulation point may be a single 

well, a subsea manifold, the last well in 

a group of wells connected in a series, 

or a platform extending above the 

surface of the water; 

(iii) The gathering costs are for 

movement of oil to a facility that is not 

located on a lease or unit adjacent to the 

lease or unit on which the production 

originates. For purposes of paragraph 

(a)(2) of this section, an adjacent lease 

or unit is any lease or unit with at least 

one point of contact with the producing 

lease or unit. Typically, for a single OCS 

lease, there are 8 adjacent leases; and 

(iv) The gathering costs are only those 

allocable to the royalty-bearing oil. 

Gathering costs properly allocable to 

non-royalty bearing substances, or any 

royalty-bearing substance other than oil, 

may not be included in your 

transportation allowance under this 

section. 

* * * * * 

(f) ONRR may direct you to modify 

your transportation allowance if: 

* * * * * 

(2) ONRR determines that the 

consideration that you or your affiliate 

paid under an arm’s-length 

transportation contract does not reflect 

the reasonable cost of the transportation 

because you breached your duty to 

market the oil for the mutual benefit of 

yourself and the lessor by transporting 

your oil at a cost that is unreasonably 

high; or 

* * * * * 

■ 9. Amend § 1206.111 by: 

■ a. Removing paragraph (d)(1) 

■ b. Redesignating paragraph (d) 

introductory text as (d)(1); 

■ c. Revising newly redesignated 

paragraph (d)(1); and 

■ d. Removing the word ‘‘may’’ in 

paragraph (d)(2) and adding in its place 

the word ‘‘must’’. 

The revision reads as follows: 

§ 1206.111 How do I determine a 

transportation allowance if I have an arm’s 

length transportation contract? 

* * * * * 

(d)(1) If you have no written contract 

for the arm’s-length transportation of 

oil, you must propose to ONRR a 

method to determine the allowance 

using the procedures in § 1206.108(a). 

* * * * * 

■ 10. Amend § 1206.117 by revising 

paragraph (a) to read as follows: 

§ 1206.117 What interest and penalties 

apply if I improperly report a transportation 

allowance? 

(a) If you deduct a transportation 

allowance on form ONRR–2014 that 

exceeds 50 percent of the value of the 

oil transported without obtaining 

ONRR’s prior approval under 

§ 1206.110(d)(2), you must pay 

additional royalties due, plus late 

payment interest calculated under 

§§ 1218.54 and 1218.102 of this chapter, 

on the excess allowance amount taken 

from the date when that amount is taken 

to the date when you file an exception 

request that ONRR approves. If you do 

not file an exception request, or if ONRR 

does not approve your request, you 

must pay late payment interest on the 

excess allowance amount taken from the 

date that amount is taken until the date 

you pay the additional royalties owed. 

* * * * * 

Subpart D—Federal Gas 

■ 11. Amend § 1206.141 by: 

■ a. Revising paragraphs (a)(2), (b) 

introductory text, (b)(2), (b)(3), (c) 

introductory text, (c)(1)(i), (c)(1)(ii), 

(c)(1)(iv), (c)(1)(vi), and (e)(2) 

introductory text; 

■ b. Removing the word ‘‘may’’ in 

paragraph (e)(2)(ii) and adding in its 

place the word ‘‘must’’; and 

■ c. Adding paragraphs (f) and (g). 

The revisions and additions read as 

follows: 

§ 1206.141 How do I calculate royalty value 

for unprocessed gas that I or my affiliate 

sell(s) under an arm’s-length or non-arm’s 

length contract? 

(a) * * * 

(2) Any gas that you are not required 

to value under § 1206.142; or 

* * * * * 

(b) The value of gas under this section 

for royalty purposes is the gross 

proceeds accruing to you or your 

affiliate under the first arm’s-length 

contract less a transportation allowance 

determined under § 1206.152. This 

value does not apply if you exercise the 

option in paragraph (c) of this section. 

Unless you elect to value your gas under 

paragraph (c) of this section, you must 

use this paragraph (b) to value gas 

when: 

* * * * * 

(2) You sell or transfer unprocessed 

gas to your affiliate or another person 

under a non-arm’s-length contract and 

that affiliate or person, or an affiliate of 

either of them, then sells the gas under 

an arm’s-length contract; 

(3) You, your affiliate, or another 

person sell(s) unprocessed gas produced 

from a lease under multiple arm’s length 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4655 

contracts, and that gas is valued under 

this paragraph. The value of the gas is 

the volume-weighted average of the 

values, established under this 

paragraph, for each contract for the sale 

of gas produced from that lease; or 

* * * * * 

(c) Alternatively, you may elect to 

value your unprocessed gas under this 

paragraph (c), which allows you to use 

an index-based valuation method to 

calculate royalty value. You may not 

change your election more often than 

once every two years. 

(1)(i) If you can only transport gas to 

one index pricing point published in an 

ONRR-approved publication, available 

at www.onrr.gov, your value, for royalty 

purposes, is the published average 

bidweek price to which your gas may 

flow for that respective production 

month. 

(ii) If you can transport gas to more 

than one index pricing point published 

in an ONRR-approved publication 

available at www.onrr.gov, your value, 

for royalty purposes, is the highest of 

the published average bidweek prices to 

which your gas may flow for that 

respective production month, whether 

or not there are constraints for that 

production month. 

* * * * * 

(iv) You may adjust the number 

calculated under paragraphs (c)(1)(i) 

and (ii) of this section by reducing the 

value by 10 percent, but not less than 

10 cents per MMBtu nor more than 40 

cents per MMBtu for sales from the OCS 

Gulf of Mexico and by 15 percent, but 

not less than 10 cents per MMBtu nor 

more than 50 cents per MMBtu, for sales 

from all other areas. 

* * * * * 

(vi) ONRR may exclude an individual 

index pricing point found in an ONRRapproved publication if ONRR 

determines that the index pricing point 

does not accurately reflect the values of 

production. ONRR will publish criteria 

for index pricing points available at 

www.onrr.gov. 

* * * * * 

(e) * * * 

(2) There is not an index pricing point 

for the gas, then: 

* * * * * 

(f) Under no circumstances may your 

gas be valued for royalty purposes at 

less than zero. 

(g) If you elect to value your gas under 

paragraph (c) of this section, ONRR 

reserves the right to collect actual 

transaction data in the future to assess 

the validity of the index-based valuation 

option. 

■ 12. Amend § 1206.142 by: 

■ a. Revising paragraphs (c) 

introductory text, (c)(2), (c)(3), (d)(1)(i), 

(d)(1)(ii), (d)(1)(iv), and (d)(1)(vi); 

■ b. Removing the word ‘‘methodology’’ 

from paragraph (d)(2)(ii) and adding in 

its place the word ‘‘method’’; 

■ c. Removing the word ‘‘may’’ in 

paragraph (d)(2)(iii) and adding in its 

place the word ‘‘must’’; 

■ d. Revising paragraph (f)(2) 

introductory text; 

■ e. Removing the word ‘‘may’’ in 

paragraph (f)(2)(ii) and adding in its 

place the word ‘‘must’’; and 

■ f. Adding paragraphs (g) and (h). 

The revisions and additions read as 

follows: 

§ 1206.142 How do I calculate royalty value 

for processed gas that I or my affiliate 

sell(s) under an arm’s-length or non-arm’s 

length contract? 

* * * * * 

(c) The value of residue gas or any gas 

plant product under this section for 

royalty purposes is the gross proceeds 

accruing to you or your affiliate under 

the first arm’s-length contract. This 

value does not apply if you exercise the 

option provided in paragraph (d) of this 

section. Unless you exercise the option 

provided in paragraph (d) of this 

section, you must use this paragraph (c) 

to value residue gas or any gas plant 

product when: 

* * * * * 

(2) You sell or transfer to your affiliate 

or another person under a non-arm’s 

length contract, and that affiliate or 

person, or another affiliate of either of 

them, then sells the residue gas or any 

gas plant product under an arm’s-length 

contract; 

(3) You, your affiliate, or another 

person sell(s), under multiple arm’slength contracts, residue gas or any gas 

plant products recovered from gas 

produced from a lease that you value 

under this paragraph. In that case, 

because you sold non-arm’s-length to 

your affiliate or another person, the 

value of the residue gas or any gas plant 

product is the volume-weighted average 

of the gross proceeds established under 

this paragraph for each arm’s-length 

contract for the sale of residue gas or 

any gas plant products recovered from 

gas produced from that lease; or 

* * * * * 

(d) Alternatively, you may elect to 

value your residue gas and NGLs under 

this paragraph (d). You may not change 

your election more often than once 

every two years. 

(1)(i) If you can only transport residue 

gas to one index pricing point published 

in an ONRR-approved publication 

available at www.onrr.gov, your value, 

for royalty purposes, is the published 

average bidweek price to which your gas 

may flow for that respective production 

month. 

(ii) If you can transport residue gas to 

more than one index pricing point 

published in an ONRR-approved 

publication available at www.onrr.gov, 

your value, for royalty purposes, is the 

highest of the published average 

bidweek prices to which your gas may 

flow for that respective production 

month, whether or not there are 

constraints for that production month. 

* * * * * 

(iv) You may adjust the number 

calculated under paragraphs (d)(1)(i) 

and (ii) of this section by reducing the 

value by 10 percent, but not less than 

10 cents per MMBtu nor more than 40 

cents per MMBtu for sales from the OCS 

Gulf of Mexico and by 15 percent, but 

not less than 10 cents per MMBtu nor 

more than 50 cents per MMBtu for sales 

from all other areas. 

* * * * * 

(vi) ONRR may exclude an individual 

index pricing point found in an ONRRapproved publication if ONRR 

determines that the index pricing point 

does not accurately reflect the values of 

production. ONRR will publish criteria 

for index pricing points on 

www.onrr.gov. 

* * * * * 

(f) * * * 

(2) There is not an index pricing point 

or commercial price bulletin for the gas, 

then: 

* * * * * 

(g) Under no circumstances may your 

gas be valued for royalty purposes at 

less than zero. 

(h) If you elect to value your gas 

under paragraph (d) of this section, 

ONRR reserves the right to collect actual 

transaction data in the future to assess 

the validity of the index-based valuation 

option. 

■ 13. Amend § 1206.143 by revising 

paragraphs (a)(1), (b), (c) introductory 

text, (c)(2), (g)(1), and (g)(2) to read as 

follows: 

§ 1206.143 How will ONRR determine if my 

royalty payments are correct? 

(a)(1) ONRR may monitor, review, and 

audit the royalties that you report. If 

ONRR determines that your reported 

value is inconsistent with the 

requirements of this subpart, ONRR will 

direct you to use a different measure of 

royalty value. 

* * * * * 

(b) ONRR may examine whether your 

or your affiliate’s contract reflects the 

total consideration transferred for 

Federal gas, either directly or indirectly, 

from the buyer to you or your affiliate. 

4656 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

If ONRR determines that additional 

consideration beyond that reflected in 

the contract was transferred, or that any 

portion of the consideration was not 

included in gross proceeds reported, 

ONRR may establish a reasonable 

royalty value based on other relevant 

matters. 

(c) ONRR may direct you to use a 

different measure of royalty value if 

ONRR determines that the gross 

proceeds accruing to you or your 

affiliate under a contract do not reflect 

reasonable consideration because: 

* * * * * 

(2) You have breached your duty to 

market the gas, residue gas, or gas plant 

products for the mutual benefit of 

yourself and the lessor; or 

* * * * * 

(g)(1) You or your affiliate must make 

all contracts, contract revisions, or 

amendments in writing. 

(2) If you or your affiliate fail(s) to 

comply with paragraph (g)(1) of this 

section, ONRR may direct you to use a 

different measure of royalty value. 

* * * * * 

§ 1206.144 [Removed and Reserved] 

■ 14. Remove and reserve § 1206.144. 

■ 15. Amend § 1206.148 by: 

■ a. Revising paragraphs (a) 

introductory text and (a)(5); and 

■ b. Removing the words ‘‘Assistant 

Secretary’’ in paragraphs (c)(2), (c)(3), 

(d)(1), (e), and (f) and adding in their 

place the words ‘‘Assistant Secretary for 

Policy, Management and Budget’’. 

The revisions read as follows: 

§ 1206.148 How do I request a valuation 

determination? 

(a) You may request a valuation 

determination from ONRR regarding any 

gas produced. Your request must 

comply with all of the following: 

* * * * * 

(5) Provide your analysis of the 

issue(s); 

* * * * * 

■ 16. Amend § 1206.152 by revising 

paragraph (a), (g) introductory text, and 

(g)(2) to read as follows: 

§ 1206.152 What general transportation 

allowance requirements apply to me? 

(a)(1) ONRR will allow a deduction 

for the reasonable, actual costs to 

transport residue gas, gas plant 

products, or unprocessed gas from the 

lease to the point off of the lease under 

§ 1206.152, 1206.153, or 1206.154, as 

applicable. You may not deduct 

transportation costs that you incur when 

moving a particular volume of 

production to reduce royalties that you 

owe on production for which you did 

not incur those costs. This paragraph 

applies when you value unprocessed 

gas under § 1206.141(b) or residue gas 

and gas plant products under 

§ 1206.142(b) based on a sale at a point 

off of the lease, unit, or communitized 

area from which the residue gas, gas 

plant products, or unprocessed gas is 

produced. 

(2) You may not include any gathering 

costs in your transportation allowance 

under § 1206.152, 1206.153, or 

1206.154, as applicable, except those 

reasonable, actual gathering costs you 

incur for residue gas, gas plant products, 

or unprocessed gas produced from a 

lease or unit on the OCS, any part of 

which lies in waters deeper than 200 

meters, that meet all of the following 

criteria: 

(i) The gathering costs are for residue 

gas, gas plant products, or unprocessed 

gas for which you are entitled to take a 

transportation allowance under 

paragraph (a)(1) of this section; 

(ii) The gathering costs are for 

movement of residue gas, gas plant 

products, or unprocessed gas beyond a 

central accumulation point. For 

purposes of paragraph (a)(2) of this 

section, a central accumulation point 

may be a single well, a subsea manifold, 

the last well in a group of wells 

connected in a series, or a platform 

extending above the surface of the 

water; 

(iii) The gathering costs are for 

movement of residue gas, gas plant 

products, or unprocessed gas to a 

facility that is not located on a lease or 

unit adjacent to the lease or unit on 

which the production originates. For 

purposes of paragraph (a)(2) of this 

section, an adjacent lease or unit is any 

lease or unit with at least one point of 

contact with the producing lease or unit. 

Typically, for a single OCS lease, there 

are 8 adjacent leases; and 

(iv) The gathering costs are only those 

allocable to the royalty-bearing residue 

gas, gas plant products, or unprocessed 

gas. Gathering costs properly allocable 

to non-royalty bearing substances, or 

any royalty-bearing substance other than 

residue gas, gas plant products, or 

unprocessed gas, may not be included 

in a transportation allowance under this 

section. 

* * * * * 

(g) ONRR may direct you to modify 

your transportation allowance if: 

* * * * * 

(2) ONRR determines that the 

consideration that you or your affiliate 

paid under an arm’s-length 

transportation contract does not reflect 

the reasonable cost of the transportation 

because you breached your duty to 

market the gas, residue gas, or gas plant 

products for the mutual benefit of 

yourself and the lessor; or 

* * * * * 

■ 17. Amend § 1206.153 by revising 

paragraph (d) to read as follows: 

§ 1206.153 How do I determine a 

transportation allowance if I have an arm’slength transportation contract? 

* * * * * 

(d) If you have no written contract for 

the arm’s-length transportation of gas, 

and neither you nor your affiliate 

perform your own transportation, you 

must propose to ONRR a method to 

determine the transportation allowance 

using the procedures in § 1206.148(a). 

(1) You must use that method to 

determine your allowance until ONRR 

issues its determination. 

(2) [Reserved] 

■ 18. Amend § 1206.157 by revising 

paragraph (b) to read as follows: 

§ 1206.157 What interest and penalties 

apply if I improperly report a transportation 

allowance? 

* * * * * 

(b) If you deduct a transportation 

allowance on form ONRR–2014 that 

exceeds 50 percent of the value of the 

gas, residue gas, or gas plant products 

transported without obtaining ONRR’s 

prior approval under § 1206.152(e)(2), 

you must pay additional royalties due, 

plus late payment interest calculated 

under §§ 1218.54 and 1218.102 of this 

chapter, on the excess allowance 

amount taken from the date when that 

amount is taken to the date when you 

file an exception request that ONRR 

approves. If you do not file an exception 

request, or if ONRR does not approve 

your request, you must pay late 

payment interest on the excess 

allowance amount taken from the date 

that amount is taken until the date you 

pay the additional royalties owed. 

* * * * * 

■ 19. Amend § 1206.159 by: 

■ a. Revising paragraph (c)(1); 

■ b. Adding paragraph (c)(5); 

■ c. Redesignating paragraphs (d)(2)(A) 

and (B) as (d)(2)(i) and (ii); and 

■ d. Revising paragraphs (e) 

introductory text and (e)(2). 

The revisions and additions read as 

follows: 

§ 1206.159 What general processing 

allowances requirements apply to me? 

* * * * * 

(c)(1) You may not apply the 

processing allowance against the value 

of the residue gas, except as provided in 

paragraph (c)(5) of this section. 

* * * * * 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4657 

(5) If you incur extraordinary costs for 

processing gas, you may apply to ONRR 

for an allowance for those costs which 

must be in addition to any other 

processing allowance to which the 

lessee is entitled pursuant to this 

section. You must demonstrate that the 

costs are, by reference to standard 

industry conditions and practice, 

extraordinary, unusual, or 

unconventional. You are not required to 

receive ONRR approval to continue an 

extraordinary processing allowance. 

However, you must report the deduction 

to ONRR in a form and manner 

prescribed by ONRR in order to retain 

the ability to deduct the allowance. 

* * * * * 

(e) ONRR may direct you to modify 

your processing allowance if: 

* * * * * 

(2) ONRR determines that the 

consideration that you or your affiliate 

paid under an arm’s-length processing 

contract does not reflect the reasonable 

cost of the processing because you 

breached your duty to market the gas, 

residue gas, or gas plant products for the 

mutual benefit of yourself and the 

lessor; or 

* * * * * 

■ 20. Amend § 1206.160 by: 

■ Revising paragraphs (a)(1) and (c), to 

read as follows: 

§ 1206.160 How do I determine a 

processing allowance if I have an arm’s 

length processing contract? 

(a)(1) If you or your affiliate incur 

processing costs under an arm’s-length 

processing contract, you may claim a 

processing allowance for the reasonable, 

actual costs incurred, as more fully 

explained in paragraph (b) of this 

section, except as provided in 

§ 1206.159(e) and subject to the 

limitation in § 1206.159(c)(2). 

* * * * * 

(c) If you have no written contract for 

the arm’s-length processing of gas, and 

neither you nor your affiliate perform 

your own processing, you must propose 

to ONRR a method to determine the 

processing allowance using the 

procedures in § 1206.148(a). 

(1) You must use that method to 

determine your allowance until ONRR 

issues a determination. 

(2) [Reserved] 

■ 21. Amend § 1206.164 by revising 

paragraph (b) to read as follows: 

§ 1206.164 What interest and penalties 

apply if I improperly report a processing 

allowance? 

* * * * * 

(b) If you deduct a processing 

allowance on form ONRR–2014 that 

exceeds 662⁄3 percent of the value of a 

gas plant product without obtaining 

ONRR’s prior approval under 

§ 1206.159(c)(3), you must pay 

additional royalties due, plus late 

payment interest calculated under 

§§ 1218.54 and 1218.102 of this chapter, 

on the excess allowance amount taken 

from the date when that amount is taken 

to the date when you file an exception 

request that ONRR approves. If you do 

not file an exception request, or if ONRR 

does not approve your request, you 

must pay late payment interest on the 

excess allowance amount taken from the 

date that amount is taken until the date 

you pay the additional royalties owed. 

* * * * * 

Subpart F—Federal Coal 

■ 22. Amend § 1206.252 by revising 

paragraph (a) introductory text, (b) and 

removing and reserving paragraph (c) to 

read as follows: 

§ 1206.252 How do I calculate royalty value 

for coal? 

(a) The value of coal under this 

section for royalty purposes is the gross 

proceeds accruing to you or your 

affiliate under the first arm’s-length 

contract, or another person, less an 

applicable transportation allowance 

determined under §§ 1206.260 through 

1206.262 and washing allowance under 

§§ 1206.267 through 1206.269. You 

must use this paragraph (a) to value coal 

when: 

* * * * * 

(b) If you have no contract for the sale 

of coal subject to this section because 

you or your affiliate used the coal in a 

power plant that you or your affiliate 

own(s) for the generation and sale of 

electricity: 

(1) You must propose to ONRR a 

method to determine the value using the 

procedures in § 1206.258(a). 

(2) You must use that method to 

determine value, for royalty purposes, 

until ONRR issues a determination. 

(3) After ONRR issues a 

determination, you must make the 

adjustments under § 1206.253(a)(2). 

* * * * * 

■ 23. Amend § 1206.253 by revising 

paragraphs (a)(1), (b), (c) introductory 

text, (c)(2), (g)(1) and (2) to read as 

follows: 

§ 1206.253 How will ONRR determine if my 

royalty payments are correct? 

(a)(1) ONRR may monitor, review, and 

audit the royalties that you report, and, 

if ONRR determines that your reported 

value is inconsistent with the 

requirements of this subpart, ONRR may 

establish a reasonable royalty value 

based on other relevant matters. 

* * * * * 

(b) ONRR may examine whether your 

or your affiliate’s contract reflects the 

total consideration transferred for 

Federal coal, either directly or 

indirectly, from the buyer to you or your 

affiliate. If ONRR determines that 

additional consideration beyond that 

reflected in the contract was transferred, 

or that any portion of the consideration 

was not included in gross proceeds 

reported, ONRR may establish a 

reasonable royalty value based on other 

relevant matters. 

(c) ONRR may establish a reasonable 

royalty value based on other relevant 

matters if ONRR determines that the 

gross proceeds accruing to you or your 

affiliate under a contract do not reflect 

reasonable consideration because: 

* * * * * 

(2) You breached your duty to market 

the coal for the mutual benefit of 

yourself and the lessor; or 

* * * * * 

(g)(1) You or your affiliate must make 

all contracts, contract revisions, or 

amendments in writing. 

(2) If you or your affiliate fail(s) to 

comply with paragraph (g)(1) of this 

section, ONRR may establish a 

reasonable royalty value based on other 

relevant matters. 

* * * * * 

§ 1206.254 [Removed and Reserved] 

■ 24. Remove and reserve § 1206.254. 

■ 25. Amend § 1206.258 by: 

■ a. Revising paragraphs (a) 

introductory text and (a)(5); 

■ b. Removing the words ‘‘Assistant 

Secretary’’ in paragraphs (c)(2), (c)(3), 

(e), and (f) and adding in their place the 

words ‘‘Assistant Secretary for Policy, 

Management and Budget’’; 

■ c. Revising paragraph (g); and 

■ d. Adding paragraph (h). 

The revisions and additions read as 

follows: 

§ 1206.258 How do I request a valuation 

determination? 

(a) You may request a valuation 

determination from ONRR regarding any 

coal produced. Your request must 

comply with all of the following: 

* * * * * 

(5) Provide your analysis of the 

issue(s); 

* * * * * 

(g) ONRR or the Assistant Secretary 

for Policy, Management and Budget 

generally will not retroactively modify 

or rescinds a valuation determination 

issued under paragraph (d) of this 

section, unless: 

4658 Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 

(1) There was a misstatement or 

omission of material facts; or 

(2) The facts subsequently developed 

are materially different from the facts on 

which the guidance was based. 

(h) ONRR may make requests and 

replies under this section available to 

the public, subject to the confidentiality 

requirements under § 1206.259. 

■ 26. Amend § 1206.260 by revising 

paragraphs (g) introductory text and 

(g)(2) to read as follows: 

§ 1206.260 What general transportation 

allowance requirements apply to me? 

* * * * * 

(g) ONRR may determine your 

transportation allowance if: 

* * * * * 

(2) ONRR determines that the 

consideration that you or your affiliate 

paid under an arm’s-length 

transportation contract does not reflect 

the reasonable cost of the transportation 

because you breached your duty to 

market the coal for the mutual benefit of 

yourself and the lessor by transporting 

your coal at a cost that is unreasonably 

high; or 

* * * * * 

■ 27. Amend § 1206.261 by revising 

paragraph (c) to read as follows: 

§ 1206.261 How do I determine a 

transportation allowance if I have an arm’slength transportation contract? 

* * * * * 

(c) If you have no written contract for 

the arm’s-length transportation of coal, 

and neither you nor your affiliate 

perform your own transportation, you 

must propose to ONRR a method to 

determine the transportation allowance 

using the procedures in § 1206.258(a). 

(1) You must use that method to 

determine your allowance until ONRR 

issues a determination. 

(2) [Reserved] 

■ 28. Amend § 1206.267 by revising 

paragraphs (d) introductory text and 

(d)(2) to read as follows: 

§ 1206.267 What general washing 

allowance requirements apply to me? 

* * * * * 

(d) ONRR may direct you to modify 

your washing allowance if: 

* * * * * 

(2) ONRR determines that the 

consideration that you or your affiliate 

paid under an arm’s-length washing 

contract does not reflect the reasonable 

cost of the washing because you 

breached your duty to market the coal 

for the mutual benefit of yourself and 

the lessor by washing your coal at a cost 

that is unreasonably high; or 

* * * * * 

■ 29. Amend § 1206.268 by revising 

paragraphs (b) and (c) to read as follows: 

§ 1206.268 How do I determine washing 

allowances if I have an arm’s-length 

washing contract or no written arm’s-length 

contract? 

* * * * * 

(b) You must be able to demonstrate 

that your or your affiliate’s washing 

contract is arm’s-length. 

(c) If you have no written contract for 

the arm’s-length washing of coal, and 

neither you nor your affiliate perform 

your own washing, you must propose to 

ONRR a method to determine the 

washing allowance using the procedures 

in § 1206.258(a). 

(1) You must use that method to 

determine your allowance until ONRR 

issues a determination. 

(2) [Reserved] 

Subpart J—Indian Coal 

■ 30. Amend § 1206.452 by revising the 

section heading, paragraphs (a) 

introductory text and (b) and removing 

and reserving paragraph (c) to read as 

follows: 

§ 1206.452 How do I calculate royalty value 

for coal? 

(a) The value of coal under this 

section for royalty purposes is the gross 

proceeds accruing to you or your 

affiliate under the first arm’s-length 

contract, or another person, less an 

applicable transportation allowance 

determined under §§ 1206.460 through 

1206.462 and washing allowance under 

§§ 1206.467 through 1206.469. You 

must use this paragraph (a) to value coal 

when: 

* * * * * 

(b) If you have no contract for the sale 

of coal subject to this section because 

you or your affiliate used the coal in a 

power plant that you or your affiliate 

own(s) for the generation and sale of 

electricity: 

(1) You must propose to ONRR a 

method to determine the value using the 

procedures in § 1206.458(a). 

(2) You must use that method to 

determine value, for royalty purposes, 

until ONRR issues a determination. 

(3) After ONRR issues a 

determination, you must make the 

adjustments under § 1206.453(a)(2). 

* * * * * 

■ 31. Amend § 1206.453 by revising 

paragraphs (a)(1), (b), (c) introductory 

text, (c)(2), (g)(1), and (2) to read as 

follows: 

§ 1206.453 How will ONRR determine if my 

royalty payments are correct? 

(a)(1) ONRR may monitor, review, and 

audit the royalties that you report, and, 

if ONRR determines that your reported 

value is inconsistent with the 

requirements of this subpart, ONRR may 

establish a reasonable royalty value 

based on other relevant matters. 

* * * * * 

(b) ONRR may examine whether your 

or your affiliate’s contract reflects the 

total consideration transferred for 

Indian coal, either directly or indirectly, 

from the buyer to you or your affiliate. 

If ONRR determines that additional 

consideration beyond that reflected in 

the contract was transferred, or that any 

portion of the consideration was not 

included in gross proceeds reported, 

ONRR may establish a reasonable 

royalty value based on other relevant 

matters. 

(c) ONRR may establish a reasonable 

royalty value based on other relevant 

matters if ONRR determines that the 

gross proceeds accruing to you or your 

affiliate under a contract do not reflect 

reasonable consideration because: 

* * * * * 

(2) You breached your duty to market 

the coal for the mutual benefit of 

yourself and the lessor; or 

* * * * * 

(g)(1) You or your affiliate must make 

all contracts, contract revisions, or 

amendments in writing. 

(2) If you or your affiliate fail(s) to 

comply with paragraph (g)(1) of this 

section, ONRR may establish a 

reasonable royalty value based on other 

relevant matters. 

* * * * * 

§ 1206.454 [Removed and Reserved] 

■ 32. Remove and reserve § 1206.454. 

■ 33. Amend § 1206.458 by: 

■ a. Revising paragraphs (a) 

introductory text and (a)(5); 

■ b. Removing the words ‘‘Assistant 

Secretary’’ in paragraphs (c)(2), (c)(3), 

(d)(1), (e), and (f) and adding in their 

place the words ‘‘Assistant Secretary for 

Policy, Management and Budget’’; 

■ c. Revising paragraph (g); and 

■ d. Adding paragraph (h). 

The revisions and additions read as 

follows: 

§ 1206.458 How do I request a valuation 

determination? 

(a) You may request a valuation 

determination from ONRR regarding any 

coal produced. Your request must 

comply with all of the following: 

* * * * * 

(5) Provide your analysis of the 

issue(s); 

* * * * * 

(g) ONRR or the Assistant Secretary 

for Policy, Management and Budget 

generally will not retroactively modify 

Federal Register / Vol. 86, No. 10 / Friday, January 15, 2021 / Rules and Regulations 4659 

or rescinds a valuation determination 

issued under paragraph (d) of this 

section, unless: 

(1) There was a misstatement or 

omission of material facts; or 

(2) The facts subsequently developed 

are materially different from the facts on 

which the guidance was based. 

(h) ONRR may make requests and 

replies under this section available to 

the public, subject to the confidentiality 

requirements under § 1206.459. 

■ 34. Amend § 1206.460 by: 

■ a. Revising paragraph (a)(2); 

■ b. Removing paragraph (a)(3); 

■ c. Removing the words ‘‘a Federal’’ in 

paragraphs (b)(2) and (b)(3) and adding 

in their place the words ‘‘an Indian’’; 

■ d. Removing the word ‘‘Federal’’ in 

paragraphs (e)(1) and (e)(2) and adding 

in its place the word ‘‘Indian’’; and 

■ e. Revising paragraphs (g) 

introductory text and (g)(2). 

The revisions read as follows: 

§ 1206.460 What general transportation 

allowance requirements apply to me? 

(a)(1) * * * 

(2) You do not need ONRR’s approval 

before reporting a transportation 

allowance for costs incurred. 

* * * * * 

(g) ONRR may determine your 

transportation allowance if: 

* * * * * 

(2) ONRR determines that the 

consideration that you or your affiliate 

paid under an arm’s-length 

transportation contract does not reflect 

the reasonable cost of the transportation 

because you breached your duty to 

market the coal for the mutual benefit of 

yourself and the lessor by transporting 

your coal at a cost that is unreasonably 

high; or 

* * * * * 

■ 35. Amend § 1206.461 by revising 

paragraph (c) to read as follows: 

§ 1206.461 How do I determine a 

transportation allowance if I have an arm’slength transportation contract? 

* * * * * 

(c) If you have no written contract for 

the arm’s-length transportation of coal, 

then you must propose to ONRR a 

method to determine the allowance 

using the procedures in § 1206.458(a). 

You may use that method to determine 

your allowance until ONRR issues a 

determination. 

(1) You must use that method to 

determine your allowance until ONRR 

issues a determination. 

(2) [Reserved] 

■ 36. Amend § 1206.467 by: 

■ a. Revising paragraph (a)(2); 

■ b. Removing the word ‘‘Federal’’ in 

paragraph (b)(2) and adding in its place 

the word ‘‘Indian’’; and 

■ c. Revising paragraphs (d) 

introductory text and (d)(2). 

The revisions read as follows: 

§ 1206.467 What general washing 

allowance requirements app ly to me? 

(a)(1) * * * 

(2) You do not need ONRR’s approval 

before reporting a washing allowance. 

* * * * * 

(d) ONRR may direct you to modify 

your washing allowance if: 

* * * * * 

(2) ONRR determines that the 

consideration that you or your affiliate 

paid under an arm’s-length washing 

contract does not reflect the reasonable 

cost of the washing because you 

breached your duty to market the coal 

for the mutual benefit of yourself and 

the lessor by washing your coal at a cost 

that is unreasonably high; or 

* * * * * 

■ 37. Amend § 1206.468 by revising 

paragraph (c) to read as follows: 

§ 1206.468 How do I determine washing 

allowances if I have an arm’s-length 

washing contract or no written arm’s-length 

contract? 

* * * * * 

(c) If you have no written contract for 

the arm’s-length washing of coal, and 

neither you nor your affiliate perform 

your own washing, you must propose to 

ONRR a method to determine the 

washing allowance using the procedures 

in § 1206.458(a). 

(1) You must use that method to 

determine your allowance until ONRR 

issues a determination. 

(2) [Reserved] 

* * * * * 

PART 1241—PENALTIES 

■ 38. The authority citation for part 

1241 continues to read as follows: 

Authority: 25 U.S.C. 396 et seq., 396a et 

seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 

et seq., 1001 et seq., 1701 et seq.; 43 U.S.C. 

1301 et seq., 1331 et seq., 1801 et seq. 

Subpart A—General Provisions 

■ 39. Amend § 1241.11 by removing 

paragraph (b)(5). 

Subpart C—Penalty Amount, Interest, 

and Collections 

■ 40. Amend § 1241.70 by: 

■ a. Revising paragraph (b); and 

■ b. Adding paragraph (d). 

The revision and addition read as 

follows: 

§ 1241.70 How does ONRR decide the 

amount of the penalty to assess? 

* * * * * 

(b) For payment violations only, we 

will consider the unpaid, underpaid, or 

late payment amount in our analysis of 

the severity of the violation. 

* * * * * 

(d) After we provisionally determine 

the civil penalty amount using the 

criteria and matrices described in 

paragraphs (a), (b), and (c) of this 

section, we may adjust the penalty 

amount in the FCCP or ILCP upward or 

downward if we find aggravating or 

mitigating circumstances to exist. 

(1) Aggravating circumstances may 

include, but are not limited to: 

(i) Committing a violation because 

you determined that the cost of a 

potential penalty is less than the cost of 

compliance; 

(ii) Committing a violation where you 

have no recent history of 

noncompliance of the same type, but 

you have a history of noncompliance of 

other violation types; 

(iii) Committing a violation that is 

also a criminal act. 

(2) Mitigating circumstances may 

include, but are not limited to: 

(i) Operational impacts resulting from 

the unexpected illness or death of an 

employee, natural disasters, pandemics, 

acts of terrorism, civil unrest, or armed 

conflict; 

(ii) Delays caused by government 

action or inaction, including as a result 

of a government shutdown and an 

extended ONRR-system downtime; 

(iii) Good-faith efforts to comply with 

formal or informal agency guidance. 

[FR Doc. 2021–00217 Filed 1–14–21; 8:45 am] 

BILLING CODE 4335–30–P