608 Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 

DEPARTMENT OF THE INTERIOR 

Office of Natural Resources Revenue 

30 CFR Parts 1202 and 1206 

[Docket No. ONRR–2012–0004] 

RIN 1012–AA13 

Consolidated Federal Oil & Gas and 

Federal & Indian Coal Valuation 

Reform 

AGENCY: Office of Natural Resources 

Revenue, Interior. 

ACTION: Proposed rule. 

SUMMARY: The Office of Natural 

Resources Revenue (ONRR) proposes to 

change the regulations governing 

valuation for royalty purposes of oil and 

gas produced from Federal onshore and 

offshore leases and coal produced from 

Federal and Indian leases. The proposed 

rule also consolidates definitions for oil, 

gas, and coal product valuation into one 

subpart applicable to the Federal oil and 

gas and Federal and Indian coal 

subparts. 

DATES: You must submit comments on 

or before March 9, 2015. 

ADDRESSES: You may submit comments 

to ONRR on this proposed rulemaking 

by any method below. Please refer to the 

Regulation Identifier Number (RIN) 

1012–AA13 in your comments. (See also 

Public Availability of Comments under 

Procedural Matters.) 

• Electronically go to 

www.regulations.gov. In the entry titled 

‘‘Enter Keyword or ID,’’ enter ‘‘ONRR– 

2012–0004,’’ then click ‘‘Search.’’ 

Follow the instructions to submit public 

comments. ONRR will post all 

comments. 

• Mail comments to Armand 

Southall, Regulatory Specialist, P.O. 

Box 25165, MS 61030A, Denver, 

Colorado 80225. 

• Hand-carry comments, or use an 

overnight courier service, to the Office 

of Natural Resources Revenue, Building 

85, Room A–614, Denver Federal 

Center, West 6th Ave. and Kipling St., 

Denver, Colorado 80225. 

FOR FURTHER INFORMATION CONTACT: For 

comments or questions on procedural 

issues, contact Armand Southall, ONRR, 

telephone (303) 231–3221, or email at 

armand.southall@onrr.gov. The authors 

of the proposed rule are Sarah 

Inderbitzin, Richard Adamski, Michael 

DeBerard, Peter Christnacht, Kimbra 

Davis, and Lance Wenger. 

SUPPLEMENTARY INFORMATION: 

I. Background 

In 2007, the Royalty Policy Committee 

(RPC) Subcommittee on Royalty 

Management issued a report titled 

‘‘Mineral Revenue Collection From 

Federal and Indian Lands and the Outer 

Continental Shelf.’’ The Subcommittee’s 

report recommended clarification of the 

regulations governing onshore gas and 

transportation deductions to provide 

more certainty for ONRR, BLM, and 

industry, which should result in better 

compliance. More specifically, the 

Subcommittee recommended revisions 

to the gas valuation regulations and 

guidelines to address the cost-bundling 

issue and to facilitate the calculation of 

gas transportation and gas processing 

deductions. The Subcommittee also 

recommended the use of market indices 

for gas valuation in the context of nonarm’s-length transactions in lieu of 

benchmarks, which have been used 

since 1988. 

The Subcommittee’s report also 

recommended ‘‘revis(ing) and 

implement(ing) the regulations and 

guidance for calculating prices used in 

checking royalty compliance for solid 

minerals, with particular attention to 

non-arm’s-length transactions.’’ 

The current Federal oil valuation 

regulations have been in effect since 

2000, with a subsequent amendment 

relating primarily to the use of index 

pricing in some circumstances. The 

current Federal gas valuation 

regulations have been in effect since 

March 1, 1988, with various subsequent 

amendments relating primarily to the 

transportation allowance provisions. 

The current Federal and Indian coal 

valuation regulations have been in effect 

since March 1, 1989, with minor 

subsequent amendments relating 

primarily to the Federal black lung 

excise taxes, abandoned mine lands 

fees, State and local severance taxes, 

and washing and transportation 

allowance provisions. In the years since 

we wrote these regulations, the 

Secretary of the Interior’s (Secretary) 

responsibility to determine the royalty 

value of minerals produced has not 

changed, but the industry and 

marketplace have changed dramatically. 

ONRR proposes these amendments to 

our valuation regulations to permit the 

Secretary to discharge the Department of 

the Interior’s (Department) royalty 

valuation responsibility in an 

environment of continuing and 

accelerating change in the industry and 

the marketplace. The Secretary’s 

responsibilities regarding oil and gas 

production from Federal leases and coal 

production from Federal and Indian 

leases require development of flexible 

valuation methodologies that lessees 

can accurately comply with in a timely 

manner. 

To increase the effectiveness and 

efficiency of our rules, ONRR is 

proposing proactive and innovative 

changes. We intend for this proposed 

rulemaking to provide regulations that 

(1) offer greater simplicity, certainty, 

clarity, and consistency in product 

valuation for mineral lessees and 

mineral revenue recipients; (2) are more 

understandable; (3) decrease industry’s 

cost of compliance and ONRR’s cost to 

ensure industry compliance; and (4) 

provide early certainty to industry and 

ONRR that companies have paid every 

dollar due. Therefore, ONRR proposes 

to amend the current regulations at 30 

CFR part 1202, subpart F, and part 1206, 

subparts C, D, F, and J, governing the 

valuation, for royalty purposes, of oil, 

gas, and coal produced from Federal 

leases and coal produced from Indian 

leases. 

On May 27, 2011, ONRR published 

Advance Notices of Proposed 

Rulemaking (ANPRs) regarding the 

valuation, for royalty purposes, of oil, 

gas, and coal produced from Federal 

leases and coal produced from Indian 

leases (76 FR 30878, 30881). ONRR 

received responses to the Federal oil 

and gas valuation ANPR from 19 State, 

industry, industry trade association, and 

the general public commenters. ONRR 

then conducted 3 public workshops on 

Federal oil and gas valuation in 

September and October 2011 in 

Houston, Texas, Washington, DC, and 

Denver, Colorado. At the workshops, 

ONRR asked attendees to discuss, 

among other things, the use of index 

prices to value oil and gas, alternatives 

to the current requirement to track 

actual costs to determine transportation 

allowances, and alternate methods for 

valuing wellhead gas volumes to 

eliminate the requirement to trace the 

value of liquids removed from 

processed gas. 

ONRR received responses to the 

Federal and Indian coal valuation ANPR 

from 11 industry representative, Tribe, 

State, community group (representing 

several member groups), coal 

publication, and trade organization 

commenters. ONRR then conducted 3 

public workshops on Federal and Indian 

coal valuation in October 2011 in 

Denver, Colorado; St. Louis, Missouri; 

and Albuquerque, New Mexico. At 

those workshops, ONRR asked attendees 

to discuss, among other things, (1) 

possible alternatives to the current 

methods that we use to value arm’slength and non-arm’s-length coal sales, 

(2) coal comparability factors, (3) 

possible alternatives to the current 

methods we use to value coal 

cooperative sales of coal, (4) use of 

index prices to value coal, and (5) 


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possible alternatives to the current 

requirements to track actual costs to 

determine transportation and washing 

allowances. 

ONRR considered the input from the 

ANPRs and the workshops and proposes 

this consolidated rulemaking to improve 

the current regulations. The proposed 

rule would not alter the underlying 

principles of the current regulations. By 

proposing these amendments, the 

Department reaffirms that the value, for 

royalty purposes, of crude oil and 

natural gas produced from Federal 

leases and coal produced from Federal 

and Indian leases is determined at or 

near the lease and that gross proceeds 

from arm’s-length contracts are the best 

indication of market value. Like the 

current regulations, these proposed 

regulations would not restrict ONRR to 

a comparison of arm’s-length sales of 

other production occurring in the field 

or area to value production not sold 

under an arm’s-length contract. Thus, 

like the current regulations, in this 

proposed rule, ONRR may begin with a 

‘‘downstream’’ price or value and 

determine value at the lease by allowing 

deductions for the cost of transporting 

production to downstream sales points 

or markets, or by allowing appropriate 

adjustments for location or quality. 

Federal and Indian lessees are not 

obligated to sell their production 

downstream of the lease. A lessee is at 

liberty to sell production at or near the 

lease, even if selling downstream might 

yield a higher royalty value than selling 

it at the lease. If a lessee chooses to sell 

downstream, the choice to sell 

downstream does not make otherwise 

non-deductible costs deductible (for 

example marketable condition and 

marketing costs). See Independent 

Petroleum Ass’n of America. v. DeWitt, 

279 F.3d 1036 (D.C. Cir. 2002), cert. 

denied sub nom., Independent 

Petroleum Ass’n of America. v. Watson, 

537 U.S. 1105 (2003) (‘‘Independent 

Petroleum Ass’n v. DeWitt’’); Devon 

Energy Corp v. Norton, No. 04–CV–0821 

(GK), 2007 WL 2422005 (D.D.C. Aug. 23, 

2007), aff’d sub nom., Devon Energy 

Corp. v. Kempthorne, 551 F.3d 1030 

(D.C. Cir. 2008), cert. denied, 130 S. Ct. 

86 (2009) (‘‘Devon’’) and cases cited 

therein. 

As noted above, the changes proposed 

in this rule reflect an effort by ONRR to 

update its royalty valuation regulations 

to, among other things, simplify 

processes and provide early clarity 

regarding royalties owed. However, 

even with the changes outlined in this 

rule, royalty valuations will continue to 

be complex, and the markets for oil, gas, 

and coal will continue to evolve. 

Therefore, ONRR continues to be 

interested in opportunities to further 

streamline the valuation process, while 

also bringing added transparency to the 

system. In particular, we seek ideas and 

comments on: 

1. The potential for creating 

standardized ‘‘schedules’’ for 

transportation and processing 

allowances to reduce the need to rely on 

case-by-case operator reporting and 

agency review of actual costs. 

2. Opportunities to more 

fundamentally reassess how non-arm’s 

length transactions are treated for the 

purposes of determining royalties owed. 

ONRR recognizes that the costs and 

benefits of making further changes to its 

valuation regulations (beyond those 

specifically proposed in this rule) will 

depend on the specific commodity at 

issue (i.e., oil, gas or coal), as well as 

geographic or other factors. Thus, 

detailed comments that elaborate on 

specific situations where further 

valuation changes should be considered 

would be particularly useful to ONRR as 

it proceeds with this rulemaking as well 

as any future rules that may be 

considered. 

II. Explanation of Proposed 

Amendments 

Based on comments ONRR received 

on the ANPRs and at the public 

workshops, and other relevant 

information, we propose this 

consolidated rule to improve the current 

regulations to ensure greater clarity, 

efficiency, certainty, and consistency in 

production valuation. 

The general consensus of comments 

received on the ANPR about arm’slength oil sales was that actual proceeds 

are the best indicator of value, and 

ONRR should not change to index 

prices. Most commenters agreed the 

valuation methodology for non-arm’slength sales of Federal oil is working, as 

is using actual costs to determine 

transportation allowances. Thus, ONRR 

is not currently proposing major 

changes to oil valuation methodologies 

except to eliminate both unused 

valuation options, such as tendering, 

and associated definition(s), and to 

make the oil rule consistent with our 

proposed changes to the proposed 

Federal gas rule. 

The comments we received regarding 

gas produced from Federal leases were, 

in certain instances, polarized. Very 

large companies generally support index 

pricing as an option if it is revenueneutral and there are no required trueups (end-of-year comparison of the 

index value to actual sales and payment 

on the higher of the two). Independent 

gas producers and States generally 

disagreed with the major companies and 

did not support index pricing because 

they believe it may not reflect actual 

value and may not be revenue neutral. 

The majority of respondents generally 

support using actual costs for gas 

transportation and processing 

deductions to maintain revenue 

neutrality. In response, ONRR proposes 

no major changes for the valuation of 

arm’s-length gas sales. However, for 

non-arm’s-length gas sales, ONRR 

proposes to eliminate current 

benchmarks (a series of indicators of 

market value). Instead, ONRR proposes 

valuation methodology options based on 

how gas is sold using the first arm’slength-sale price (affiliate resales), 

optional index prices, or weighted 

average pool prices. 

The general consensus of ANPR 

commenters for coal valuation was not 

to change royalty valuation of arm’slength sales and not to use coal index 

values because of their very limited 

applicability. Commenters suggested 

modifying the non-arm’s-length coal 

benchmarks and eliminating seldomused benchmarks. Commenters agreed 

ONRR should keep Federal and Indian 

rules separate. Therefore, at this time, 

ONRR is proposing no changes to the 

valuation of arm’s-length coal sales. 

For non-arm’s-length coal sales, 

ONRR proposes to eliminate the current 

benchmarks. Instead, ONRR proposes to 

value coal on the gross proceeds 

received from the first arm’s-length sale. 

ONRR also proposes to value sales of 

coal between coal cooperative members 

using the first arm’s-length sale or a 

netback methodology. In addition, if 

there is no coal sale, and lessees or their 

affiliates use the coal to generate 

electricity and sell the electricity, then 

ONRR proposes to value the coal for 

royalty purposes based on the gross 

proceeds the lessee or its affiliate 

receive for the power plant’s arm’slength sales of the electricity, less 

applicable deductions. ONRR proposes 

the same changes for both Federal and 

Indian coal, with some minor 

exceptions, but would continue to 

maintain separate regulations. 

ONRR also proposes other changes to 

our regulations, although we did not 

specifically request comments on these 

changes in the ANPRs or at the 

workshops. One such proposed change 

is adding a new ‘‘default provision’’ to 

address valuation when ONRR 

determines (1) a contract does not 

reflect total consideration, (2) the gross 

proceeds accruing to you or your 

affiliate under a contract do not reflect 

reasonable consideration due to 

misconduct or breach of the duty to 

market for the mutual benefit of the 

lessee and the lessor, or (3) it cannot 


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ascertain the correct value of production 

because of a variety of factors, 

including, but not limited to, a lessee’s 

failure to provide documents. In these 

cases, the Secretary may enforce his/her 

authority and exercise considerable 

discretion to establish the reasonable 

value of production using a variety of 

discretionary factors and any other 

information the Secretary believes is 

appropriate. 

Finally, we rewrote all sections of the 

current regulations in Plain Language to 

meet the criteria of Executive Orders 

12866 and 12988 and the Presidential 

Memorandum of June 1, 1998, and to 

make our rules more clear, consistent, 

and readable. All citations to the current 

ONRR regulations in title 30 of the Code 

of Federal Regulations (CFR) in this 

preamble refer to the July 1, 2012, CFR. 

III. Section-by-Section Analysis 

Before reading the additional 

explanatory information below, please 

turn to the proposed rule language that 

immediately follows the List of Subjects 

in 30 CFR parts 1202 and 1206 and 

signature page in this proposed rule. 

The Department will codify this 

language in the CFR if we finalize the 

proposed rule as written. 

After you read the proposed rule, 

please return to the preamble discussion 

below. The preamble contains more 

information about the proposed rule, 

such as why we define a term in a 

certain manner and why we chose one 

valuation method over another. 

The derivation table below only 

shows a crosswalk of the recodified 

sections of the current and the proposed 

regulations in part 1206. 

DERIVATION TABLE FOR PART 1206 

The requirements of section: Are derived from section: 

Subpart C 

1206.20 ................................ 1206.101; 1206.151; 1206.251; 1206.451. 

1206.101 .............................. 1206.102. 

1206.102 .............................. 1206.103. 

1206.103 .............................. 1206.104. 

1206.106 .............................. 1206.105. 

1206.107 .............................. 1206.106. 

1206.108 .............................. 1206.107. 

1206.109 .............................. 1206.108. 

1206.110 .............................. 1206.109. 

1206.111 .............................. 1206.110. 

1206.112 .............................. 1206.111. 

1206.113 .............................. 1206.112. 

1206.114 .............................. 1206.113. 

1206.115 .............................. 1206.114. 

1206.116 .............................. 1206.115. 

1206.117 .............................. 1206.116. 

1206.118 .............................. 1206.117. 

Subpart D 

1206.140 .............................. 1206.150. 

1206.141(a)(1)–(4) ............... 1206.152(a)(1). 

1206.141(b)(1)–(3) ............... 1206.152(a)(2). 

1206.141(b)(4) ...................... 1206.152(b)(1)(iv). 

1206.142(a)(4) ...................... 1206.153(a)(1). 

1206.142(b) .......................... 1206.153(a)(2). 

1206.142(c) .......................... 1206.153(b)(1)(i). 

1206.143(a)(1) and (b) ......... 1206.152(b)(1)(ii); 1206.153(b)(1)(ii). 

1206.143(a)(2) ...................... 1206.152(f); 1206.153(f). 

1206.143(c) .......................... 1206.152(b)(1)(iii); 1206.153(b)(1)(iii). 

1206.144 .............................. 1206.152(c)(1)–(3); 1206.153(c)(1)–(3). 

1206.145 .............................. 1206.152(e)(1) and (2); 1206.153(e)(1) and (2); 1206.157(c)(1)(ii) and (c)(2)(iii); 1206.159(c)(1)(ii) and (c)(2)(iii). 

1206.146 .............................. 1206.152(i); 1206.153(i). 

1206.147 .............................. 1206.152(k); 1206.153(k). 

1206.148 .............................. 1206.152(g); 1206.153(g). 

1206.149 .............................. 1206.152(l); 1206.153(l). 

1206.150 .............................. 1206.154. 

1206.151 .............................. 1206.155. 

1206.152(a) .......................... 1206.156(a). 

1206.152(b) .......................... 1206.156(b); 1206.57(a)(2) and (b)(3). 

1206.152(c)(1) ...................... 1206.157(a)(2) and (b)(4). 

1206.152(f) ........................... 1206.157(a)(4). 

1206.153(b) .......................... 1206.157(f). 

1206.153(c) .......................... 1206.157(g). 

1206.154(a) .......................... 1206.157(b). 

1206.154(e)–(h) .................... 1206.157(b)(2)(i)–(iii). 

1206.154(i) ........................... 1206.157(b)(2)(iv). 

1206.154(i)(3) ....................... 1206.157(b)(2)(v). 

1206.155 .............................. 1206.157(c)(1)(i), (ii). 

1206.156 .............................. 1206.157(c)(2)(i)–(iv). 

1206.157(a)(1) and (c) ......... 1206.156(d). 

1206.157(a)(2) and 

1206.158.

1206.157(e). 


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DERIVATION TABLE FOR PART 1206—Continued 

The requirements of section: Are derived from section: 

1206.159(a)(1) ...................... 1206.158(a). 

1206.159(b) .......................... 1206.158(b). 

1206.159(c)(1) and (2) ......... 1206.158(c)(1) and (2). 

1206.159(d) .......................... 1206.158(d)(1). 

1206.160 .............................. 1206.159(a). 

1206.161 .............................. 1206.159(b). 

1206.162 .............................. 1206.159(c)(1). 

1206.163 .............................. 1206.159(c)(2). 

1206.164 .............................. 1206.159(d). 

1206.165 .............................. 1206.159(e). 

Subpart F 

1206.250 .............................. 1206.250. 

1206.251 .............................. 1206.254; 1206.255; 1206.260. 

1206.252(d) .......................... 1206.258(a); 1206.261(b). 

1206.260(a)(1) and (b) ......... 1206.261(a). 

1206.260(c)(2) ...................... 1206.261(a)(2). 

1206.260(d) .......................... 1206.261(c)(3). 

1206.260(e) .......................... 1206.261(c)(1), (c)(2), and (e). 

1206.260(f) ........................... 1206.262(a)(4). 

1206.260(g) .......................... 1206.262(a)(2) and (a)(3). 

1206.261 .............................. 1206.262(a)(1). 

1206.262 .............................. 1206.262(b). 

1206.263 .............................. 1206.262(c)(1). 

1206.264 .............................. 1206.262(c)(2). 

1206.265 .............................. 1206.262(d). 

1206.266 .............................. 1206.262(e). 

1206.267(a) .......................... 1206.258(a). 

1206.267(b)(2) ...................... 1206.258(c); 1206.260. 

1206.267(c) .......................... 1206.259(a)(4). 

1206.267(d) .......................... 1206.259(a)(2) and (a)(3). 

1206.267(e) .......................... 1206.258(e). 

1206.268 .............................. 1206.259(a)(1). 

1206.269 .............................. 1206.259(b). 

1206.270 .............................. 1206.259(c)(1). 

1206.271 .............................. 1206.259(c)(2). 

1206.272 .............................. 1206.259(d). 

1206.273 .............................. 1206.259(e). 

Subpart J 

1206.450 .............................. 1206.450. 

1206.451 .............................. 1206.453; 1206.454; 1206.459. 

1206.460 .............................. 1206.461(a)(1). 

1206.463 .............................. 1206.461(c). 

A. Section-By-Section Analysis of 30 

CFR Part 1202—Royalties, Subpart F— 

Coal 

ONRR proposes to amend subpart F 

regarding Federal and Indian coal 

production volumes on which you must 

pay royalties. The proposed rule merely 

moves current 30 CFR 1206.253 and 

1206.452 to 30 CFR part 1202, subpart 

F to a new § 1202.251. We also rewrote 

the current sections in Plain Language 

without substantive change. 

B. Section-By-Section Analysis of 30 

CFR Part 1206—Product Valuation, 

Subpart A—General Provisions and 

Definitions, Subpart C—Federal Oil, 

Subpart D—Federal Gas, Subpart F— 

Federal Coal, and Subpart J—Indian 

Coal 

ONRR proposes to amend subparts A, 

C, D, F, and J relating to the valuation 

of oil and gas produced from Federal 

leases and coal produced from Federal 

and Indian leases. 

Subpart A—General Provisions 

1206.20 What definitions apply to 

subparts C, D, F, and J? 

ONRR proposes to consolidate the 

definitions from Federal Oil (30 CFR 

1206.101), Federal Gas (30 CFR 

1206.151), Federal Coal (30 CFR 

1206.251), and Indian Coal (30 CFR 

1206.451). The consolidated definitions 

reside in a proposed § 1206.20 under 

proposed Subpart A—General 

Provisions and Definitions. 

ONRR proposes to consolidate the 

existing definitions for these products to 

provide greater clarity and eliminate 

redundancy. Where common terms exist 

in the four subparts, ONRR modifies the 

definitions to incorporate the active 

voice and to use plain and simple 

language similar to the language 

reflected in the 2000 Federal crude oil 

rule. For example, the term arm’s-length 

contract applies the modern language of 

the 2000 Federal crude oil rule and 

extends its applicability to Federal gas 

and Federal and Indian coal. Where a 

definition has different meanings for 

different subparts, we define the term 


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for each subpart in that definition. For 

example, see the definition of ‘‘gross 

proceeds’’ below. Terms we currently 

reference in only one subpart, for 

example ANS (Alaska North Slope), 

remain unmodified, except we propose 

to locate these definitions in the 

consolidated definitions in § 1206.20. 

Finally, ONRR proposes to add new 

definitions. 

We identify all new definitions in the 

table below and show if each existing 

definition remains unchanged, is 

modified, or is eliminated. 

SUMMARY OF TERMS AND STATUS

Term 

Status 

Modified Not modified Added new 

definition 

Removed definition 

Ad valorem lease ............................................................................................. ........................ X ........................ ........................

Affiliate ............................................................................................................. X ........................ ........................ ........................

Allowance ......................................................................................................... ........................ ........................ ........................ X 

ANS .................................................................................................................. ........................ X ........................ ........................

Area ................................................................................................................. X ........................ ........................ ........................

Arm’s-length contract ....................................................................................... X ........................ ........................ ........................

Audit ................................................................................................................. X ........................ ........................ ........................

BIA ................................................................................................................... ........................ X ........................ ........................

BLM .................................................................................................................. ........................ X ........................ ........................

BOEM .............................................................................................................. ........................ ........................ X ........................

BSEE ............................................................................................................... ........................ ........................ X ........................

Coal .................................................................................................................. ........................ X ........................ ........................

Coal cooperative .............................................................................................. ........................ ........................ X ........................

Coal washing ................................................................................................... ........................ X ........................ ........................

Compression .................................................................................................... ........................ X ........................ ........................

Condensate ...................................................................................................... X ........................ ........................ ........................

Constraint ......................................................................................................... ........................ ........................ X ........................

Contract ........................................................................................................... X ........................ ........................ ........................

Designee .......................................................................................................... ........................ X ........................ ........................

Exchange agreement ....................................................................................... ........................ X ........................ ........................

FERC ............................................................................................................... ........................ ........................ X ........................

Field ................................................................................................................. X ........................ ........................ ........................

Gas .................................................................................................................. ........................ X ........................ ........................

Gas plant products .......................................................................................... ........................ X ........................ ........................

Gathering ......................................................................................................... X ........................ ........................ ........................

Geographic region ........................................................................................... ........................ ........................ X ........................

Gross proceeds ............................................................................................... X ........................ ........................ ........................

Index ................................................................................................................ X ........................ ........................ ........................

Index pricing point ........................................................................................... X ........................ ........................ ........................

Index zone ....................................................................................................... ........................ ........................ X ........................

Indian allottee .................................................................................................. ........................ ........................ ........................ X 

Indian Tribe ...................................................................................................... X ........................ ........................ ........................

Individual Indian mineral owner ....................................................................... ........................ ........................ X ........................

Keepwhole contract ......................................................................................... ........................ ........................ X ........................

Lease ............................................................................................................... X ........................ ........................ ........................

Lease products ................................................................................................ X ........................ ........................ ........................

Lessee ............................................................................................................. X ........................ ........................ ........................

Like quality ....................................................................................................... ........................ ........................ X ........................

Like quality coal ............................................................................................... ........................ ........................ ........................ X 

Like-quality lease products .............................................................................. ........................ ........................ ........................ X 

Location differential .......................................................................................... ........................ X ........................ ........................

Market center ................................................................................................... ........................ X ........................ ........................

Marketable condition ........................................................................................ ........................ X ........................ ........................

Marketing affiliate ............................................................................................. ........................ ........................ ........................ X 

Mine ................................................................................................................. ........................ X ........................ ........................

Minimum royalty ............................................................................................... ........................ ........................ ........................ X 

Misconduct ....................................................................................................... ........................ ........................ X ........................

Net-Back method ............................................................................................. ........................ ........................ ........................ X 

Net output ........................................................................................................ X ........................ ........................ ........................

Net profit share ................................................................................................ ........................ ........................ ........................ X 

Netting .............................................................................................................. X ........................ ........................ ........................

NGLs ................................................................................................................ ........................ ........................ X ........................

NYMEX price ................................................................................................... ........................ X ........................ ........................

Oil ..................................................................................................................... ........................ X ........................ ........................

ONRR .............................................................................................................. ........................ X ........................ ........................

ONRR-approved commercial price bulletin ..................................................... ........................ ........................ X ........................

ONRR-approved publication ............................................................................ X ........................ ........................ ........................

Outer Continental Shelf ................................................................................... ........................ X ........................ ........................

Payor ................................................................................................................ ........................ ........................ X ........................

Person .............................................................................................................. X ........................ ........................ ........................

Posted price ..................................................................................................... ........................ ........................ ........................ X 

Processing ....................................................................................................... X ........................ ........................ ........................

Processing allowance ...................................................................................... ........................ ........................ X ........................


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 613 

SUMMARY OF TERMS AND STATUS—Continued 

Term 

Status 

Modified Not modified Added new 

definition 

Removed definition 

Prompt month .................................................................................................. ........................ X ........................ ........................

Quality differential ............................................................................................ ........................ X ........................ ........................

Region .............................................................................................................. ........................ ........................ X ........................

Residue gas ..................................................................................................... ........................ X ........................ ........................

Rocky Mountain Region .................................................................................. ........................ X ........................ ........................

Roll ................................................................................................................... X ........................ ........................ ........................

Sale .................................................................................................................. X ........................ ........................ ........................

Sales type code ............................................................................................... ........................ ........................ ........................ X 

Section 6 lease ................................................................................................ ........................ X ........................ ........................

Short ton .......................................................................................................... ........................ ........................ X ........................

Spot market price ............................................................................................ ........................ ........................ ........................ X 

Spot price ......................................................................................................... ........................ X ........................ ........................

Spot sales agreement ...................................................................................... ........................ ........................ ........................ X 

Tendering program .......................................................................................... ........................ ........................ ........................ X 

Tonnage ........................................................................................................... ........................ ........................ X ........................

Trading month .................................................................................................. ........................ X ........................ ........................

Transportation allowance ................................................................................. X ........................ ........................ ........................

Warranty contract ............................................................................................ ........................ ........................ ........................ X 

Washing allowance .......................................................................................... ........................ ........................ X ........................

WTI differential ................................................................................................. ........................ X ........................ ........................

We explain the new and modified 

terms and definitions below. For most 

modified terms, we rewrote the terms in 

Plain Language and make no substantive 

change. 

Subpart C—Federal Oil 

1206.100 What is the purpose of this 

subpart? 

This proposed section is the same as 

current 30 CFR 1206.100. 

1206.101 How do I calculate royalty 

value for oil I or my affiliate sell(s) 

under an arm’s-length contract? 

This proposed section is the same as 

current 30 CFR 1206.102 except for two 

substantive changes. First, proposed 

paragraph (a) contains the same 

provisions as existing § 1206.102(a) with 

one modification. Proposed paragraph 

(a) adds that the value in this paragraph 

does not apply ‘‘if ONRR decides to 

value your oil under § 1206.105.’’ 

Proposed § 1206.105 is ONRR’s new 

proposed default valuation mechanism. 

ONRR also proposes to add a new 

provision to paragraph (c)(1) allowing 

ONRR to decide a lessee’s oil value if 

the lessee fails to make the election in 

this paragraph. Under the current 

regulations, if a contract is either nonarm’s-length or an exchange agreement, 

a lessee can choose one of two different 

valuation methods. ONRR proposes to 

add a new provision to clarify the 

current regulations by explaining the 

consequences if a lessee fails to properly 

make the election. For example, if a 

lessee improperly classifies its contract 

as an arm’s-length contract under the 

current regulations, the lessee will most 

likely pay royalties on the price 

specified in its contract. However, if the 

lessee or ONRR subsequently 

determines the contract actually was 

non-arm’s-length or an exchange 

agreement, the existing regulations do 

not specify if the lessee may make the 

election retroactively. To remove this 

ambiguity, ONRR proposes to eliminate 

the lessee’s election in these situations 

and provide that ONRR can determine 

the lessee’s oil value under the new 

default valuation mechanism in 

§ 1206.105. 

1206.102 How do I value oil not sold 

under an arm’s-length contract? 

This proposed section is the same as 

current 30 CFR 1206.103 except for two 

substantive changes. The first 

substantive change is to paragraph (a), 

which explains when you may value oil 

under this section. Proposed paragraph 

(a) requires you to use this section to 

value your oil ‘‘unless ONRR decides to 

value your oil under § 1206.105.’’ 

Proposed § 1206.105 is ONRR’s new 

proposed default valuation mechanism. 

ONRR also proposes to remove 

current 30 CFR 1206.103(b)(1) 

containing the option for lessees to use 

a tendering program to value oil they 

produce from Federal leases in the 

Rocky Mountain Region. Since the final 

oil valuation regulations were published 

in March 2000, ONRR is aware of only 

one company that valued its oil using 

this provision. At that time, we received 

feedback from oil producers that it was 

administratively inefficient to 

implement a tendering program for 

valuation purposes. We do not believe 

any oil producer has used this provision 

since then. Therefore, because industry 

has abandoned its use of this provision, 

we propose to remove tendering from 

the options available to value Federal 

oil produced in the Rocky Mountain 

Region. 

Finally, ONRR proposes to amend 

paragraphs (d) and (e) of § 1206.103 in 

the current regulations. Under the 

current regulations, lessees may apply 

paragraphs (d) and (e) to value their 

production with ONRR approval. ONRR 

proposes to amend paragraphs (d) and 

(e) to instead state that ONRR may 

decide to use these paragraphs to value 

production under § 1206.105. 

1206.103 What publications are 

acceptable to ONRR? 

The substantive requirements of this 

proposed section are the same as current 

30 CFR 1206.104. However, we propose 

to remove our requirement to publish a 

notice of acceptable publications in the 

Federal Register. Instead, we propose to 

provide acceptable publications on our 

Web site. 

1206.104 How will ONRR determine if 

my royalty payments are correct? 

In this section, ONRR proposes 

amendments to the text of its gross 

proceeds provisions to rewrite them in 

Plain Language and to make them 

consistent with other valuation 

regulations. Thus, rather than repeat the 

requirements or procedures in each 

applicable section of this rule, ONRR 

proposes to have this section apply to 

this entire subpart. However, the 

substantive requirements of proposed 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
614 Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 

paragraphs (d), (e) and (f) remain 

unchanged. We propose the same 

changes to the Federal gas amendments 

that we propose in this section, so 

please refer to the discussion of the 

substantive changes we propose to make 

to the Federal gas regulation in 

§ 1206.143 below for more information. 

1206.105 How will ONRR determine 

the value of my oil for royalty purposes? 

ONRR proposes to add a new 

‘‘default’’ valuation § 1206.105 under 

which ONRR can value your oil if we 

decide to do so pursuant to the criteria 

under § 1206.104 or any other provision 

in this subpart. If ONRR determines 

value under this new default section, we 

may consider any information we deem 

relevant. Also, this proposed section 

enumerates factors ONRR may consider 

if we decide we will determine value, 

for royalty purposes, under this section, 

which may include, but not be limited 

to: 

(a) The value of like-quality oil in the 

same field or nearby fields or areas; 

(b) The value of like-quality oil from 

the same plant; 

(c) Public sources of price or market 

information ONRR deems reliable; 

(d) Information available and reported 

to ONRR, including but not limited to, 

on Form ONRR–2014 and Form ONRR– 

4054; 

(e) Costs of transportation or 

processing, if ONRR determines they are 

applicable; or 

(f) Any information ONRR deems 

relevant regarding the particular lease 

operation or the salability of the oil. 

This proposed section allows ONRR 

to consider any criteria we deem 

relevant, as well as criteria similar to the 

current gas valuation benchmarks under 

30 CFR 1206.152(c)(1) and (2) and 

1206.153(c)(1) and (2). Like the 

valuation regulations in effect prior to 

the 1988 rulemaking that resulted in the 

current gas valuation regulations, 30 

CFR 206.103 (1984) (onshore) and 

206.150 (1984) (offshore), under 

proposed § 1206.105, ONRR has the 

authority and responsibility to establish 

the reasonable value of production for 

royalty purposes and possesses 

considerable discretion in determining 

that value. Independent Petroleum 

Ass’n v. DeWitt, 279 F.3d at 1039–1040, 

and cases cited therein. Thus, under this 

proposed section, ONRR has broad 

authority to value your oil in the 

manner we deem most appropriate 

considering the factors we deem most 

appropriate. 

We add the same default provision to 

Federal gas in § 1206.144, Federal coal 

in § 1206.254, and Indian coal in 

§ 1206.454. 

1206.106 What records must I keep to 

support my calculations of value under 

this subpart? 

1206.107 What are my responsibilities 

to place production into marketable 

condition and to market production? 

The two proposed sections above are 

the same as current 30 CFR 1206.105 

and 1206.106, except we rewrite the 

sections in Plain Language. 

1206.108 How do I request a value 

determination? 

This proposed section is the same as 

current 30 CFR 1206.107 except we 

make some substantive changes to 

provide greater clarity to the process a 

lessee may use to request valuation 

guidance and determinations, as well as 

the effect of ONRR’s response to such 

requests. Because we are making the 

same changes to the Federal gas 

amendments in this proposed 

rulemaking, please refer to proposed 

§ 1206.148 of the Federal gas regulation 

below for more information. 

1206.109 Does ONRR protect 

information I provide? 

This proposed section is the same as 

current 30 CFR 1206.108, except we 

rewrite the section in Plain Language. 

1206.110 What general transportation 

allowance requirements apply to me? 

This proposed section is the same as 

current 30 CFR 1206.109 except we 

reword the section name and make the 

following substantive changes. First, in 

proposed paragraph (a)(2)(ii), we add a 

new provision that states you may not 

take a transportation allowance for the 

movement of oil produced on the OCS 

from the wellhead to the first platform. 

Because we are making the same change 

to the Federal gas amendments we 

propose in this rulemaking, please refer 

to § 1206.152(a)(2)(ii) of the Federal gas 

regulation below for more information. 

Second, we propose in paragraph (b) 

to clarify that if you request to use a 

different cost allocation than that in 

paragraph (b), and we approve your 

request, you can only use your proposed 

allocation methodology prospectively. 

We make this proposed change to clarify 

that you may not request retroactive 

changes to your royalty reporting and 

payment. We make the same change to 

proposed §§ 1206.112(b), 1206.112(i)(1), 

1206.112(j), 1206.113(c)(2), 

1206.150(c)(4), 1206.152(b), 

1206.154(b)(3), 1206.154(i)(1), 

1206.161(b)(3), 1206.151(h)(1), 

1206.262(b)(3), 1206.262(h)(1), 

1206.269(b)(3), 1206.269(h)(1), 

1206.462(b)(3), 1206.462(h)(1), 

1206.463(d)(4)(i), 1206.469(b)(3), 

1206.469(h)(1), and 1206.470(d)(4)(i). 

Third, in paragraph (d)(1) of this 

section, we propose to remove current 

30 CFR 1206.109(c)(2) that allows a 

lessee to request to exceed the limit on 

transportation allowances of 50 percent 

of the value of the oil. We also propose 

to terminate existing approvals to 

exceed the 50 percent limit under 

paragraph (d)(2). Because we are making 

the same change to the Federal gas 

amendments in this proposed 

rulemaking, please refer to § 1206.152(e) 

below for more information. 

Fourth, like the default provision for 

valuation we discuss above under 

§ 1206.104, proposed paragraph (f) 

provides that ONRR may determine 

your transportation allowance under 

§ 1206.105 if (1) there is misconduct by 

or between the contracting parties, (2) 

the total consideration the lessee or its 

affiliate pays under an arm’s-length 

contract does not reflect the reasonable 

cost of transportation because the lessee 

breached its duty to market oil for the 

mutual benefit of the lessee and the 

lessor by transporting oil at a cost that 

is unreasonably high, or (3) ONRR 

cannot determine if the lessee properly 

calculated a transportation allowance 

for any reason. Because we are making 

the same change to the Federal gas 

amendments we propose in this 

rulemaking, please refer to the 

discussion of § 1206.152(g) below for 

more information on this provision. 

Finally, we also propose a new 

provision under paragraph (g) to clarify 

that you do not need ONRR’s approval 

before reporting a transportation 

allowance for costs you incur. This is 

consistent with existing practice. 

1206.111 How do I determine a 

transportation allowance if I have an 

arm’s-length transportation contract? 

This proposed section is the same as 

current 30 CFR 1206.110, except for 

three substantive changes. ONRR 

proposes to eliminate the provision in 

current 30 CFR 1206.110(b)(4) that 

allows a lessee to include the costs of 

carrying line fill on its books as a 

component of arm’s-length 

transportation allowances. Rather, we 

propose to specifically preclude 

including this cost in transportation 

allowances under new paragraph (c)(9) 

of this section. We propose to eliminate 

allowing this cost because we believe 

this is a cost to market the oil we 

disallow as a deduction under our 

existing valuation regulations. Line fill 

occurs after the royalty measurement 

point and is necessary for the pipeline 

operator to get Federal oil production to 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 615 

market. We request comments on 

whether this is a marketing cost. 

We also propose to add a new 

paragraph (d) that applies if you have no 

contract in writing for the arm’s-length 

transportation of oil. In that case, ONRR 

determines your transportation 

allowance under § 1206.105. Under the 

proposed rule, you may propose to 

ONRR a method to determine the 

allowance using the procedures in 

§ 1206.108(a) and may use that method 

to determine your allowance until 

ONRR issues its determination. This 

proposed paragraph does not apply if a 

lessee performs its own transportation. 

Instead, proposed § 1206.112 for nonarm’s-length transportation allowances, 

applies. 

Finally, ONRR proposes to eliminate 

the provision in current 30 CFR 

1206.110(g) that allows a lessee to report 

transportation costs, in certain 

circumstances, as a transportation 

factor. We propose that a lessee must 

report separately all transportation costs 

under both arm’s-length and non-arm’slength sales contracts as a transportation 

allowance on Form ONRR–2014. ONRR 

believes requiring lessees to report all 

deductions for transportation costs 

separately as allowances on Form 

ONRR–2014 is more transparent, 

supports ONRR’s increased data mining 

efforts to promote accurate upfront 

royalty reporting, and assists State and 

Federal auditors in their compliance 

work. 

1206.112 How do I determine a 

transportation allowance if I do not 

have an arm’s-length transportation 

contract? 

This proposed section is the same as 

current 30 CFR 1206.111 except for the 

following substantive changes. 

We replace current 30 CFR 

1206.111(b)(3) and (b)(4) with proposed 

paragraph (b)(3)(i) of this section, which 

allows you to elect to calculate 

depreciation and a return on 

undepreciated capital investment in a 

transportation system under proposed 

paragraph (b)(3)(i)(1) or a return on 

undepreciated capital investment with 

no depreciation under proposed 

paragraph (b)(3)(i)(2). The proposed 

regulation provides that once you make 

an election, you may not change it 

without ONRR’s approval. In addition, 

proposed paragraph (b)(3)(ii) replaces 

current 30 CFR 1206.111(b)(5). 

Currently, 30 CFR 1206.111(b)(5) allows 

you to continue deducting 10 percent of 

the cost of capital expenditures once 

you have depreciated the asset below 10 

percent under current 30 CFR 

1206.111(j). However, under proposed 

paragraph (i)(1)(iii) of this section, 

instead of allowing a 10 percent 

deduction, we base the return on 

undepreciated capital investment on the 

reasonable salvage value of the asset. 

ONRR believes this method more 

reasonably reflects the actual costs for 

oil transportation systems. Also, it 

makes the treatment of depreciation 

consistent with other royalty valuation 

rules, including the current Federal gas 

rule at 30 CFR 1206.157(g) (proposed 

§ 1206.154(i)). 

In proposed paragraph (c)(2)(ii), we 

prohibit you from including actual or 

theoretical line loss as a transportation 

cost. ONRR proposes to eliminate the 

provision in the current regulations at 

30 CFR 1206.111(b)(6)(v) which allows 

a lessee to reduce the royalty volume 

measured at the royalty measurement 

point by actual or theoretical line loss 

occurring after the royalty measurement 

point. This change is consistent with 

long-standing mineral leasing laws that 

require royalty on the volume of 

production removed from the lease. 

Mineral Leasing Act, 30 U.S.C. 181–287; 

Mineral Leasing Act for Acquired 

Lands, 30 U.S.C. 351–359 (onshore 

acquired lands); Indian leasing statutes, 

25 U.S.C. 396a—396g (tribal leases); 25 

U.S.C. 396 (allotted leases); and the 

Outer Continental Shelf Lands Act, 43 

U.S.C. 1331–1356. This change also 

makes Federal oil valuation consistent 

with ONRR’s other product valuation 

regulations. 

Under proposed paragraph (c)(2)(iii), 

ONRR eliminates the provision in 

current 30 CFR 1206.111(b)(6)(ii) which 

allows a lessee to include the costs of 

carrying line fill on its books as a 

component of non-arm’s-length 

transportation allowances. We believe 

this is a cost to market the oil, which we 

disallow as a deduction under current 

valuation regulations. Line fill occurs 

after the royalty measurement point and 

is necessary for the pipeline operator to 

get Federal oil production to market. We 

request comments on whether this is a 

marketing cost. 

Proposed paragraph (i)(1) allows you 

to calculate depreciation and a return on 

undepreciated capital investment using 

either a straight-line method (based on 

either the life of the equipment or the 

life of the reserves that the 

transportation system services) or a unit 

of production method. This 

depreciation method was in ONRR’s oil 

valuation regulations in effect for 

producer-owned transportation systems 

prior to the effective date of the 2000 

Federal oil valuation regulations. This 

new proposed paragraph (i)(1) would 

replace the provision in current 30 CFR 

1206.111(h), which allows a lessee to 

depreciate a transportation asset a 

second time after the lessee already 

fully depreciated that asset. The current 

Federal oil valuation regulations 

authorize fully depreciated 

transportation assets to be recapitalized 

a second time when they are purchased 

from the original owner. ONRR 

proposes to remove this provision. 

Under proposed paragraph (i)(1)(ii), 

ONRR allows depreciation of pipeline 

assets only one time. If the pipeline 

asset is sold, we allow the purchaser to 

continue the remaining allowance 

depreciation schedule if applicable. 

This change makes Federal oil valuation 

consistent with ONRR’s other product 

valuation regulations. 

Proposed paragraph (i)(1)(iii)(B) 

changes the return on undepreciated 

capital investment from10 percent to the 

reasonable salvage value of the asset 

multiplied by the rate of return in 

proposed paragraph (i)(3) of this section. 

New proposed paragraph (i)(2) 

provides an alternative to depreciating 

the asset under paragraph (i)(1). Under 

this option, you may elect to use a cost 

equal to the allowable initial capital 

investment in the transportation system, 

multiplied by the rate of return in 

proposed paragraph (i)(3) of this section. 

If you chose this option, you may not 

include depreciation as a cost in your 

allowance. ONRR removed the 

provision limiting this option to 

transportation assets put in place after 

March 1, 1988. When ONRR published 

its Federal oil valuation regulations on 

May 5, 2004, it changed the 

requirements for transportation 

allowances. In recognition that certain 

transportation facilities had been given 

approval prior to these regulations’ 

effective date (August 1, 2004), ONRR 

made the new requirements apply only 

to facilities that were placed in service 

on or after the effective date of these 

regulations. Now, almost ten years later, 

ONRR believes that none of facilities 

affected by the 2004 rule change are still 

eligible for depreciation under the 

requirements in effect prior to August 1, 

2004. Therefore, we remove this 

language from the proposed regulations. 

Proposed paragraph (i)(3) would 

amend current 30 CFR 1206.111(i)(2) to 

change the Standard & Poor’s BBB bond 

rate we allow as an approximation of 

the cost of capital for non-arm’s-length 

transportation. Currently, 30 CFR 

1206.111(i)(2) allows a lessee to 

compute the rate of return on the 

undepreciated cost of capital by 

multiplying the undepreciated amount 

remaining by 1.3 times the Standard & 

Poor’s BBB bond rate. ONRR proposes 

to decrease the multiplier of the 

Standard & Poor’s BBB bond rate from 

1.3 to 1.0. In the final Federal oil 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
616 Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 

valuation regulations published in 

March 2000, we increased the multiplier 

of the Standard & Poor’s BBB bond rate 

from 1.0 to 1.3. We propose to change 

it back to 1.0 times the BBB bond rate 

because we believe this rate better 

reflects the cost of borrowing to finance 

capital expenditures involved in 

pipeline construction. It also is 

consistent with our other product 

valuation regulations. 

When a company or affiliate invests 

in shipping its own production, it 

considers if it can more profitably 

transport its own production or contract 

with a third party to provide the service. 

At this stage in production 

development, a company has a solid 

asset to demonstrate its ability to repay 

the capital investment necessary to 

construct the pipeline. ONRR consulted 

with FERC and has concluded that the 

BBB bond rate is an adequate 

representation for the cost of capital for 

the construction of producer-owned 

pipelines. 

1206.113 What adjustments and 

transportation allowances apply when I 

value oil production from my lease 

using NYMEX prices or ANS spot 

prices? 

1206.114 How will ONRR identify 

market centers? 

1206.115 What are my reporting 

requirements under an arm’s-length 

transportation contract? 

Proposed §§ 1206.113 through 

1206.115 are the same as current 30 CFR 

1206.112 through 1206.114, but we 

rewrite the sections in Plain Language 

and update the examples in current 30 

CFR 1206.112(d) using November 2012 

prices. 

1206.116 What are my reporting 

requirements under a non-arm’s-length 

transportation contract? 

This proposed section is the same as 

current 30 CFR 1206.115 except we 

make each sentence a paragraph. We 

also add a new paragraph (d) that 

explains you must follow the reporting 

requirements for arm’s-length contract 

under § 1206.115 if you are authorized 

under § 1206.112(j) to not use your 

actual costs. 

1206.117 What interest and penalties 

apply if I improperly report a 

transportation allowance? 

This proposed section is the same as 

current 30 CFR 1206.116 except we 

make each sentence a paragraph and 

add ‘‘penalties’’ to the heading to better 

describe the section. 

1206.118 What reporting adjustments 

must I make for transportation 

allowances? 

1206.119 How do I determine royalty 

quantity and quality? 

These two proposed sections, 30 CFR 

1206.118 and 1206.119, are the same as 

current §§ 1206.117 and 1206.119, 

respectively, but we rewrite the sections 

in Plain Language. 

1206.120 How are operating 

allowances determined? 

We propose to remove current 30 CFR 

1206.120 on how to determine operating 

allowances because it is unnecessary. If 

a lease has provisions for operating 

allowances, that lease term will govern 

valuation under proposed 

§ 1206.100(d)(4) of this subpart. 

Subpart D—Federal Gas 

ONRR proposes to add new 

§§ 1206.140 through 1206.149 to this 

subpart to codify, clarify, and enhance 

current ONRR Federal gas valuation 

practices. 

1206.140 What is the purpose and 

scope of this subpart? 

We propose to redesignate the current 

regulations at § 1206.150 to § 1206.160. 

Also, in this proposed rule, we rewrote 

the redesignated sections in Plain 

Language. Proposed § 1206.140 is the 

same as current 30 CFR 1206.150 except 

for three changes. First, we propose to 

add a new paragraph (b) to explain that 

the terms ‘‘you’’ and ‘‘your’’ in this 

subpart refer to the lessee. Second, we 

propose to redesignate paragraphs (b) 

and (c) as paragraphs (c) and (d). 

Finally, we propose to remove existing 

regulations in paragraph (d), which state 

this subpart is intended to ensure leases 

are administered in accordance with 

governing mineral leasing laws and 

lease terms. We believe current 

paragraph (d) is unnecessary and 

duplicative of our authority to 

promulgate this rule. 

1206.141 How do I calculate royalty 

value for unprocessed gas I or my 

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

non-arm’s-length contract? 

This proposed section explains the 

valuation of unprocessed gas for royalty 

purposes. Proposed paragraph (a)(1) 

explains that this section applies to 

unprocessed gas—meaning gas that is 

never processed—consistent with the 

current gas regulations. 

Proposed paragraph (a)(2) explains 

this section applies to gas you are not 

required to value under proposed 

§ 1206.142, or that ONRR does not value 

under proposed § 1206.144. Proposed 

§ 1206.142(a) explains what gas ONRR 

considers processed for valuation 

purposes, and proposed § 1206.144 

explains ONRR’s new proposed default 

valuation mechanism. We discuss 

proposed §§ 1206.142 and 1206.144 

below. 

Under proposed paragraph (a)(3), we 

state this section also applies to 

processed gas you must value prior to 

processing under § 1206.151 of this part. 

Proposed § 1206.151 contains the dual 

accounting provisions for Federal gas in 

current 30 CFR 1206.155. 

Under proposed paragraph (a)(4), we 

consider unprocessed gas any gas you 

sell prior to processing if price is based 

on an amount per MMBtu or Mcf, and 

not on the value of residue gas and gas 

plant products. Therefore, this proposed 

paragraph applies to the valuation of gas 

when price is not based on a processed 

gas price. 

Paragraph (b) proposes a new 

valuation methodology based on the 

first arm’s-length sale of the gas. ONRR 

promulgated the current gas valuation 

regulations in 1988 to achieve market 

value based on transactions between 

independent, non-affiliated parties. The 

Department has long believed the values 

established in arm’s-length transactions 

are the best indication of market value, 

and the 1988 rules reflect that belief. 

Although the Secretary’s 

responsibility to determine the royalty 

value of minerals produced has not 

changed, the industry and marketplace 

have changed dramatically since we 

wrote the 1988 regulations. As 

discussed below, industry and 

marketplace changes, as well as 

litigation necessitate changes to ONRR’s 

valuation regulations. Indeed, ONRR 

already amended the Indian gas (30 CFR 

part 1206, subpart E) and Federal oil (30 

CFR part 1206, subpart C) valuation 

regulations to simplify those regulations 

and provide early certainty by valuing 

those products based on the first arm’slength sale and/or on publicly available 

prices. 

When we developed the 1988 rules, 

producers most commonly sold natural 

gas at the wellhead to natural gas 

pipeline companies, which transported 

and sold the gas to local distribution 

companies. However, from mid-1980 to 

early 1990, a series of FERC rulemakings 

resulted in deregulation of some 

pipeline systems. As a result, industry 

now sells directly to end users or 

distributors, and pipelines only provide 

transportation services. Producers also 

created marketing affiliates to which 

they initially transferred production. 

For lessee sales to affiliates, the 

current Federal gas valuation 

regulations require a lessee to value 


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Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 617 

production based on a series of 

‘‘benchmarks’’ to be applied in a 

prescribed order (30 CFR 1206.152(c)). 

The first benchmark is the gross 

proceeds accruing to the lessee in a sale 

under its non-arm’s-length contract, 

provided that those gross proceeds are 

equivalent to the gross proceeds derived 

from, or paid under, comparable arm’slength contracts (30 CFR 

1206.152(c)(1)). This method has posed 

practical difficulties since companies 

are not privy to other companies’ 

‘‘comparable’’ sales transactions. In 

addition, ONRR and lessees have found 

it difficult to determine what portion of 

lease production a lessee must sell at 

arm’s-length to reliably determine the 

value of the remaining production. 

Likewise, the remaining benchmarks at 

30 CFR 1206.152(c)(2) and (3) have 

proven difficult for industry to follow 

and ONRR to administer. ONRR 

proposes to replace the current 

regulations in § 1206.152(c)(1), (2), and 

(3) with proposed paragraph (b). 

To simplify and clarify valuation of 

non-arm’s-length sales, proposed 

paragraph (b) bases value on the first 

arm’s-length sale with applicable 

allowances. The first arm’s-length sale 

may occur immediately, or may follow 

one or more non-arm’s-length transfers 

or sales of the gas. However, under the 

proposed rule, you will use the first 

arm’s-length sale regardless of whether 

you sell or transfer gas to one or more 

affiliates or other persons in non-arm’slength transactions before the first 

arm’s-length sale, and regardless of the 

number of those non-arm’s-length 

transactions. This arm’s-length sales 

value will apply unless you exercise the 

index-based option in proposed 

paragraph (c) of this section we discuss 

below. 

Proposed paragraph (b)(1) would state 

value is the gross proceeds accruing to 

you under an arm’s-length contract, less 

applicable allowances. 

Similarly, under proposed paragraph 

(b)(2), if you sell or transfer your Federal 

gas production to your affiliate, or some 

other person at less than arm’s length, 

and that person or its affiliate then sells 

the gas at arm’s length, royalty value 

will be the other person’s (or its 

affiliate’s) gross proceeds under the first 

arm’s-length contract. For example, a 

lessee might sell its Federal gas 

production to a person who is not an 

‘‘affiliate’’ as defined, but with whom its 

relationship is not one of ‘‘opposing 

economic interests’’ and therefore is not 

at arm’s length. An illustrative example 

is when a number of working interest 

owners in a large field form a 

cooperative venture that purchases all of 

the working interest owners’ production 

and resells the combined volumes to a 

purchaser at arm’s-length. Xeno, Inc., 

134 IBLA 172 (1995), involved a similar 

situation. If none of the working interest 

owners own 10 percent or more of the 

new entity, the new entity would not be 

an ‘‘affiliate’’ of any of them. 

Nevertheless, the relationship between 

the new entity and the respective 

working interest owners is not at arm’s 

length because of the lack of opposing 

economic interests regarding the 

contract. In this case, we believe it 

appropriate to value the production 

based on the arm’s-length sale price the 

cooperative venture receives for the gas. 

Therefore, under proposed paragraph 

(b)(2), you must value the production 

based on the gross proceeds accruing to 

you, your affiliate, or other person to 

whom you transferred the gas (or its 

affiliate) when the gas ultimately is sold 

at arm’s length, unless you elect to use 

the index pricing option we propose 

under § 1206.141(c) of this section or 

ONRR decides to value your gas under 

the new default valuation provision in 

proposed § 1206.144 discussed below. 

In summary, to provide early certainty 

and simplification, ONRR proposes to 

amend its valuation regulations for 

Federal gas to provide that, with certain 

exceptions, the first arm’s-length sale is 

the value for royalty purposes consistent 

with valuation of non-arm’s-length sales 

of Federal oil production under current 

30 CFR 1206.102(a). 

Proposed paragraph (b)(3) explains 

valuation if you, your affiliate, or 

another person sell under multiple 

arm’s-length contracts for gas produced 

from a lease that is valued under this 

proposed paragraph (b). In this case, 

unless you exercise the index-based 

option we provide in paragraph (c) of 

this section, because you sold non-arm’s 

length to your affiliate or another 

person, under the proposed rule, you 

must value the gas based on the volumeweighted average of the value 

established under this paragraph for 

each contract for the sale of gas 

produced from that lease. This is 

identical to current 30 CFR 1206.102(b) 

applicable to valuation of Federal oil. In 

addition, we believe this provision is 

consistent with ongoing practice under 

the current gas valuation rule. 

Proposed paragraph (b)(4) contains 

the provisions of the current gas 

valuation rule at 30 CFR 

1206.152(b)(1)(iv) that explains how to 

value over-delivered volumes under a 

cash-out program, but we rewrite this 

provision in Plain Language. 

ONRR proposes to add a new 

paragraph (c) containing an index price 

valuation methodology that a lessee may 

elect to use in lieu of valuing its gas 

under proposed paragraphs (b)(2) and 

(b)(3) of this section based on the gross 

proceeds accruing to its affiliate or other 

person under the first arm’s-length sale. 

The proposed methodology is based on 

publicly available index prices less a 

specified deduction to account for 

processing and transportation costs. 

Under the proposed rule, this valuation 

methodology also applies to ‘‘no 

contract’’ situations we describe below 

under paragraph (e). 

We believe this index price option 

simplifies the current valuation 

methodology and provides early 

certainty. Many pipelines and service 

providers now charge producers 

‘‘bundled’’ fees that include both 

deductible costs of transportation and 

non-deductible costs to place 

production into marketable condition. 

Both ONRR and lessees with arm’slength transportation contracts have 

found allocating the costs between 

placing the gas in marketable condition 

and transportation is administratively 

burdensome and time consuming. 

Similarly, when processing plants 

charge bundled fees that include nondeductible costs, the cost allocation is 

administratively burdensome and time 

consuming. 

Litigation also has complicated the 

application of ONRR’s gas valuation 

regulations. Although litigation has 

clarified what constitutes marketable 

condition, its application is fact specific 

and time consuming. See Devon and 

cases cited therein. 

The proposed index-based option 

provides a lessee with an alternative 

that is simple, certain, and avoids the 

requirements to ‘‘trace’’ production 

when there are numerous non-arm’slength sales prior to an arm’s-length sale 

and unbundle fees. Under this proposed 

paragraph (c), the lessee may choose to 

value its gas only in an area that has an 

active index pricing point published in 

a publication that ONRR approves. The 

lessee may elect to value its gas under 

this proposed paragraph, and that 

election is binding on the lessee for 2 

years. ONRR would post a list of 

approved publications at www.onrr.gov. 

ONRR proposes to use Platts and 

Natural Gas Intelligence as ONRRapproved publications but invites 

comments on whether these 

publications are appropriate, as well as 

whether there are other publications 

that ONRR should use. 

If the lease is in an area with active 

index pricing points, the lessee must 

determine the applicable index pricing 

point or points. We used the language 

in proposed paragraphs (c)(1)(i) and (ii) 

‘‘If you can only transport to one index 

pricing point’’ and ‘‘If you can transport 


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618 Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 

gas to more than one index pricing 

point,’’ respectively (emphasis added), 

because, under the proposed rule, we 

intend that for an index pricing point to 

be applicable, the lessee must be able to 

physically transport its gas by pipeline 

to that index pricing point. Further, an 

index pricing point would be applicable 

as long as the lessee could physically 

transport their gas by pipeline to that 

index pricing point (emphasis added). 

This means that under the proposed 

rule, the index pricing point applies 

even if the lessee could not transport its 

gas to that index pricing point because 

the pipeline is constrained (for example 

when all available capacity on a 

pipeline through which the lessee’s gas 

might flow to that index pricing point 

was already under contract to other 

parties). 

For example, assume you have a lease 

in the West Delta area of the Gulf of 

Mexico and your lease is physically 

connected by pipeline to the Mississippi 

Canyon Pipeline. In this case, your gas 

is physically capable of flowing to the 

Toca Plant (through the Southern 

Natural Gas Pipeline), the Yscloskey 

Plant (through the Tennessee Gas 

Pipeline), or the Venice Plant, and you 

have multiple index pricing points to 

which your gas can physically flow. 

Also, assume the highest reported 

monthly bid week price among the 

multiple index pricing points is the 

Tennessee Gas 500 Leg Price at the 

tailgate of the Yscloskey Plant. Finally, 

assume you cannot flow your gas 

through the Tennessee Gas Pipeline (to 

the Yscloskey Plant) because all 

available capacity on that pipeline is 

under contract to other persons, and the 

pipeline has no capacity available to 

you for the production month—in other 

words, it is constrained. In this 

example, you would use the highest 

reported monthly bid week price at the 

tailgate of the Yscloskey Plant as the 

value under this paragraph even though 

your gas did not flow to that index 

pricing point during the production 

month. 

Under proposed paragraph (c), the 

lessee could not use index pricing 

points if it could not physically 

transport its gas to that index pricing 

point because there is not a pipeline or 

series of pipelines that physically 

connect to the lease and flow from the 

lease to the index pricing point. ONRR 

would exclude the use of these index 

pricing points because they do not 

represent points at which the lessee can 

sell its gas, and it is difficult to adjust 

these prices for location differentials 

between the index pricing points and 

the lease. 

If the lessee can transport its gas to 

only one index pricing point, the value 

under proposed paragraph (c)(1)(i) is the 

highest reported monthly bid week 

price for that index pricing point in the 

ONRR-approved publication for the 

production month. If the lessee can 

transport its gas to more than one index 

pricing point, the value under proposed 

paragraph (c)(1)(ii) is the highest 

reported monthly bid week price for the 

index pricing points to which the lessee 

could transport its gas, in the ONRRapproved publication for the production 

month. However, under paragraph 

(c)(1)(iii), if there are sequential index 

pricing points on a pipeline, the lessee 

would use the first index pricing point 

at or after the lessee’s gas enters the 

pipeline. 

ONRR recognizes that index pricing 

points are normally located off the lease, 

and frequently at lengthy distances from 

the lease. Thus, under proposed 

paragraph (c)(1)(iv), ONRR allows a 

lessee to reduce the highest reported 

monthly bid week price by a set amount 

to account for transportation costs a 

lessee would incur to move the gas from 

the lease to an applicable index pricing 

point. ONRR proposes to allow a lessee 

to reduce the highest reported monthly 

bid week prices by 5 percent for sales 

from the OCS Gulf of Mexico and by 10 

percent for sales from all other areas, 

but not by less than 10 cents per MMBtu 

or more than 30 cents per MMBtu. 

ONRR proposes these percent 

reductions based on the average gas 

transportation rates that lessees have 

reported to ONRR from 2007 through 

2010 for OCS and all other areas. 

ONRR proposes to allow a lessee to 

choose the index price methodology to 

value its gas under this paragraph for 

the following reasons: (1) It relies on a 

market price at which gas is sold from 

the area during the production month; 

(2) it recognizes costs that a lessee must 

incur to transport gas from the lease to 

an index pricing point; and (3) it makes 

payment and verification of royalties 

paid simple and efficient, thereby 

saving both lessees and ONRR 

significant administrative costs. Further, 

ONRR believes this alternative 

methodology provides ONRR with a 

reasonable market value for the lessee’s 

gas that avoids requiring a lessee and 

ONRR to track every resale of the 

lessee’s gas during the production 

month, especially when those sales can 

involve several transactions hundreds of 

miles downstream from the lease. As we 

state above, it also avoids the 

unbundling of transportation and 

processing costs. 

ONRR proposes to use the highest 

reported monthly bid week price with a 

reduction for transportation costs. We 

propose this because it generally 

represents the gross proceeds net of 

transportation allowances accruing to 

lessees that ONRR believes are most 

likely to choose this option to value 

their gas based on information lessees 

and others reported on Form ONRR– 

2014 for the period from 2007 through 

2011. 

Proposed paragraph (c)(1)(v) states 

that, after you select an ONRR-approved 

publication available at www.onrr.gov, 

you may not select a different 

publication more often than once every 

2 years. ONRR also proposes, under 

paragraph (c)(1)(vi), to exclude 

individual index prices from this option 

if we determine that the index price 

does not accurately reflect the value of 

production. ONRR plans to disallow the 

use of index prices with low liquidity, 

such as those classified as Tier 3 in the 

Platts publications. ONRR would post a 

list of excluded index pricing points at 

www.onrr.gov. We would appreciate 

comments on this proposal. 

Proposed paragraph (c)(2) explains 

that you may not take any other 

deductions from the value calculated 

under this paragraph (c) because you 

would already receive a reduction for 

transportation under proposed 

paragraph (c)(1)(iv). 

Proposed paragraph (d)(1) provides 

that, if you have no written contract or 

no sale of gas subject to this section and 

there is an index pricing point for the 

gas, then you must value your gas under 

the index pricing provisions of 

paragraph (c) of this section unless 

ONRR values your gas under § 1206.144. 

This provision includes, but is not 

limited to, when: (1) The lessee sells its 

gas to an affiliate and the affiliate uses 

the gas in its facility; (2) the lessee sells 

its gas to an affiliate and the affiliate 

resells the gas to another affiliate of 

either the lessee or itself and that 

affiliate uses the gas in its facility; (3) 

the lessee uses the gas as fuel for its 

other leases in the field or area; or (4) 

the lessee delivers gas to another person 

as payment of an overriding royalty 

interest that other person holds. 

Proposed paragraph (d)(2) addresses 

situations in which you have no 

contract for the sale of gas subject to this 

section and there is not an index pricing 

point for the gas. In these situations, 

ONRR will decide the value under 

§ 1206.144. However, when this occurs, 

under paragraph (d)(2)(i), we require 

that you propose to ONRR a method to 

determine the value using the 

procedures in proposed § 1206.148(a). 

Proposed § 1206.148(a) describes the 

information you must provide to ONRR 

when you request a valuation 


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Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 619 

determination. Proposed paragraph 

(d)(2)(ii) allows you to use your 

proposed method until ONRR issues a 

decision. After ONRR issues a 

determination, under paragraph 

(d)(2)(iii), you will have to make any 

adjustment under proposed 

§ 1206.143(a)(2). You have to make 

adjustments only if ONRR decides you 

must use a different methodology than 

you propose under paragraph (d)(2)(i). 

1206.142 How do I calculate royalty 

value for processed gas I or my affiliate 

sell(s) under an arm’s-length or nonarm’s-length contract? 

ONRR proposes a new § 1206.142 

including a new paragraph (a) that 

amends and expands what is processed 

gas for royalty valuation purposes. 

Currently, when gas is sold under an 

arm’s-length contract prior to 

processing, and the lessee neither 

retains nor exercises any rights to the 

gas after processing (in other words, an 

outright sale before the plant), such gas 

is valued as unprocessed gas. Included 

are contracts where the title passes 

before processing, but payment is based 

on the values of residue gas and gas 

plant products after processing. 

Percentage-of-Proceeds (POP) contracts 

(contracts where the lessee’s arm’slength contract for the sale of that gas 

prior to processing provides for the 

value to be determined on the basis of 

a percentage of the purchaser’s proceeds 

resulting from processing the gas) are 

the most common of these contracts, but 

ONRR has observed a myriad of 

variations of such contracts. Because 

this gas is valued as unprocessed gas 

under the current regulations, there are 

no limits on the minimum value of such 

gas for royalty purposes, except for gas 

sold under arm’s-length POP contracts, 

which has a minimum value of 100 

percent of the residue gas. No such 

limitation applies to contracts that do 

not specifically qualify as POP 

contracts. 

For example, if the sales value is 

based on a percentage of an index price 

for residue gas and/or NGLs, the current 

regulations base value simply on the 

gross proceeds the lessee receives under 

the contract. In essence, the 

unprocessed gas regulations allow such 

sales arrangements to reduce the value 

of residue gas below the 100-percent 

minimum value required under the 

processed gas regulations and below the 

1-percent minimum value for NGLs 

(assuming ONRR approves an exception 

under the current rules in excess of 662⁄3

percent of the NGL value) required for 

processed gas. 

ONRR has seen numerous contract 

arrangements that provide payment 

terms based on: (1) A percentage of the 

volume or value of residue gas, plant 

products, or any combination of the two 

actually recovered at the plant; (2) the 

full volume and value of residue gas 

and/or plant products recovered at the 

plant, less a flat fee per MMBtu of wet 

gas entering the plant; (3) a combination 

of (1) and (2); and (4) the value of a 

percentage of the theoretical volumes of 

residue gas and/or plant products 

contained in the wet gas stream (socalled casing head gas contracts). 

Because the many contract variations 

base the underlying value on processed 

gas values, ONRR believes we should 

require a lessee to value gas sold under 

such contracts as processed gas for 

royalty purposes. This proposal 

provides the protection the current 

processed gas regulations have against 

excessive transportation and processing 

allowances and prevents a lessee from 

structuring contracts to avoid these 

requirements. Such a change also 

clarifies if gas is processed gas or 

unprocessed gas. 

In summary, under proposed 

paragraph (a)(1), ONRR will consider 

gas you or your affiliate do not sell or 

otherwise dispose of under an arm’slength contract before processing 

‘‘processed gas.’’ Paragraph (a)(1) also 

applies to non-arm’s-length sales of gas 

before processing and transfers to a 

plant without a contract like the current 

regulations. 

Proposed paragraph (a)(2) applies to 

the situations described above when 

payment is based on any constituent 

products resulting from processing, 

such as residue gas, NGLs, sulfur, or 

carbon dioxide. We would value POP 

contracts, percentage-of-index contracts, 

casing head gas contracts, and contracts 

with any such variations of payment 

based on volumes or value of those 

products as processed gas. With the 

exception of POP contracts, this 

constitutes a departure from current 

practice. 

Proposed paragraph (a)(3), while not a 

change in current regulatory practice, 

explicitly states that the lessee must 

value gas processed under a keepwhole 

contract as processed gas. Under 

proposed § 1206.20, we define a 

keepwhole contract as a processing 

agreement under which the processor 

compensates the lessee by delivering to 

the lessee a quantity of residue gas after 

processing equivalent to the quantity of 

gas the processor received prior to 

processing, normally based on heat 

content, less gas used as plant fuel and 

gas that is unaccounted for and/or lost. 

The lessee does not receive NGLs under 

these contracts. Over the past several 

years, ONRR has witnessed much 

confusion over how to value gas sold 

under such contracts for royalty 

purposes. This provision makes it clear 

that the lessee must value gas processed 

under a keepwhole contract as 

processed gas. That is, royalty would be 

based on 100 percent of the value of 

residue gas, 100 percent of the value of 

gas plant products, plus the value of any 

condensate recovered downstream of 

the point of royalty settlement prior to 

processing, less applicable 

transportation and processing 

allowances. 

To illustrate how to calculate the 

processing allowance in these cases, 

assume you deliver 32,000 MMBtu of 

natural gas to the gas processing plant. 

Also assume 7,000 MMBtu represents 

the shrinkage volume (the MMBtu 

equivalent of the NGLs recovered), and 

the plant recovers and retains 92,000 

gallons of NGLs from your gas. Further, 

assume the plant returns 7,000 MMBtu 

of gas to you at the tailgate of the plant 

in addition to the residue gas that 

results after processing your gas to 

‘‘keep you whole.’’ Finally, assume the 

7,000 MMBtu of gas returned to you is 

worth $42,000 and the NGLs the plant 

retained are worth $63,000. In this 

example, the cost you incur to process 

the gas is $21,000 ($63,000¥$42,000). If 

you incur additional costs, for example 

a $0.03 per MMBtu fee times the 32,000 

MMBtu you deliver to the plant for 

processing, then you add those 

additional costs (in this example, $960) 

to the $21,000 cost calculated above to 

determine your total processing costs (in 

this example $21,960). 

Proposed paragraph (a)(4) simply 

restates current 30 CFR 1206.153(a)(1) 

regarding arm’s-length contracts and 

reservations of rights to process gas the 

lessee or its affiliate exercises. 

ONRR also proposes paragraph (b), 

which contains the same requirements 

as current 30 CFR 1206.153(a)(2), but we 

rewrite it in Plain Language, without 

substantive change. 

Like the valuation of unprocessed gas 

under proposed § 1206.141(b), proposed 

paragraph (c) provides that the value of 

residue gas or any gas plant product 

under this section is the gross proceeds 

accruing to you or your affiliate under 

the first arm’s-length contract. Also, like 

proposed § 1206.141(b), this value does 

not apply if you exercise the indexbased option we provide in paragraph 

(d) of this section or if ONRR decides to 

value your residue gas or any gas plant 

product under the new default valuation 

provision in § 1206.144. Proposed 

paragraphs (c)(1), (2), (3), and (4) 

explain to which transactions this 

paragraph applies. See the discussion of 


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620 Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 

the identical proposal for proposed 

§§ 1206.141(b)(1), (2), (3), and (4) above. 

Proposed paragraph (d) contains the 

index-based valuation option for 

valuation of your residue gas and NGLs. 

Under this proposed rule, you may elect 

to value either your residue gas or your 

NGLs under the index-based option, or 

you may elect to value both of them 

under this option if your residue gas or 

NGLs meet the requirements for using 

the optional valuation methodology we 

discuss above. Like the current Federal 

oil regulations (30 CFR 

1206.102(d)(1)(ii)) and proposed 

§ 1206.141(c), you cannot change your 

election to use this paragraph (d) to 

value your gas more often than once 

every two years. 

Proposed paragraph (d)(1) applies to 

residue gas. It has the same index price 

option as proposed §§ 1206.141(c)(i) 

through (vi) we discuss above using 

index pricing points. 

Proposed paragraph (d)(2) contains 

the index-based pricing option for 

NGLs. Under paragraph (d)(2)(i), if you 

sell NGLs in an area with one or more 

ONRR-approved commercial price 

bulletins available at www.onrr.gov, you 

may choose one bulletin, and your value 

for royalty purposes would be the 

monthly average price for that bulletin 

for the production month. We consider 

you to be selling NGLs in an area with 

an ONRR-approved commercial price 

bulletin if actual sales of NGLs that the 

plant processing your gas recovers are 

made using NGLs prices in an ONRRapproved commercial price bulletin. For 

example, in ONRR’s experience, actual 

sales of NGLs recovered in plants in 

New Mexico commonly reference Mt. 

Belvieu prices in Platts, while actual 

sales of NGLs recovered in plants in 

certain parts of Wyoming reference Mt. 

Belvieu or Conway, Kansas prices. If 

your gas is processed at one of these 

plants with these types of actual sales 

arrangements, under this proposed rule, 

ONRR will consider you to be selling 

NGLs in an area with an ONRRapproved commercial price bulletin. In 

that case, you may elect to value your 

NGLs using the index price method if 

your NGLs meet the requirements for 

using that method. ONRR will monitor 

actual sales of NGLs and eliminate any 

area where an active market using NGLs 

prices in an ONRR-approved 

commercial price bulletin ceases to 

exist. 

Under proposed paragraph (d)(2)(ii), 

you may reduce the index-based value 

you calculate under paragraph (d)(2)(i) 

by a specified amount to account for a 

theoretical processing allowance and 

transportation and fractionation (T&F). 

Therefore, the reduction includes two 

components we calculated—an 

allowance based on processing 

allowance information lessees report to 

ONRR and T&F based on our review of 

gas plant contracts and gas plant 

statements. 

For the processing allowance 

component, ONRR examined processing 

allowances that lessees and others 

reported from January 2007 through 

October 2011. We segregated the data 

into 2 subsets—the first being the Gulf 

of Mexico (GOM) and the second being 

onshore Federal leases and OCS leases 

other than those in the GOM. We 

segregated the leases geographically 

because the GOM is closer to major 

market centers at Mt. Belvieu, 

Napoleonville, and Geismer/Sorrento 

and, generally, has its own processing, 

transportation, and fractionation 

regimen that is distinct from the rest of 

the country. We do not believe it is fair 

or accurate to benchmark processing for 

the entire country based on the 

economics of GOM processing. 

We could not segregate non-arm’slength processing allowances because 

lessees do not identify processing 

allowances as arm’s-length or nonarm’s-length when they report to ONRR. 

Rather, we calculated a weighted 

average cents per gallon processing 

allowance by month for both GOM and 

all other Federal leases. Using the 

weighted average cents per gallon 

processing allowance we calculated, we 

determined the average allowance rate 

over the 5-year period, along with the 

maximum and minimum monthly rates 

as follows: 

GOM Other 

Average Rate ..................................................... 17 ¢/gal ............................................................. 22 ¢/gal. 

Maximum Rate .................................................. 29 ¢/gal ............................................................. 32 ¢/gal. 

Minimum Rate ................................................... 10 ¢/gal ............................................................. 15 ¢/gal. 

Because we intend for this option to 

provide a simple method for ONRR to 

calculate and provide to lessees, we 

used the minimum, rather than the 

average rate, for the processing 

allowance portion of the deduction. For 

both the GOM and all other Federal 

leases, the minimum rate is 7 cents less 

than the average rate. ONRR believes 

that: (1) The minimum allowance best 

protects the public interest and (2) a 

lessee experiencing higher costs than 

this rate does not have to elect to use 

this option and the lower cost 

allowance. Moreover, ONRR believes 

that 7 cents is a reasonable tradeoff 

given the simplicity, certainty, and 

commensurate administrative savings 

this option would provide a lessee. 

For the T&F part of the reduction, 

ONRR examined contracts that specified 

T&F. If contracts did not specify T&F, 

we looked at the gas plant statements. 

If the statements listed T&F as a line 

item, we used that line item as the T&F. 

If the statements did not list T&F as a 

line item, we calculated the difference 

between the price on the plant 

statement and an appropriate published 

price to approximate the T&F. We then 

averaged these T&F costs for GOM, New 

Mexico, and other as follows: 

GOM New Mexico Other 

Average T&F .................................. 5 ¢/gal ........................................... 7 ¢/gal ........................................... 12 ¢/gal. 

We broke out New Mexico because 

the T&F fees for New Mexico plants 

were consistently around 7 cents per 

gallon and were considerably less than 

for other onshore plants. We then added 

the processing allowances we calculated 

and the T&F. Based on the 5-years’ 

worth of data discussed above, we 

calculated the total NGLs reductions 

lessees could use under this option are 

as follows: 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 621 

GOM New Mexico Other 

NGLs Deduction ............................ 15 ¢/gal ......................................... 22 ¢/gal ......................................... 27 ¢/gal. 

Under paragraph (d)(2)(ii), rather than 

publish the reductions in the CFR, 

ONRR proposes to post the reductions at 

www.onrr.gov for the geographic 

location of your lease. ONRR proposes 

to calculate the reductions using the 

methodology explained above. This 

process would give ONRR the flexibility 

to quickly recalculate and provide 

revised reductions to lessees in response 

to market changes. This methodology 

would be binding on you and ONRR. 

Under paragraph (d)(4), ONRR would 

update the allowable reductions 

periodically using this methodology and 

post changes at www.onrr.gov. 

Proposed paragraph (d)(2)(iii) 

explains that after you select an ONRRapproved commercial price bulletin 

available at www.onrr.gov, you may not 

select a different commercial price 

bulletin more often than once every two 

years. Under proposed paragraph (d)(3), 

you may not take any other deductions 

from the value you used under this 

paragraph (d) because it already 

includes reductions for transportation 

and processing. 

Proposed paragraph (e) mirrors 

proposed § 1206.141(d). It explains how 

you must value your processed gas if 

you have no written contract for the sale 

of gas or no sale of the gas subject to this 

section. 

1206.143 How will ONRR determine if 

my royalty payments are correct? 

In this section, ONRR proposes 

amendments to the current gross 

proceeds provisions, rewriting them in 

Plain Language and making them 

consistent with our other product 

valuation regulations (such as 

geothermal resources and Federal oil). 

Like those published regulations, rather 

than repeating the requirements or 

procedures in each applicable section of 

this proposed rule, ONRR proposes to 

apply this section to this entire subpart. 

However, the substantive requirements 

of proposed paragraphs (d), (e), and (f) 

remain unchanged. Below we discuss 

the paragraphs with substantive 

changes. 

Proposed paragraph (a)(1), like our 

current regulations, states ‘‘ONRR may 

monitor, review, and audit the royalties 

you report, and, 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 . . . .’’ 

However, we propose to add paragraph 

(a)(1) that states in addition to directing 

you to use a different measure of value, 

we also may decide your value under 

§ 1206.144 as we discuss below. 

Proposed paragraph (b), like our 

current regulations, explains ‘‘[w]hen 

the provisions in this subpart refer to 

gross proceeds, in conducting reviews 

and audits, ONRR will examine if your 

or your affiliate’s contract reflects the 

total consideration actually transferred, 

either directly or indirectly, from the 

buyer to you or your affiliate for the gas, 

residue gas, or gas plant products.’’ 

However, we propose to add a new 

paragraph (b) that if ONRR determines 

a contract does not reflect the total 

consideration, ONRR may decide your 

value under § 1206.144 as we discuss 

below. 

Proposed paragraph (c) broadly 

defines three circumstances when 

ONRR will calculate the value of your 

gas using the method specified in the 

new proposed ‘‘default’’ valuation 

§ 1206.144. During its compliance 

activities, ONRR encounters a wide 

range of situations in which lessees 

have inaccurately calculated value. By 

broadly defining the circumstances in 

which ONRR may calculate value, this 

proposed rule ensures ONRR can fulfill 

its statutory mandate under FOGRMA to 

ensure that lessees accurately calculate, 

report, and pay royalties (30 U.S.C. 1701 

and 1711). 

Proposed paragraphs (c)(1) and (c)(2) 

contain the provisions regarding 

misconduct and breach of the duty to 

market in current 30 CFR 

1206.152(b)(1)(i) and 1206.153(b)(1)(iii). 

Under the current regulations, if ONRR 

determines there is misconduct between 

the parties, or that the lessee has 

breached its duty to market, then the 

lessee must value its gas under the 

current benchmarks for non-arm’slength sales of gas in 30 CFR 

1206.152(c)(2) or (c)(3) (unprocessed 

gas) and 1206.153(c)(2) or (c)(3) 

(processed gas). However, as we discuss 

above, ONRR proposes to eliminate the 

benchmarks in this rulemaking. We 

propose instead that if ONRR 

determines there is misconduct between 

the parties to a contract or the lessee has 

breached its duty to market, we may 

decide your value under § 1206.144 as 

we discuss below. 

As we discuss above in proposed 

§ 1206.20, misconduct, for purposes of 

proposed paragraph (c)(1), means 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. Misconduct, in this 

subpart, would be different than, and in 

addition to, any violations subject to 

civil penalties under FOGRMA, 30 

U.S.C. 1719, and its implementing 

regulations in part 1241 of this chapter. 

Behavior that constitutes misconduct, 

under this part 1206, would not need to 

be willful, knowing, voluntary, or 

intentional. This is a valuation 

mechanism, not an enforcement tool. 

Under this proposed rule, if ONRR 

determines that misconduct has 

occurred, ONRR will calculate value 

under § 1206.144. However, if ONRR 

determines the misconduct was 

knowing or willful, it also could pursue 

civil penalties under part 1241 of this 

chapter. 

Under proposed paragraph (c)(2), 

ONRR defines what is a breach of the 

duty to market. The proposed rule 

specifies that ONRR may determine 

value under § 1206.144 if a lessee sells 

gas, residue gas, or gas plant products at 

an unreasonably low price. The 

proposed rule explains what ONRR 

could consider an ‘‘unreasonably low’’ 

price. A lessee has a duty to market gas 

for the mutual benefit of the United 

States, as lessor, and the lessee. An 

unreasonably low price may reflect a 

failure of the lessee to perform that 

duty. Proposed paragraph (a)(2) defines 

a sales price as ‘‘unreasonably low’’ ‘‘if 

it is 10 percent less than the lowest 

reasonable measures of market price, 

including, but not limited to, index 

prices and prices reported to ONRR for 

like-quality gas, residue gas, or gas plant 

products.’’ ONRR’s authority to exercise 

this provision is discretionary; ONRR 

‘‘may’’ decide your value if it 

determines your price is unreasonably 

low. In exercising its discretion, ONRR 

may consider any information that 

shows a price appears unreasonably 

low, and, thus, is not an accurate 

reflection of fair market value. 

ONRR also proposes a new paragraph 

(c)(3). Under proposed paragraph (c)(3), 

ONRR may value your gas, residue gas, 

or gas plant products under § 1206.144 

if ONRR cannot determine if you 

properly valued your gas, residue gas, or 

gas plant products under § 1206.141 or 

§ 1206.142 for any reason. This is a 

broad ‘‘catch-all’’ provision ONRR may 


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use to decide the value of gas, residue 

gas, or gas plant products when it 

cannot determine if a lessee properly 

valued its production. ONRR will 

exercise this discretionary authority to 

meet its mandate under 30 U.S.C. 1711 

to ensure accurate accounting for 

Federal oil and gas royalties under the 

different circumstances it encounters 

during its compliance verification 

activities. It is the lessee’s responsibility 

to provide ONRR with information 

sufficient for us to ensure that royalties 

are accurately calculated. Under this 

provision, ONRR will still meet its 

statutory mandate even when a lessee 

fails to provide sufficient information. 

However, like proposed paragraph (c)(1) 

of this section, this is an ONRR 

valuation mechanism that is in addition 

to any civil penalty authority ONRR has 

under part 1241 of this chapter. 

We propose a new paragraph (g)(1) 

that requires the lessee or its affiliate to 

make all contracts in writing before it 

can use the contracts as the basis for the 

lessee’s valuation of its gas produced 

from Federal leases. This proposed 

requirement will apply to any contract 

revisions or amendments. Further, 

ONRR proposes that all parties to the 

contract must sign the contracts, 

contract revisions, or amendments 

before lessees can use them as the basis 

for the lessee’s valuation of its gas under 

these regulations. 

ONRR believes this proposed 

requirement is critical to the proper 

application of the valuation regulations. 

Lessees should provide to ONRR the 

actual, written contracts signed by all 

parties because those contracts 

document the very transactions on 

which the regulations require lessees to 

base values and allowances. Without the 

applicable sales, transportation, and/or 

processing contracts, neither the lessee 

nor ONRR can verify that Federal 

royalties are properly paid. Because 

ONRR would only require a lessee to 

provide its actual contractual 

arrangements that it uses to conduct its 

business, this requirement should place 

no burden on a lessee. 

ONRR proposes a new paragraph 

(g)(2) providing that ONRR may decide 

the value of a lessee’s gas if the lessee 

or its affiliate fails to make all contracts, 

contract revisions, or amendments in 

writing. If the lessee cannot produce the 

written, signed contracts that would 

otherwise serve as the basis of the 

lessee’s valuation of its gas under the 

regulations, ONRR may decide to 

determine the appropriate value of the 

lessee’s gas under newly proposed 

§ 1206.144 as we discuss below. 

Finally, ONRR proposes to add 

paragraph (g)(3) to make clear the new 

provision requiring contracts to be in 

writing and signed by all parties is in 

addition to any other recordkeeping 

requirements the lessee must satisfy 

under this title, and that this new 

requirement supersedes any provision 

in this title to the contrary. 

1206.144 How will ONRR determine 

the value of my gas for royalty 

purposes? 

ONRR proposes a new ‘‘default’’ 

valuation § 1206.144 that ONRR may 

use to value your gas, residue gas, or gas 

plant products for royalty purposes. 

Because we propose the same default 

provision for federal oil, please refer to 

§ 1206.105 above for more information. 

1206.145 What records must I keep to 

support my calculations of royalty 

under this subpart? 

1206.146 What are my responsibilities 

to place production into marketable 

condition and to market production? 

1206.147 When is an ONRR audit, 

review, reconciliation, monitoring, or 

other like process considered final? 

1206.148 How do I request a valuation 

determination or guidance? 

See discussion below. 

1206.149 Does ONRR protect 

information I provide? 

1206.150 How do I determine royalty 

quantity and quality? 

ONRR proposes to rewrite in Plain 

Language the regulations for 

recordkeeping, marketable condition 

and marketing, audit, confidentiality, 

and quantity and quality requirements 

and procedures. Also, ONRR proposes 

to make these sections consistent with 

other product valuation regulations, 

such as the geothermal and Federal oil 

regulations. In addition, rather than 

repeat the requirements or procedures 

in each applicable section of this rule, 

ONRR proposes to have these sections 

apply to this entire subpart. The 

substantive requirements remain 

unchanged. 

1206.148 How do I request a valuation 

determination or guidance? 

ONRR proposes a new § 1206.148 on 

how to request a valuation 

determination or guidance. This section 

is the same as § 1206.108 applicable to 

Federal oil we discuss above, with 

several substantive changes. Proposed 

§ 1206.148 replaces and expands the 

provisions contained in current 30 CFR 

1206.152(g) and 1206.153(g). The newly 

proposed section provides greater 

clarity on the process lessees may use to 

request valuation guidance and 

determinations, as well as on the effect 

of ONRR’s response to such requests. 

Adding proposed § 1206.148 will make 

the procedures for gas valuation 

requests consistent with the procedures 

ONRR proposes for Federal oil and 

Federal and Indian coal. 

Under proposed paragraph (a), a 

lessee may request a valuation 

determination or guidance from ONRR 

regarding any gas produced. Paragraph 

(a)(1) through (3) explains that the 

lessee’s request must be in writing; 

identify all leases involved, all interest 

owners in the leases, and the operator(s) 

for those leases; and completely explain 

all relevant facts. In addition, under 

paragraphs (a)(4) through (6), a lessee 

must provide all relevant documents, its 

analysis of the issue(s), citations to all 

relevant precedents, including adverse 

precedents, and its proposed valuation 

method. 

In response to a lessee’s request, 

under proposed paragraph (b), ONRR 

may (1) decide that it will issue 

guidance, (2) inform the lessee in 

writing that it will not provide a 

determination or guidance, or (3) 

request that the Assistant Secretary for 

Policy, Management, and Budget issue a 

determination. This proposal changes 

the current Federal oil regulations under 

30 CFR 1206.107(b), which has caused 

confusion over whether an ONRRissued determination is a binding 

appealable order or non-appealable 

guidance. Under this proposed rule, 

ONRR clarifies that we only issue nonbinding guidance for valuation of 

Federal oil and gas and Federal and 

Indian coal. This proposal is consistent 

with ONRR’s existing practice of having 

only the Assistant Secretary sign 

decisions that are binding on the 

Department. Also, ONRR proposes to 

remove the regulatory language that we 

will ‘‘reply to requests expeditiously.’’ 

Our practice is to reply as quickly as 

possible, so we do not make it a 

regulatory requirement. 

Proposed paragraphs (b)(3)(i) and (ii) 

identify situations in which ONRR and 

the Assistant Secretary typically do not 

provide a determination or guidance, 

including, but not limited to, requests 

for guidance on hypothetical situations 

and matters that are the subject of 

pending litigation or administrative 

appeals. 

Under proposed paragraph (c)(1), a 

determination the Assistant Secretary of 

Policy, Management and Budget signs 

binds both the lessee and ONRR unless 

the Assistant Secretary modifies or 

rescinds the determination. After the 

Assistant Secretary issues a 

determination, under proposed 

paragraph (c)(2), the lessee must make 


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any adjustments to its royalty payments 

that follow from the determination. If 

the lessee owes additional royalties, it 

must pay the additional royalties due 

plus late payment interest calculated 

under §§ 1218.54 and 1218.102 of this 

chapter. In addition, proposed 

paragraph (c)(3) explains that a 

determination the Assistant Secretary 

signs is the final action of the 

Department and is subject to judicial 

review under 5 U.S.C. 701–706. 

Proposed paragraph (d) explains that, 

if ONRR issues guidance, the guidance 

is not binding on ONRR, delegated 

States, or the lessee with respect to the 

specific situation addressed in the 

guidance. This is a change from the 

current Federal oil regulation at 30 CFR 

1206.107(d) that makes a determination 

ONRR issues binding on ONRR and 

delegated States but not the lessee. 

Moreover, guidance, ONRR’s decision 

whether to issue guidance, and ONRR’s 

decision whether to request a 

determination by the Assistant Secretary 

would not be appealable decisions or 

orders under 30 CFR part 1290. This is 

the same as current 30 CFR 

1206.107(d)(1). However, as provided 

under current 30 CFR 1206.107(d)(2), 

under proposed paragraph (d)(2) of this 

section, if ONRR issues an order 

requiring the lessee to pay royalty on 

the same basis as the guidance, the 

lessee could appeal the order under 30 

CFR part 1290. 

Under proposed paragraph (e), ONRR 

or the Assistant Secretary may use any 

of the applicable criteria in this subpart 

to make a determination or provide 

guidance. Also, under proposed 

paragraph (f), if a statute or regulation 

on which ONRR based any 

determination or guidance is changed, 

the changed statute or regulation takes 

precedence over the determination or 

guidance after the effective date of the 

statute or regulation, regardless of 

whether ONRR or the Assistant 

Secretary modifies or rescinds the 

determination or guidance. Therefore, 

under this proposed provision, 

determinations and guidance are not 

open-ended. 

1206.151 How do I perform accounting 

for comparison? 

ONRR proposes to move the 

regulations in current 30 CFR 1206.155 

to proposed § 1206.151, but we rewrite 

this section in Plain Language. This 

section requires a lessee to pay royalties 

on the greater of the value of the 

unprocessed gas or the value of its 

processed gas if the lessee, its affiliate, 

a person to whom the lessee transferred 

gas under a non-arm’s-length contract, 

or a person to whom the lessee 

transferred gas without a contract 

processes the lessee’s or its affiliate’s gas 

and does not sell the residue gas at 

arm’s length. However, ONRR requests 

comments on whether we need this 

proposed requirement for two reasons. 

First, proposed §§ 1206.142 and 

1206.143 of this subpart recognize the 

real market value of gas today is the 

combined value of its constituent 

components—residue gas and gas plant 

products. And, the proposed regulations 

value gas sold on that basis as processed 

gas. There appears to be a limited 

market for unprocessed gas, unless it is 

sold based upon the constituent 

products contained therein, hence 

accounting for comparison may not be 

needed. Second, because the criteria 

that triggers dual accounting—a nonarm’s-length sale of residue gas after 

processing—is not used to value gas 

under this proposed rule, dual 

accounting may no longer be 

appropriate because the residue gas is 

valued based on the first arm’s-length 

sale or index-based option. 

ONRR also proposes to keep the 

requirement in current 30 CFR 1206.155 

that lessees must perform dual 

accounting if required by lease terms. 

ONRR believes this provision is 

consistent with proposed 

§ 1206.140(c)(4), which specifically 

recognizes the primacy of lease terms 

over the terms of the regulations when 

they are inconsistent. 

Before we discuss each section of 

proposed §§ 1206.152 through 1206.158 

regarding transportation allowances, we 

believe it is helpful to discuss some 

general changes we make. The proposed 

regulations move the current regulations 

regarding transportation allowances 

from 30 CFR 1206.156 and 1206.157 to 

proposed §§ 1206.152 through 1206.158. 

The proposed gas transportation 

allowance regulations are changed, 

primarily in structure, but there also are 

a few substantive changes. The structure 

of the proposed gas transportation 

allowance regulations is modeled after 

the current Federal oil transportation 

allowance regulations to achieve 

consistency between the two. In most 

cases, the regulatory requirements do 

not change. We reorganize the current 

provisions and rewrite them in Plain 

Language. Like the current oil 

transportation allowance regulations, 

this structure provides more regulatory 

section headings, better organization, 

and greater visibility to locate regulatory 

requirements applicable to the lessee’s 

particular transportation allowance 

situations. Also, we reorganize or 

combine many paragraphs that were 

embedded within a current section into 

a new section for greater visibility. We 

propose to segregate individual multiple 

requirements within paragraphs into 

separate paragraphs to improve 

visibility and identification. 

1206.152 What general transportation 

allowance requirements apply to me? 

Proposed § 1206.152 retains the 

provisions in current § 1206.156 

(‘‘Transportation allowances—general’’), 

makes Federal gas regulations consistent 

with Federal oil regulations, and 

consolidates provisions applicable to 

both arm’s-length and non-arm’s-length 

transportation in the current regulations 

rather than repeating those provisions in 

the respective sections explaining those 

allowances. We also rewrite the current 

regulations in Plain Language and only 

discuss substantive changes and 

additions below. 

Proposed paragraph (a) contains the 

same requirements as current 

§ 1206.156(a) and includes a new 

provision that ‘‘[y]ou may not deduct 

transportation costs you incur to move 

a particular volume of production to 

reduce royalties you owe on production 

for which you did not incur those 

costs.’’ Consistent with current 

regulations, this provision prevents the 

lessee from claiming transportation 

costs incurred for a segment of 

transportation when the gas did not 

actually flow on that segment. A lessee 

could only claim transportation costs 

attributable to the actual movement of 

the lease production on that 

transportation segment. 

We also propose new paragraphs 

(a)(1) and (a)(2)(i), which are consistent 

with the current Federal oil rule 

§ 1206.109(a)(2). New paragraph (a)(1) 

states you may take a transportation 

allowance 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 the lease, unit, or communitized area 

where the gas is produced. New 

paragraph (a)(2)(i) states that you may 

take a transportation allowance when 

the movement to the sales point is not 

gathering. Neither change to the current 

rule is substantive because both codify 

existing practice and case law. 

Proposed new paragraph (a)(2)(ii) 

states that ‘‘[f]or gas produced on the 

OCS, the movement of gas from the 

wellhead to the first platform is not 

transportation.’’ It is well established 

that the movement of oil and gas that 

ONRR determines is ‘‘gathering’’ is not 

allowable as a transportation allowance. 

California Co. v. Udall, 296 F.2d 384 

(D.C. Cir. 1961); Kerr-McGee Corp., 147 

IBLA 277 (1999). However, on May 20, 

1999, the then-Associate Director for the 

former MMS’s Royalty Management 


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624 Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 

Program issued ‘‘Guidance for 

Determining Transportation Allowances 

for Production from Leases in Water 

Depths Greater Than 200 Meters’’ (Deep 

Water Policy). The Deep Water Policy 

provides the following guidelines: (1) 

Current regulations must be followed; 

(2) movement costs are allocated 

between royalty and non-royalty bearing 

substances; (3) movement prior to a 

central accumulation point is 

considered gathering, movement beyond 

the point is considered transportation; 

(4) leases and units are treated similarly; 

(5) the movement is to a facility that is 

not located on a lease adjacent to the 

lease on which the production 

originates; and (6) allowances for subsea 

completions not located in water deeper 

than 200 meters are considered on a 

case-by-case basis. 

Both the current Federal oil and gas 

valuation rules 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 the lease, unit, or 

communitized area that BLM or BSEE 

approves for onshore and offshore 

leases, respectively.’’ 30 CFR 1206.101 

(Federal oil) and 1206.151 (Federal gas). 

Under the Deep Water Policy, ONRR 

considered a subsea manifold located on 

the OCS in deep water to be a ‘‘central 

accumulation point’’ regardless of 

whether it was actually a central 

accumulation or treatment point as 

ONRR’s regulations require. Since 

ONRR issued the Deep Water Policy, 

lessees have been deducting the costs of 

moving bulk production from the subsea 

manifold to the platform where the oil 

and gas first surface. In addition, lessees 

have attempted to expand the Deep 

Water Policy to deem subsea wellheads 

‘‘central accumulation points’’ and take 

transportation allowances from the sea 

bed floor to the first platform where the 

bulk production surfaces. Thus, lessees 

have taken transportation allowances 

under the Deep Water Policy, in some 

instances, for movement ONRR 

considers non-deductible ‘‘gathering’’ 

under its regulations. 

In addition, the Interior Board of Land 

Appeals (IBLA) has concluded there are 

three definitive attributes of gas 

gathering lines: (1) They move lease 

production to a central accumulation 

point; (2) they connect to gas wells; and 

(3) they bring gas by separate and 

individual lines to a central point where 

it is delivered into a single line. KerrMcGee Corp., 147 IBLA at 282 (citations 

omitted). In Kerr-McGee, the IBLA 

stated that ‘‘even though production is 

moved across lease boundaries, because 

it is treated and sold on adjacent leases 

the costs of moving it there are properly 

regarded as gathering, not 

transportation.’’ Id. at 283 (citations 

omitted). Under Kerr-McGee, almost all 

of the movement the Deep Water Policy 

allows as a transportation allowance is, 

in actuality, non-deductible ‘‘gathering’’ 

under ONRR’s current valuation 

regulations. 

We have determined that the Deep 

Water Policy is inconsistent with our 

regulatory definition of gathering and 

Departmental decisions interpreting that 

term. Therefore, we propose to rescind 

the Deep Water Policy in this 

rulemaking. We propose to accomplish 

this by making two changes. First, 

consistent with Kerr-McGee, we propose 

to add to the definition of ‘‘gathering’’ 

that any movement of bulk production 

from the wellhead to a platform offshore 

is gathering, not allowable 

transportation. Second, we propose to 

add a new paragraph (a)(2)(ii) to this 

section that states ‘‘[f]or gas produced 

on the OCS, the movement of gas from 

the wellhead to the first platform is not 

transportation.’’ We also make this 

change to proposed Federal oil 

§ 1206.110(a)(2)(ii). 

Proposed paragraph (b) of this section 

contains and consolidates current 

requirements in 30 CFR 1206.156(b) and 

1206.157(a)(2) and (b)(3) regarding 

allocation of transportations costs based 

on your or your affiliate’s cost of 

transporting each product if you 

transport one or more products in the 

gaseous phase in a transportation 

system. 

Proposed paragraph (c)(1) contains 

and consolidates current requirements 

in 30 CFR 1206.157(a)(2) and (b)(4) 

which all apply to allocation of 

transportations costs when you or your 

affiliate transport both gaseous and 

liquid products in the same 

transportation system. 

Under proposed paragraph (d), if you 

value unprocessed gas under 

§ 1206.141(c) or residue gas and gas 

plant products under § 1206.142(d)—the 

index-based valuation options—you 

may not take a transportation allowance. 

This is because the index-based 

valuation provisions already incorporate 

the costs of transportation. 

Proposed paragraph (e)(1), eliminates 

the current provision allowing lessees to 

request transportation allowances in 

excess of 50 percent of the sales value 

of the unprocessed gas, residue gas, or 

NGLs. Currently, ONRR limits 

transportation allowances and factors to 

50 percent of the sales value of 

unprocessed gas, residue gas, or gas 

plant products unless we approve an 

exception to the limitation. To ensure a 

fair return to the public and to limit 

ONRR’s administrative costs to process 

such requests, the proposed regulation 

eliminates the exception to the 50- 

percent limit. ONRR believes the 

current 50-percent limit on 

transportation-related costs is adequate 

in the vast majority of transportation 

situations. Thus, paragraph (e)(2) 

provides that any existing approvals for 

the exception to the limitation terminate 

on the effective date of the final rule. 

We will not grandfather any existing 

approval to exceed the 50-percent limit. 

Proposed paragraph (f) continues the 

current requirement under 30 CFR 

1206.157(a)(4), applicable to arm’slength transportation, that lessees must 

express transportation allowances for 

residue gas, gas plant products, or 

unprocessed gas in a dollar-value 

equivalent. We propose to also apply 

this requirement to non-arm’s-length 

transportation consistent with existing 

practice. We further propose that if your 

or your affiliate’s payments for 

transportation under a contract are not 

in dollars-per-unit, you must convert 

the consideration you or your affiliate 

paid to its dollar-value equivalent. 

Like the default provision for 

valuation we discuss above under 

§ 1206.143(c), proposed paragraphs 

(g)(1), (2), and (3) provide that ONRR 

may determine your transportation 

allowance under § 1206.144, if: (1) 

There is misconduct by or between the 

contracting parties; (2) the total 

consideration the lessee or its affiliate 

pays under an arm’s-length contract 

does not reflect the reasonable cost of 

transportation because the lessee 

breached its duty to market the 

unprocessed gas, residue gas, or gas 

plant products for the mutual benefit of 

the lessee and the lessor by transporting 

such products at a cost that is 

unreasonably high; or (3) ONRR cannot 

determine if the lessee properly 

calculated a transportation allowance 

under § 1206.153 or § 1206.154, for any 

reason. Under proposed paragraph 

(g)(2), ONRR may consider an allowance 

to be unreasonably high if it is 10- 

percent higher than the highest 

reasonable measures of transportation 

costs, including, but not limited to, 

transportation allowances lessees and 

others report to ONRR and tariffs for 

gas, residue gas, or gas plant products 

transported through the same system. 

Finally, we propose a new provision 

under paragraph (h) to make clear that 

you do not need ONRR’s approval 

before reporting a transportation 

allowance for costs that you incur. This 

provision is in the current regulations 

that apply to arm’s-length transportation 

at 30 CFR 1206.157(a), but we propose 

to apply it to non-arm’s-length 


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transportation as well. This is consistent 

with existing practice. 

1206.153 How do I determine a 

transportation allowance if I have an 

arm’s-length transportation contract? 

Proposed § 1206.153 explains how 

lessees must determine a transportation 

allowance under arm’s-length 

transportation contracts. As we discuss 

above, we propose to restructure this 

section for consistency with the Federal 

oil transportation allowance regulations. 

In addition, we move the requirements 

for non-arm’s-length transportation 

allowances to a separate § 1206.154. 

Proposed paragraph (a)(1) states that 

this section applies to both the lessee 

and its affiliate if the lessee chooses to 

use the affiliate’s arm’s-length sales 

contract for valuation and if that affiliate 

incurs transportation costs under an 

arm’s-length transportation contract to 

move the lease production to the sales 

point. However, ONRR will determine 

your transportation allowance under 

§ 1206.152(g) if ONRR determines there 

is misconduct, the arm’s-length 

transportation cost is unreasonably 

high, or ONRR cannot determine if your 

transportation allowance is proper. This 

provision gives ONRR greater discretion 

and flexibility to determine 

transportation allowances (for example, 

when arm’s-length transportation 

service providers charge bundled fees). 

See the discussion of bundled fees in 

proposed § 1206.141 above. 

ONRR proposes to eliminate the 

provision in current 30 CFR 

1206.157(a)(5) that allows lessees to 

report transportation costs, in certain 

circumstances, as a transportation 

factor. Rather, we propose that a lessee 

must report separately all transportation 

costs under both arm’s-length and nonarm’s-length sales contracts as a 

transportation allowance on Form 

ONRR–2014. ONRR believes that 

requiring lessees to report all 

deductions for transportation costs 

separately as allowances on Form 

ONRR–2014 is more transparent, 

supports ONRR’s increased data mining 

efforts to promote accuracy, and assists 

State and Federal auditors with their 

compliance work. We propose this same 

change for oil produced from Federal 

lands. 

Proposed paragraph (b) allows a 

lessee to include the same costs we 

allow under current 30 CFR 1206.157(f) 

in its transportation allowance. Under 

new paragraph (b)(11), we also propose 

that a lessee may include in its 

transportation allowance hurricane 

surcharges the lessee or its affiliate pay. 

This proposal is consistent with existing 

practice. 

Under proposed paragraph (c), we 

specify transportation costs we would 

not allow a lessee to include in its 

transportation allowance. These nonallowable costs remain mostly the same 

as those we currently disallow under 30 

CFR 1206.157(g). We believe it is 

already clear the cost of boosting gas 

(e.g. recompressing residue gas at the 

plant after processing) is not a 

deductible cost of transportation under 

current 30 CFR 1202.151(b) and the 

Assistant Secretary’s decision at issue in 

Devon. Nevertheless, proposed 

paragraph (c)(8) specifically states that 

the costs of boosting residue gas are not 

allowable as a cost of transportation. 

Finally, we propose a new paragraph 

(d) that applies if you have no written 

contract for the arm’s-length 

transportation of gas. In that case, ONRR 

determines your transportation 

allowance under proposed § 1206.144. 

Under this proposal, you have to 

propose to ONRR a method to determine 

the allowance using the procedures in 

§ 1206.148(a) and could use that method 

until ONRR issues its determination. 

This paragraph only applies when there 

is no contract for arm’s-length 

transportation. Thus, it would not apply 

if lessees perform their own 

transportation. Rather, § 1206.154 

regarding non-arm’s-length 

transportation allowances applies. 

1206.154 How do I determine a 

transportation allowance if I have a 

non-arm’s-length transportation 

contract? 

We propose § 1206.154 as a separate 

section explaining how to calculate 

transportation allowances under a nonarm’s-length contract, such as where the 

lessee ships its production through its 

own pipeline or through a pipeline its 

affiliate owns. Under proposed 

paragraph (a), ONRR continues the 

provision in current 30 CFR 1206.157(b) 

that does not recognize contracts 

between the lessee and its affiliate or 

any other person without opposing 

economic interests regarding that 

contract. Like the current regulations, 

you will determine non-arm’s-length 

transportation allowances based on your 

actual costs or the actual costs of the 

affiliated pipeline owner. 

Proposed paragraph (b) generally 

explains costs you may include in your 

transportation allowance. Paragraph 

(b)(1) explains the lessee’s or its 

affiliate’s actual costs include capital 

costs and operating and maintenance 

expenses under paragraphs (e), (f), and 

(g) of this section. Proposed paragraph 

(b)(2) explains you also could include 

overhead under paragraph (h) of this 

section. Under proposed paragraph 

(b)(3), we revise the current regulation 

to clarify the methodology for the two 

options to calculate depreciation. Under 

this proposed rulemaking, we allow 

lessees to choose between depreciation 

and a return on undepreciated capital 

investment under paragraph (i)(1) of this 

section, or a cost equal to a return on the 

initial depreciable capital investment in 

the transportation system under 

paragraph (i)(2) of this section. Finally, 

paragraph (b)(4) allows the lessee to 

continue to claim a rate of return on the 

reasonable salvage value of the 

transportation system after it is fully 

depreciated. For example, if the 

pipeline had a salvage value of 5 

percent, the lessee may claim a rate of 

return on 5 percent of the system value, 

even though we would allow no further 

depreciation. See the discussion of 

reasonable salvage value in proposed 

§ 1206.112(i)(1)(iii). 

We also propose to remove the 

provisions of current § 1206.175(b)(5) 

that allow a lessee with a non-arm’slength contract to use FERC or Stateregulatory-agency approved tariffs as an 

exception from the requirement to 

calculate actual costs. We remove this 

provision to make it consistent with the 

current Federal oil valuation 

regulations. Under the proposed rule, 

lessees must compute their actual costs 

to determine transportation allowances 

under non-arm’s-length contracts even 

when a regulatory agency has approved 

a tariff. 

Proposed paragraph (c) further 

explains the transportation costs you 

may and may not include in a 

transportation allowance. Proposed 

paragraph (c)(1) states that, to the extent 

that you have not already included in 

your transportation allowances the 

allowable costs under paragraphs (e) 

through (g) of this section, you may 

include in your allowance the actual 

transportation costs we list under 

§ 1206.153(b)(2), (5), and (6) of this 

subpart (Gas supply realignment (GSR) 

costs, Gas Research Institute (GRI) fees, 

and Annual Charge Adjustment (ACA) 

fees that FERC imposes). ONRR 

proposes to disallow the remaining 

costs we allow a lessee to include in 

arm’s-length transportation allowances 

under § 1206.153(b) because the lessee 

would not or should not ordinarily 

incur the costs as a pipeline owner or 

be charged for those costs by its affiliate. 

However, there may be instances when 

specific costs integral to transportation 

could be included in the pipeline 

owner’s operating and maintenance 

costs. ONRR invites comments on what 

types of costs, other than those 

identified in § 1206.153(b)(2), (5), and 

(6), may be actual costs of transportation 


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626 Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 

under non-arm’s-length transportation 

arrangements. 

ONRR also proposes to eliminate the 

current provision allowing lessees to 

deduct the costs of pipeline losses, both 

actual and theoretical, under non-arm’slength transportation situations. These 

regulations prohibited actual or 

theoretical pipeline losses prior to the 

1997 gas transportation allowance 

revisions that incorporated new costs 

resulting from FERC Order No. 636. The 

advent of Order No. 636 should not 

have had any bearing on such nonarm’s-length costs. Therefore, ONRR 

proposes to remove this provision. 

ONRR recognizes that pipeline losses 

are distinct from transportation fuel that 

is used on a pipeline to power 

compressors used for actual 

transportation. Under the proposal, 

ONRR continues to permit lessees to 

claim an allowance for actual fuel used 

for qualifying transportation purposes. 

In addition, we continue to disallow 

fuel for non-approved off-lease 

compressors and off-lease fuel for other 

processes necessary to place lease 

production in marketable condition. 

Proposed paragraph (c)(2) explains 

that we do not allow a lessee to include 

in its non-arm’s-length transportation 

allowances the same costs we do not 

allow to be included in arm’s-length 

transportation allowances under 

proposed § 1206.153(c). 

Like the arm’s-length provision, 

proposed paragraph (d) states that for 

non-arm’s-length transportation 

allowances, the lessee may not 

duplicate allowable transportation costs 

when it calculates an allowance. For 

example, if the lessee includes GRI costs 

in its operating costs under paragraph 

(b), it may not also include those costs 

under paragraph (c). 

Proposed paragraphs (e) through (h) 

contain the same requirements as 

current 30 CFR 1206.157(b)(2)(i), (ii), 

and (iii), but we rewrite the provisions 

in Plain Language and make them 

consistent with the current Federal oil 

regulations. 

Proposed paragraph (i) retains the 

requirements of current 30 CFR 

1206.157(b)(2)(iv) regarding 

depreciation, but we rewrite those 

provisions in Plain Language and make 

them consistent with the Federal oil 

regulations. ONRR proposes to 

eliminate the reference to transportation 

facilities first placed in service after 

March 1, 1988. When ONRR published 

its Federal gas valuation regulations on 

January 15, 1988, it changed the 

requirements necessary to receive 

transportation and processing 

allowances. In recognition that certain 

transportation and processing facilities 

had been given approval prior to those 

regulations’ effective date (March 15, 

1988), ONRR made the new 

requirements apply only to facilities 

that were placed in service on or after 

the effective date of those regulations. 

Now more than twenty years later, 

ONRR believes that none of the facilities 

placed in service before March 15, 1988, 

are still eligible for depreciation under 

the requirements in effect prior to 

March 15, 1988. Therefore, we propose 

to remove this outdated language from 

the proposed regulations. 

Under paragraph (i)(3), ONRR 

proposes to revise the rate of return 

from 1.3 times the Standard & Poor’s 

BBB bond rate in current 30 CFR 

1206.157(b)(2)(v) to the rate without a 

multiplier, in other words 1 times the 

BBB bond rate. We make the same 

change to Federal oil, so please refer to 

our discussion of proposed 

§ 1206.112(i)(3). 

1206.155 What are my reporting 

requirements under an arm’s-length 

transportation contract? 

This section would contain 

essentially the same provisions as 

current 30 CFR 1206.157(c)(1). 

However, ONRR proposes to add the 

term ‘‘affiliate’’ to paragraph (b). Under 

the new proposed valuation provisions, 

which use an affiliate’s arm’s-length 

sales contract, ONRR allows a 

transportation allowance to the arm’slength sales point and, therefore, needs 

the associated transportation contracts. 

In addition, ONRR proposes to 

eliminate the reference to allowances in 

effect prior to March 1, 1988, under 

current 30 CFR 1206.157(c)(1)(iii). As 

stated above, ONRR believes that none 

of facilities predating the 1988 rule 

change are still eligible for depreciation 

under the requirements in effect prior to 

March 15, 1988. Therefore, we are 

removing this language from the 

proposed regulations. 

1206.156 What are my reporting 

requirements under a non-arm’s-length 

transportation contract? 

This section contains essentially the 

same provisions as current 30 CFR 

1206.157(c)(2). In this proposed rule, 

ONRR eliminates the reference in 

current 30 CFR 1206.157(c)(2)(v) to 

allowances in effect prior to March 1, 

1988. 

1206.157 What interest or penalties 

apply if I improperly report a 

transportation allowance? 

Under proposed § 1206.157, ONRR 

consolidates the penalty and interest 

provisions for improper allowances. 

Currently, such provisions are 

contained under both the general 

transportation and determination of 

transportation allowances sections of 

the regulations. Proposed paragraph 

(a)(1) slightly modifies current 30 CFR 

1206.156(d) by using the term 

‘‘unauthorized’’ in the context of ‘‘If 

ONRR determines that you took an 

unauthorized transportation allowance, 

then you must pay any additional 

royalties due. . . .’’ However, this 

change would not alter the meaning of 

the current provisions. Examples of 

unauthorized transportation allowances 

include, but are not limited to, 

exceeding the 50-percent limitation, 

including costs necessary to place the 

gas into marketable condition, or 

including other costs that are not 

integral to the transportation of lease 

production. Proposed paragraph (a)(2) 

states that a lessee may be entitled to a 

credit with interest if it understated its 

transportation allowance. This 

provision amends current 30 CFR 

1206.157(e) to comply with RSFA’s 

provision that entitles lessees to interest 

on overpayments (30 U.S.C. 1721(h)). 

Proposed paragraph (b) states that, if 

the lessee deducts a transportation 

allowance that exceeds 50 percent of the 

value of the gas, residue gas, or gas plant 

products transported, the lessee must 

pay late payment interest on the excess 

allowance amount taken from the date 

that amount is taken until the date it 

paid the additional royalties due. This 

changes the current requirement that 

interest is calculated from the date the 

allowance is taken until the lessee files 

a request for an exception. This change 

results from ONRR proposing to 

eliminate allowance exceptions. 

Proposed paragraph (c) restates 

current 30 CFR 1206.156(d). 

1206.158 What reporting adjustments 

must I make for transportation 

allowances? 

Section 1206.158 restates the 

requirements of current 30 CFR 

1206.157(e), except we rewrite the 

provisions in Plain Language. 

1206.159 What general processing 

allowances requirements apply to me? 

Like the amendments to 

transportation allowances discussed 

above, ONRR proposes to rewrite the 

current processing allowance 

regulations at 30 CFR 1206.158 in Plain 

Language, make them consistent with 

Federal oil, and reorganize them for 

clarity and visibility. We are not 

planning to make any substantive 

changes in proposed paragraph (a)(1) 

and paragraph (b); they will contain the 

same provisions as current 30 CFR 

1206.158 (a) and (b). However, we 


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propose to add a new provision under 

paragraph (a)(2) to make clear that you 

do not need ONRR’s approval before 

reporting a processing allowance for 

costs that you incur for arm’s-length or 

non-arm’s-length allowances. This is 

consistent with existing practice. 

Proposed paragraph (c) continues the 

requirements of current 30 CFR 

1206.158(c), with two substantive 

changes and one clarification to current 

30 CFR 1206.158(c)(1). Current 

paragraph 1206.158 (c)(1) states that 

‘‘Except as provided in paragraph (d)(2) 

of this section, the processing allowance 

shall not be applied against the value of 

the residue gas. Where there is no 

residue gas ONRR may designate an 

appropriate gas plant product against 

which no allowance may be applied.’’ 

We are removing the second sentence 

because we do not believe ONRR ever 

used this provision. 

ONRR proposes to eliminate the 

exception under current 30 CFR 

1206.158 (c)(3) allowing a lessee to 

request ONRR approval of a processing 

allowance that exceeds 662⁄3 percent of 

the value of the plant products. We also 

propose to eliminate the provision 

allowing a lessee to request an 

extraordinary processing cost allowance 

under current 30 CFR 1206.158(d)(2). 

ONRR also proposes to terminate any 

approvals for the exception under 

proposed paragraph (c)(3) and the 

extraordinary cost processing allowance 

under proposed paragraph (c)(4) as of 

the effective date of the rule. Thus, we 

propose not to grandfather previously 

approved exceptions or extraordinary 

allowances. ONRR proposes these 

changes because, as with transportation 

allowances, ONRR believes the current 

662⁄3 percent limit on processing-related 

costs is adequate in the vast majority of 

situations. To date, we only have 

approved two extraordinary processing 

cost allowances. Given the age of the 

plants and improvements in technology, 

ONRR believes such extraordinary cost 

allowances no longer reflect current 

conditions. Furthermore, ONRR believes 

the current 662⁄3 percent limitation on 

gas plant products ensures a fair return 

to the public. 

Proposed paragraph (d) explains and 

clarifies that we continue to disallow 

deductions for costs necessary to place 

gas into marketable condition. ONRR 

proposes to retain the existing 

requirements of current 30 CFR 

1206.158(d)(1) but proposes to recodify 

them as § 1206.159(d)(1), (2), (3), and 

(4). Also, the proposed rule makes clear 

that any cost a lessee incurs for 

stabilizing condensate or recovering gas 

vapors from condensate or oil is 

disallowed. The methods industry 

employs to perform these services are 

not within the proper definition of 

‘‘processing’’ under these regulations 

and are, in fact, costs incurred to place 

the condensate or oil into marketable 

condition. Likewise, we currently 

analyze whether hydrocarbon dew point 

controls are actually functions that fall 

within the definition of ‘‘processing’’ 

under the regulations before qualifying 

for a processing allowance against the 

value of the liquids recovered. In 

conjunction with these efforts to clarify 

the costs that qualify as a processing 

allowance, ONRR proposes to add JouleThomson Units (JT Units) used to 

recover NGLs from gas to the definition 

of ‘‘processing’’ under proposed 

§ 1206.20, regardless of the location of 

the JT Unit. 

1206.160 How do I determine a 

processing allowance, if I have an 

arm’s-length processing contract? 

ONRR proposes this new section, 

which is essentially the same as current 

30 CFR 1206.159(a), with no material 

modifications, except we add a new 

paragraph (c) we discuss below. Like 

transportation allowances, we are 

moving the requirements for non-arm’slength processing allowances to a 

separate § 1206.161. Because the 

requirements for determining processing 

allowances under an arm’s-length 

contract are essentially the same as 

those for determining transportation 

allowances under an arm’s-length 

contract, we make the same changes to 

processing allowances in this section as 

those we propose for arm’s-length 

transportation allowances. Refer to the 

preamble discussion of § 1206.153 for 

an explanation of the changes. 

We propose a new paragraph (c) that 

applies if you have no written contract 

for arm’s-length processing of gas. In 

that case, ONRR will determine your 

processing allowance under § 1206.144. 

You will have to propose to ONRR a 

method to determine the allowance 

using the procedures in § 1206.148(a) 

and may use that method until ONRR 

issues a determination. This proposed 

paragraph only applies if there is no 

contract for arm’s-length processing. It 

does not apply if a lessee performs its 

own processing. In that case, § 1206.161 

applies. 

ONRR also proposes new § 1206.161 

through § 1206.165 to subpart D to 

codify and enhance current Federal gas 

valuation practices. 

1206.161 How do I determine a 

processing allowance if I have a nonarm’s-length processing contract? 

This section contains the same 

requirements as current 30 CFR 

1206.159(b). Because the requirements 

for determining processing allowances 

under a non-arm’s-length contract are 

essentially the same as those for 

determining transportation allowances 

under a non-arm’s-length contract, we 

make the same changes to processing 

allowances in this section as those we 

propose for non-arm’s-length 

transportation allowances. Refer to the 

preamble discussion of § 1206.154 for 

an explanation of the changes. 

ONRR proposes one material change 

to the current regulatory requirements. 

Under proposed paragraph (b)(4), we 

allow the lessee to continue claiming a 

rate of return on the reasonable salvage 

value of a processing plant after it is 

fully depreciated. For example, if the 

plant had a salvage value of 5 percent, 

the lessee could claim a rate of return 

on 5 percent of the plant value, even 

though we would allow no further 

depreciation. See the discussion of 

reasonable salvage value in proposed 

§ 1206.112(i)(1)(iii). 

1206.162 What are my reporting 

requirements under an arm’s-length 

processing contract? 

1206.163 What are my reporting 

requirements under a non-arm’s-length 

processing contract? 

1206.164 What interest or penalties 

apply if I improperly report a processing 

allowance? 

1206.165 What reporting adjustments 

must I make for processing allowances? 

These four proposed sections are the 

same as the reporting-related 

requirements in current 30 CFR 

1206.159(c), (d), and (e). Also, they are 

the same changes as those discussed 

above for transportation allowances 

under §§ 1206.155 through 1206.158. 

Subpart F—Federal Coal 

1206.250 What is the purpose and 

scope of this subpart? 

This proposed section is the same as 

current 30 CFR 1206.250, but we rewrite 

the current section in Plain Language 

and make it consistent with the other 

product valuation regulations. The 

substantive requirements remain 

unchanged. 

1206.251 How do I determine royalty 

quantity and quality? 

This proposed section is the same as 

current 30 CFR 1206.254, 1206.255, and 

1206.260, but we rewrite the sections in 

Plain Language and combine multiple 

sections into this proposed section. We 

do not propose any substantive change. 

However, under proposed paragraph (e), 

we clarify the calculation you will have 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
628 Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 

to perform to allocate washed coal 

under current 30 CFR 1206.260 by 

attributing the washed coal to the leases 

from which it was extracted. Thus, 

proposed new paragraph (e) reads as set 

forth in the regulatory text. 

1206.252 How do I calculate royalty 

value for coal I or my affiliate sell(s) 

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

Current 30 CFR 1206.256 contains 

valuation standards for Federal coal 

leases having cents-per-ton royalty rates. 

The regulation we propose eliminates 

any reference to the valuation of coal 

from these leases because there are no 

longer any Federal cents-per-ton coal 

leases. Therefore, this proposed 

§ 1206.252, and the rest of the proposed 

regulations, provide lessees with 

instructions for valuing coal from ad 

valorem Federal coal leases. 

Consistent with the current Federal 

coal valuation regulations, under the 

proposed regulations, a lessee generally 

values Federal coal based on the gross 

proceeds accruing to the lessee from the 

first arm’s-length sale. However, like the 

proposed amendments to the Federal 

gas rule we discuss above, we propose 

to eliminate the benchmarks for 

valuation of non-arm’s-length sales. We 

also propose to add the same ‘‘default’’ 

mechanism under § 1206.254 discussed 

above. Please refer to proposed 

§§ 1206.141, 1206.142, and 1206.144 

above for an explanation of the 

proposed changes. 

The benchmarks applicable to value 

coal in non-arm’s-length or no-sale 

situations have proven difficult to use in 

practice. In addition, the first 

benchmark does not allow the use of 

comparable arm’s-length sales by the 

lessee or its affiliates, exacerbating the 

challenging process of obtaining and 

comparing relevant arm’s-length sales 

contracts to value non-arm’s-length 

sales. Furthermore, disputes arise over 

which sales are comparable, particularly 

because of the inherent ambiguity in 

applying the comparability factors. 

ONRR is soliciting comments on how 

to simplify and improve the valuation of 

coal disposed of in non-arm’s-length 

transactions and no-sale situations. We 

seek input on the merits of eliminating 

the benchmarks for valuation of nonarm’s-length sales and comments on the 

following questions: 

• Should the royalty value of coal 

initially sold under non-arm’s-length 

conditions be based on the gross 

proceeds received from the first arm’slength sale of that coal in situations 

where there is a subsequent arm’slength sale? 

• If you are a coal lessee, will 

adoption of this methodology 

substantively impact your current 

calculation and payment of royalties on 

coal and how? 

• What other methodologies might 

ONRR use to determine the royalty 

value of coal not sold at arm’s length 

that we may not have considered? 

Under proposed paragraph (a), if the 

lessee sells coal to an affiliate or another 

person under a non-arm’s-length sales 

contract, and the coal purchaser sells 

the coal under an arm’s-length contract, 

the lessee must value the coal based on 

the first arm’s-length contract, less 

applicable allowances, unless ONRR 

decides to value the coal under 

§ 1206.254 (the new ‘‘default’’ 

provision). Please refer to proposed 

§ 1206.141(b) above for an explanation 

of the proposed change. 

A lessee that is part of a corporation 

with affiliates that produce coal and 

affiliates that consume the coal in an 

electrical generation plant may have 

transactions to transfer coal without a 

sale. If the affiliate consumes the coal to 

generate electricity, paragraph (a) of this 

proposed section would not provide a 

valuation methodology. Therefore, 

ONRR proposes paragraph (b) to explain 

how a lessee must value the coal in this 

circumstance. 

Under proposed paragraph (b)(1), if a 

lessee or its affiliate sells electricity at 

arm’s length, the royalty value is the 

sales value of the electricity, less 

applicable allowances. In proposed 

paragraph (b)(2), if a lessee or its 

affiliate did not sell electricity at arm’s 

length, ONRR will determine the royalty 

value of the coal under the new 

‘‘default’’ valuation provision in 

§ 1206.254. In this situation, a lessee 

must propose a valuation method to 

ONRR and may use that method until 

we issue a determination on the lessee’s 

proposal. 

We also propose a new paragraph (c) 

to explain how to value coal that a coal 

cooperative sells. Please refer to 

§ 1206.20 for the definition of a coal 

cooperative. A coal cooperative 

generally operates as a corporation, with 

members and owners associated for the 

purpose of obtaining a long-term, secure 

source of coal. This proposed rule will 

treat a coal cooperative and its 

members/owners as affiliated because 

they operate without opposing 

economic interests. Their collective 

need is to have a source of coal available 

to generate electric power and to be able 

to purchase that coal at reasonable 

prices, and, if possible, below-market 

prices. The coal cooperative’s members 

are commonly electric power generation 

companies, or electric utility, 

generation, or transmission 

cooperatives. The coal cooperative may 

operate as a coal lessee, operator, or 

payor of these and may or may not be 

organized to make a profit. Coal 

cooperatives exist to avoid the vagaries 

and potentially higher prices of the free 

market. 

One mechanism that some members 

of coal cooperatives use to maintain the 

lowest possible price for the coal mined 

and sold to other members is to refrain 

from making a profit on such 

transactions among members. A coal 

cooperative can underprice coal even 

when sales are arm’s length, all other 

costs being equal. Thus, the proposed 

regulations include a new paragraph (c) 

to value coal sold in these 

circumstances. 

Under proposed paragraph (c)(1), for 

sales of coal between the coal 

cooperative and coal cooperative 

members, if the coal is then sold at 

arm’s-length, we require the lessee to 

value the coal under paragraph (a) of 

this section, regardless of the number of 

sales between the coal cooperative 

members or the coal cooperative and its 

members. For example, assume a coal 

cooperative sold its Federal coal to a 

coal cooperative member, and that coal 

cooperative member sold its coal to 

another coal cooperative member who 

then sold the coal at arm’s-length. In 

that case, under the proposed rule, the 

coal would be valued under paragraph 

(a) of this section based on the first 

arm’s-length sale. 

Under proposed paragraph (c)(2), for 

sales of coal between the coal 

cooperative and coal cooperative 

members where the coal is consumed in 

a power generation plant to generate 

electricity owned by the coal 

cooperative or a coal cooperative 

member, we require a lessee to value the 

coal under proposed paragraph (b) of 

this section, regardless of the number of 

sales between coal cooperative members 

or between the coal cooperative and its 

members. For example, assume a coal 

cooperative sold its Federal coal to a 

coal cooperative member, and that coal 

cooperative member sold its coal to 

another coal cooperative member who 

then consumed the coal in its power 

generation plant and sold the electricity 

it generated. In that case, under the 

proposed rule, the coal would be valued 

under paragraph (b) of this section 

based on the sales of the electricity, less 

any allowable deductions. 

ONRR believes all sales between 

cooperative members are non-arm’slength because they do not have 

opposing economic interests. However, 

we treat sales to non-members of the 

cooperative like any other arm’s-length 


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Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 629 

sale under paragraph (a) or paragraph 

(b) of this section. ONRR seeks 

comments on this valuation proposal. 

Proposed paragraph (d) states that if 

you are entitled to take a washing 

allowance and transportation allowance 

for royalty purposes under this section, 

the sum of the washing and 

transportation allowances may never 

reduce the royalty value of the coal to 

zero. This is the same as current 30 CFR 

1206.258(a) and 1206.261(b), but we 

rewrite these sections in Plain 

Language. Unlike the Federal oil and gas 

rules, ONRR is not proposing to limit 

Federal and Indian coal washing and 

transportation allowances to 50 percent 

of the value of the coal. We specifically 

request comments as to whether we 

should limit coal allowances to 50 

percent of the value of the coal. 

1206.253 How will ONRR determine if 

my royalty payments are correct? 

1206.254 How will ONRR determine 

the value of my coal for royalty 

purposes? 

1206.255 What records must I keep to 

support my calculations of royalty 

under this subpart? 

1206.256 What are my responsibilities 

to place production into marketable 

condition and to market production? 

1206.257 When is an ONRR audit, 

review, reconciliation, monitoring, or 

other like process considered final? 

1206.258 How do I request a valuation 

determination or guidance? 

1206.259 Does ONRR protect 

information I provide? 

ONRR proposes the same changes to 

§§ 1206.253 through 1206.259 as those 

we propose for Federal gas valuation 

regulations under §§ 1206.143 through 

1206.149. Please refer to those proposed 

sections for an explanation of changes. 

1206.260 What general transportation 

allowance requirements apply to me? 

Proposed § 1206.260 retains the 

provisions in current 30 CFR 1206.261 

and makes the Federal coal regulations 

consistent with the Federal oil and gas 

regulations in this proposed rule. This 

section also consolidates provisions 

applicable to both arm’s-length and nonarm’s-length transportation in the 

current regulations, rather than 

repeating those provisions in the 

respective sections for those allowances. 

We also rewrite the current regulations 

in Plain Language and discuss only 

substantive changes or additions to this 

section below. 

Proposed paragraph (a)(1) contains 

the same provision as current 30 CFR 

1206.261(a) allowing you to take a 

deduction for the reasonable, actual 

costs to transport coal from the lease to 

a point off the lease or mine determined 

under §§ 1206.261 or 1206.262, as 

applicable. We propose a new provision 

under paragraph (a)(2) to make clear 

that you do not need our approval 

before reporting a transportation 

allowance for costs that you incur for 

arm’s-length and non-arm’s-length 

transportation. This proposal is 

consistent with existing practice. 

Proposed paragraph (b) would contain 

the remaining current requirements in 

30 CFR 1206.261(a) regarding when you 

may take an allowance. 

Proposed paragraph (c) explains when 

you cannot take an allowance. A new 

provision in paragraph (c)(1) states that 

you cannot take an allowance for 

transporting lease production that is not 

royalty bearing. This new provision is 

consistent with the existing and 

proposed Federal oil and gas 

regulations. Proposed paragraph (c)(2) 

contains the current requirement in 30 

CFR 1206.261(a)(2) that you cannot take 

an allowance for in-mine movement of 

your coal. We also propose a new 

provision in paragraph (c)(3) that would 

state you may not deduct transportation 

costs to move a particular tonnage of 

production for which you did not incur 

those costs. This codifies our existing 

practice of only granting a 

transportation allowance if you actually 

move coal and pay for that movement. 

Proposed paragraph (d) is the same as 

current 30 CFR 1206.261(c)(3) and 

permits you to claim a transportation 

allowance only when you sell the coal 

and pay royalties. 

We propose to add paragraph (e) to 

contain and consolidate current 

requirements in 30 CFR 1206.261(c)(1), 

1206.261(c)(2), and 1206.261(e) about 

allocation of transportations costs. This 

paragraph requires lessees to report 

their transportation costs on Form 

ONRR–4430 as a cost per ton of clean 

coal transported. We also explain how 

to calculate the cost per ton of clean 

coal transported. 

In addition, we propose to add 

paragraph (f) to contain the requirement 

in current § 1206.262(a)(4) that you 

must express arm’s-length coal 

transportation allowances as a dollarvalue equivalent per ton of coal 

transported. We also make the provision 

applicable to non-arm’s-length 

transportation allowances, consistent 

with existing practice. Under the 

proposed regulations, we further 

explain that if you do not base your or 

your affiliate’s payments for 

transportation under a transportation 

contract on a dollar-per-unit basis, you 

must convert the consideration you or 

your affiliate paid to a dollar-value 

equivalent. 

We propose to add paragraph (g), 

containing the same default provision as 

that for the Federal oil and gas 

transportation regulations discussed 

above under §§ 1206.110(f) and 

1206.152(g), respectively. This proposal 

includes moving the requirements of 

current paragraphs 1206.262(a)(2) and 

1206.262(a)(3) regarding additional 

consideration, misconduct, and breach 

of the duty to market to this new 

paragraph (g). We also propose to move 

the requirements for non-arm’s-length 

transportation allowances to a separate 

§ 1206.262. 

1206.261 How do I determine a 

transportation allowance if I have an 

arm’s-length transportation contract or 

no written arm’s-length contract? 

Proposed section 1206.261 explains 

how lessees must determine 

transportation allowances under arm’slength transportation contracts. These 

requirements are in current 30 CFR 

1206.262(a)(1). However, we rewrite this 

section in Plain Language and 

restructure it for consistency with the 

Federal gas transportation allowance 

regulations we discuss above in 

§ 1206.153. 

We propose to add a new paragraph 

(c) that would apply if you have no 

written contract for the arm’s-length 

transportation of coal. In that case, 

ONRR will determine your 

transportation allowance under 

§ 1206.254. You must propose to ONRR 

a method to determine the allowance 

using the procedures in § 1206.258(a). 

You may use that method to determine 

your allowance until ONRR issues a 

determination. This paragraph does not 

apply if a lessee performs its own 

transportation. Rather, proposed 

§ 1206.262, regarding non-arm’s-length 

transportation allowances, applies. 

1206.262 How do I determine a 

transportation allowance if I have a 

non-arm’s-length transportation 

contract? 

ONRR proposes to revise § 1206.262 

to explain how lessees must determine 

transportation allowances under nonarm’s-length transportation contracts 

using paragraphs (a) through (k) of this 

section. These requirements are in 

current 30 CFR 1206.262(b). We rewrite 

the current requirements in Plain 

Language and restructure and amend 

this section for consistency with the 

Federal gas transportation allowance 

regulations we discuss above in 

§ 1206.154. We also make several 

substantive changes discussed below. 


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The current coal rule at 30 CFR 

1206.262(b)(3) provides that a lessee 

may request an exception from having 

to calculate actual costs for non-arm’slength or no-contract transportation 

allowances. The lessee may use the 

exception if there are Federal- or Stateapproved transportation rates. We 

propose to eliminate the exception for 

the following reasons: (1) No lessee has 

ever applied to use the exception; (2) 

the Federal Government no longer sets 

or approves rail transportation rates for 

coal; and (3) the administrative burden 

on ONRR to determine approved rates 

for every State in which coal is 

produced is too great. 

The current coal rule at 30 CFR 

1206.262(b)(2)(iv)(A) permits a return 

on undepreciated capital investment in 

the transportation system as one of the 

allowable costs a lessee may include in 

non-arm’s-length or no-contract 

transportation allowances. However, 

under the current regulation, the return 

on investment ends after the capital 

costs are depreciated to (or below) a 

reasonable salvage value. In proposed 

paragraph (b)(4) of this section, we 

allow a lessee to continue to take a 

return on the reasonable salvage value 

under paragraph (i) of this section. 

Under proposed paragraph (i)(2), after 

you depreciated a transportation system 

to its reasonable salvage value, you may 

continue to include in the allowance 

calculation a cost equal to the 

reasonable salvage value, multiplied by 

the Standard & Poor’s BBB rate of return 

allowed under paragraph (k) of this 

section. We propose this change to make 

coal valuation regulations consistent 

with the Federal oil valuation 

amendments in proposed 

§ 1206.112(b)(3)(ii) and the Federal gas 

valuation amendments in proposed 

§ 1206.154(i)(1)(iii) (current Federal gas 

valuation regulation at § 1206.157(g)). 

1206.263 What are my reporting 

requirements under an arm’s-length 

transportation contract? 

1206.264 What are my reporting 

requirements under a non-arm’s-length 

transportation contract? 

1206.265 What interest and penalties 

apply if I improperly report a 

transportation allowance? 

1206.266 What reporting adjustments 

must I make for transportation 

allowances? 

ONRR proposes the same revisions to 

§§ 1206.263 through 1206.265 as those 

we propose for Federal gas valuation 

regulations under §§ 1206.155 through 

1206.157, with two exceptions. ONRR 

also proposes to add § 1206.266 to 

correspond with § 1206.158. Please refer 

to those sections for an explanation of 

the proposed changes. 

The first exception is that these 

sections keep the same reporting 

requirements as current 30 CFR 

1206.262(c), 1206.262(d), and 

1206.262(e). In addition, proposed 

§ 1206.265 (b)(1) replaces current 30 

CFR 1206.262(d)(1) regarding 

assessments if you improperly net a 

transportation allowance against the 

sales value of the coal instead of 

reporting the allowance as a separate 

entry on Form ONRR–4430. Under this 

proposed regulation, ONRR eliminates 

assessments because ONRR is now 

authorized to assess civil penalties for 

solid mineral leases under FOGRMA, 30 

U.S.C. 1719 and 30 U.S.C. 1720a. 

Penalties are a more effective 

enforcement mechanism to ensure 

lessee compliance with reporting 

requirements because ONRR can assess 

civil penalties that are significantly 

higher than the maximum assessment 

the current regulation authorizes. 

1206.267 What general washing 

allowance requirements apply to me? 

ONRR proposes to add this section to 

contain the requirements of current 30 

CFR 1206.258. This proposal makes the 

Federal coal valuation regulations 

consistent with Federal oil and gas 

valuations regulations, and consolidates 

provisions applicable to both arm’slength and non-arm’s-length washing in 

the current valuation regulations, rather 

than repeating those provisions in the 

respective sections explaining those 

allowances. We also rewrite the current 

valuation regulations in Plain Language. 

We only discuss any substantive 

changes or additions to this section 

below. 

Proposed paragraph (a) contains the 

same information as current 30 CFR 

1206.258(a) allowing you to deduct the 

reasonable, actual costs to wash coal if 

you determine the value of your coal 

under proposed § 1206.252. We also 

propose a new provision under 

paragraph (a)(2) to make clear you do 

not need ONRR’s approval before 

reporting a washing allowance for costs 

that you incur consistent with existing 

practice. 

Proposed paragraph (b) states what 

you cannot claim when you take a 

washing allowance. Paragraph (b)(1) of 

this section states that you cannot take 

an allowance for washing lease 

production that is not royalty-bearing. 

This new provision is consistent with 

the current and proposed Federal oil 

and gas valuation regulations and 

existing practices for coal valuation. 

Paragraph (b)(2) contains the current 

prohibition in 30 CFR 1206.258(c) that 

you cannot disproportionately allocate 

washing costs to Federal leases. New 

paragraph (b)(2) contains the allocation 

of washing allowance requirements 

under current 30 CFR 1206.260. 

However, new paragraph (b)(2) clarifies 

how to allocate washing costs by stating 

that you must allocate washing costs to 

washed coal attributable to each Federal 

lease by multiplying the input ratio, 

which you determine under proposed 

§ 1206.251(e)(2)(i), by the total 

allowable costs. 

Proposed paragraph (c) contains the 

requirement of current 30 CFR 

1206.259(a)(4) that you must express 

arm’s-length coal washing allowances as 

a dollar-value equivalent per ton of coal 

washed. We also apply that provision to 

non-arm’s-length washing allowances 

and make the section consistent with 

existing practices. In addition, under 

this proposed paragraph, we state that, 

if you do not base your or your affiliate’s 

payments for washing under an arm’slength contract on a dollar-per-unit 

basis, you have to convert the 

consideration you or your affiliate pay 

to a dollar-value equivalent. 

We propose to add a new paragraph 

(d) containing the same default 

provision as that for the Federal oil, gas, 

and coal transportation regulations we 

discuss above under proposed 

§§ 1206.110(f), 1206.152(g), and 

§ 1206.260(g), respectively. 

Proposed new paragraph (e) would 

contain the same provision as current 30 

CFR 1206.258(e) that you may only 

claim a washing allowance when you 

sell the washed coal and report and pay 

royalties. 

1206.268 How do I determine washing 

allowances if I have an arm’s-length 

washing contract or no written arm’slength contract? 

ONRR proposes to add this section to 

contain the requirements under current 

30 CFR 1206.259(a)(1), but we rewrite 

this section in Plain Language and 

restructure this section for consistency 

with the proposed Federal gas 

transportation allowance regulations we 

discussed above in § 1206.153. This 

proposal includes moving the 

requirements of current 

§§ 1206.259(a)(2) and 1206.259(a)(3) 

regarding additional consideration, 

misconduct, and breach of the duty to 

market to the proposed § 1206.267(d) we 

discussed above. We would move the 

requirements for non-arm’s-length 

washing allowances to § 1206.269. 

We propose to add a new paragraph 

(c) that applies if you have no written 

contract for the arm’s-length washing of 

coal. In that case, ONRR may determine 


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your washing allowance under 

§ 1206.254. You must propose to ONRR 

a method to determine the allowance 

using the procedures in § 1206.258(a). 

You may use that method to determine 

your allowance until ONRR issues a 

determination. This paragraph would 

not apply if a lessee performs its own 

washing. Rather, § 1206.269 regarding 

non-arm’s-length washing allowances 

applies. 

1206.269 How do I determine washing 

allowances if I have a non-arm’s-length 

washing contract? 

ONRR proposes to add new 

§ 1206.269 to explain how lessees must 

determine a washing allowance under a 

non-arm’s-length transportation contract 

using paragraphs (a) through (k) of this 

section. These requirements are in 

current 30 CFR 1206.259(b). We rewrite 

the current requirements in Plain 

Language and restructure, add, and 

amend this section for consistency with 

the Federal gas and coal transportation 

allowance regulations proposed above 

in §§ 1206.154 and 1206.262. We also 

propose to make several substantive 

changes we discuss below. 

The current coal rule at 30 CFR 

1206.259(b)(2)(iv)(A) permits a return 

on undepreciated capital investment in 

the wash plant as one of the allowable 

costs a lessee may include in non-arm’slength or no-contract transportation 

allowances. However, under the current 

regulation, the return on investment 

ends after the capital costs are 

depreciated to (or below) a reasonable 

salvage value. In proposed paragraph 

(b)(4) of this section, we allow lessees to 

continue to take a return on the 

reasonable salvage value under 

paragraph (i) of this section. Under 

proposed paragraph (i)(2), after you 

depreciated a wash plant to its 

reasonable salvage value, you may 

continue to include in the allowance 

calculation a cost equal to the 

reasonable salvage value multiplied by 

the Standard & Poor’s BBB rate of return 

allowed under paragraph (k) of this 

section. We propose this change in 

order to make coal valuation regulations 

consistent with the Federal oil valuation 

amendments in proposed 

§ 1206.112(b)(3)(ii) the Federal gas 

valuation amendments in proposed 

§ 1206.154(i)(1)(iii) (current Federal gas 

valuation regulation at 30 CFR 

1206.157(g)), and the Federal coal 

valuation regulation amendments 

proposed in § 1206.262 (b)(4) and in 

paragraph (i)(2) of this section. 

1206.270 What are my reporting 

requirements under an arm’s-length 

washing contract? 

1206.271 What are my reporting 

requirements under a non-arm’s-length 

washing contract? 

1206.272 What interest and penalties 

apply if I improperly report a washing 

allowance? 

1206.273 What reporting adjustments 

must I make for washing allowances? 

ONRR proposes to add §§ 1206.270 

through 1206.273, which are the same 

as we propose for Federal gas valuation 

regulations under §§ 1206.155 through 

1206.158, with two exceptions. These 

two exceptions are the same as we 

propose in §§ 1206.263 through 

1206.266. Please refer to those sections 

for an explanation of the proposed 

changes. 

Subpart J—Indian Coal 

1206.450 What is the purpose and 

scope of this subpart? 

This section would be the same as 

current 30 CFR 1206.450. We rewrite 

the current section in Plain Language 

and make this section consistent with 

the other product valuation regulations. 

As we explained above in § 1206.20, we 

replace the term ‘‘Indian allottee’’ with 

‘‘individual Indian mineral owner.’’ 

However, the substantive requirements 

remain unchanged. 

1206.451 How do I determine royalty 

quantity and quality? 

This proposed section is the same as 

current 30 CFR 1206.453, 1206.454, and 

1206.459, except that we rewrite the 

sections in Plain Language and combine 

multiple current sections into this 

proposed section. We are not proposing 

any substantive change. 

1206.452 How do I calculate royalty 

value for coal I or my affiliate sell(s) 

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

1206.453 How will ONRR determine if 

my royalty payments are correct? 

1206.454 How will ONRR determine 

the value of my coal for royalty 

purposes? 

1206.455 What records must I keep to 

support my calculations of royalty 

under this subpart? 

1206.456 What are my responsibilities 

to place production into marketable 

condition and to market production? 

1206.457 When is an ONRR audit, 

review, reconciliation, monitoring, or 

other like process considered final? 

1206.458 How do I request a valuation 

determination or guidance? 

1206.459 Does ONRR protect 

information I provide? 

ONRR proposes the same changes to 

§§ 1206.452 through 1206.459 as those 

we proposed for Federal coal valuation 

regulations under §§ 1206.252 through 

1206.259. Please refer to those proposed 

sections for an explanation of the 

changes. 

1206.460 What general transportation 

allowance requirements apply to me? 

We propose the same changes to this 

section as those we propose for Federal 

coal under § 1206.260, with two 

exceptions. Please refer to that section 

for an explanation of the proposed 

changes. 

For Indian coal under current 30 CFR 

1206.461(a)(1), a lessee must submit 

Form ONRR–4293, Coal Transportation 

Allowance Report, prior to taking an 

allowance. This provision is not in 

either the current or proposed Federal 

coal valuation regulations. However, 

ONRR proposes to retain this 

requirement for coal produced from 

Indian leases as part of our trust 

responsibility. This form submittal 

ensures that we continue the oversight 

and controls necessary on Indian leases. 

The current Indian coal regulation at 

30 CFR 1206.461(a)(1) also provide that 

a lessee who does not timely file Form 

ONRR–4293 may claim a transportation 

allowance retroactively for a period of 

not more than 3 months prior to the first 

day of the month that ONRR receives 

the lessee’s Form ONRR–4293 ‘‘unless 

ONRR approves a longer period upon a 

showing of good cause by the lessee.’’ 

We propose to remove the good cause 

exception. We have found this 

exception is difficult to administer and 

is not applicable. See Alexander Energy 

Corp., 153 IBLA 238 (2000), Union Oil 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
632 Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 

Company of California, 167 IBLA 263 

(2005). 

In addition, current 30 CFR 

1206.461(c)(1)(vi) provides that ONRR 

will allow non-arm’s-length contract or 

no written arm’s-length contract-based 

transportation allowances in effect at 

the time these regulations become 

effective, to continue until such 

allowances terminate. ONRR eliminated 

this provision for Federal coal leases in 

its 1996 Federal coal amendments but 

left this intact for Indian leases (61 FR 

5481 (1996)). To be consistent, we 

propose to remove this provision. ONRR 

also eliminated this provision for 

Federal gas leases (70 FR 11869). 

Therefore, we propose to add a new 

paragraph (a)(3) stating ‘‘You may not 

use a transportation allowance that was 

in effect before the effective date of the 

final rule. You must use the provisions 

of this subpart to determine your 

transportation allowance.’’ 

1206.461 How do I determine a 

transportation allowance if I have an 

arm’s-length transportation contract or 

no written arm’s-length contract? 

ONRR proposes the same changes to 

this section as we propose for Federal 

coal under § 1206.261. Please refer to 

that section for an explanation of the 

proposed changes. 

1206.462 How do I determine a 

transportation allowance if I have a 

non-arm’s-length transportation 

contract? 

We propose the same changes to this 

section as we propose for Federal coal 

under § 1206.262, with one exception 

discussed below. Please refer to 

§ 1206.262 for an explanation of the 

proposed changes. 

For Federal coal under proposed 

§ 1206.262, we allow a lessee to take a 

return on the reasonable salvage value 

of a transportation system. We are not 

proposing to make this change to Indian 

coal because we believe it would reduce 

the return to the Indian lessor while not 

providing a benefit to them. It would 

therefore not be in the best interest of 

the Indian lessor and be inconsistent 

with our trust responsibility. 

1206.463 What are my reporting 

requirements under an arm’s-length 

transportation contract? 

We propose to make the same changes 

to this section as we propose for Federal 

coal under § 1206.263 with one 

exception. Please refer to § 1206.263 for 

an explanation of the proposed changes. 

We also propose substantive changes to 

current 30 CFR 1206.461(c) regarding 

reporting arm’s-length transportation 

allowances. 

Unlike the Federal coal regulation, 

this proposed Indian coal regulation 

would retain the requirement for a 

lessee to submit Form ONRR–4293 prior 

to taking a transportation allowance. 

These same provisions are in current 30 

CFR 1206.458(c). Form submittal is not 

a requirement for Federal leases, but the 

form submittal ensures we continue the 

oversight and controls necessary on 

Indian leases. 

In addition to the changes we make to 

the reporting requirements under this 

section, consistent with the Federal coal 

valuation regulations, we propose to 

eliminate three provisions in the current 

Indian coal regulations. First, under the 

current 30 CFR 1206.461(c)(1)(iii), a 

lessee may request special reporting 

procedures in unique circumstances. 

ONRR eliminated this provision for 

Federal coal leases in its 1996 Federal 

coal amendments but left it intact for 

Indian leases. We do not believe any 

lessee has ever used this provision. 

Therefore, we propose to remove this 

provision. 

Second, the current coal regulation 

under 30 CFR 1206.461(c)(1)(vi) states 

ONRR may establish coal transportation 

allowance reporting requirements for 

individual leases different from those 

specified in this subpart to provide 

more effective administration. ONRR 

eliminated this provision for Federal 

coal leases in its 1996 Federal coal 

amendments but left it intact for Indian 

leases. We do not believe ONRR has 

ever used this provision. Therefore, we 

propose to remove this provision. 

Finally, current 30 CFR 

1206.461(c)(1)(vi) provides that ONRR 

will allow non-arm’s-length contract or 

no arm’s-length contract-based 

transportation allowances that are in 

effect at the time these regulations 

become effective to continue until such 

allowances terminate. We propose to 

eliminate this provision and to replace 

it with a new § 1206.460(a)(3) we 

discuss above. 

1206.464 What are my reporting 

requirements under a non-arm’s-length 

transportation contract? 

We propose to make the same 

amendments to this section as those we 

propose for section §§ 1206.264 and 

1206.463. Please refer to those proposed 

sections for an explanation of changes. 

1206.465 What interest and penalties 

apply if I improperly report a 

transportation allowance? 

We propose to make the same 

amendments to this section as those we 

propose for § 1206.265. Proposed 

paragraph (b) of this section prohibits 

the netting of transportation costs from 

gross proceeds received for a particular 

sale. When eligible to take a 

transportation allowance, a lessee must 

report gross proceeds without a 

deduction for transportation costs, and 

may simultaneously claim a 

transportation allowance for the cost of 

transporting the royalty fraction of 

Indian coal sold. Current Indian coal 

valuation regulations do not contain this 

provision. ONRR considers the change 

to be an enhancement to the Indian coal 

regulations that is already in the current 

Federal coal valuation regulations at 30 

CFR 1206.262(d). 

1206.466 What reporting adjustments 

must I make for transportation 

allowances? 

We propose the same amendments to 

this section we propose for § 1206.266. 

Please refer to the proposed section for 

an explanation of the changes. 

1206.467 What general washing 

allowance requirements apply to me? 

We propose the same amendments to 

this section we propose for §§ 1206.267 

and 1206.460. However, we propose to 

maintain the current requirement that a 

lessee must submit Form ONRR–4292, 

Coal Washing Allowance Report, prior 

to taking a washing allowance. Please 

refer to §§ 1206.267 and 1206.460 for an 

explanation of the changes. 

1206.468 How do I determine a 

washing allowance if I have an arm’slength washing contract or no written 

arm’s length contract? 

We propose to make the same 

amendments to this section we propose 

for §§ 1206.268 and 1206.461. Please 

refer to §§ 1206.268 and 1206.461 for an 

explanation of the changes. 

1206.469 How do I determine a 

washing allowance if I have a nonarm’s-length washing contract? 

We propose to make the same 

amendments to this section we propose 

for §§ 1206.269 and 1206.462, with one 

exception we discuss below. Please refer 

to §§ 1206.269 and 1206.462 for an 

explanation of the changes. 

For Federal coal under proposed 

§ 1206.269, we propose to allow a lessee 

to continually take a return on the 

reasonable salvage value of a wash 

plant. We do not propose to make this 

change to Indian coal because we 

believe it would reduce the return to the 

Indian lessor while not providing a 

benefit to them. It would therefore not 

be in the best interest of the Indian 

lessor and be inconsistent with our trust 

responsibility. 


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1206.470 What are my reporting 

requirements under an arm’s-length 

washing contract? 

We propose to make the same 

amendments to this section we propose 

for §§ 1206.270 and 1206.463. Please 

refer to §§ 1206.270 and 1206.463 for an 

explanation of the changes. 

1206.471 What are my reporting 

requirements under a non-arm’s-length 

washing contract? 

We propose to make the same 

amendments to this section we propose 

for §§ 1206.271 and 1206.464. Please 

refer to §§ 1206.271 and 1206.464 for an 

explanation of changes. 

1206.472 What interest and penalties 

apply if I improperly report a washing 

allowance? 

We propose to make the same 

amendments to this section we propose 

for §§ 1206.272 and 1206.465. Please 

refer to §§ 1206.272 and 1206.465 for an 

explanation of changes. 

1206.473 What reporting adjustments 

must I make for washing allowances? 

We propose to make the same 

amendments to this section we propose 

for §§ 1206.273 and 1206.466. Please 

refer to §§ 1206.273 and 1206.466 for an 

explanation of changes. 

III. Procedural Matters 

1. Summary Cost and Royalty Impact 

Data 

We have summarized estimated costs 

and benefits the proposed rule may have 

on potentially affected groups: Industry, 

the Federal Government, Indian lessors, 

and State and local governments. All of 

the proposed amendments that have 

cost impacts would result in increased 

royalty collections. The sum of the 

proposed amendments that have cost 

benefits are due to administrative cost 

savings to industry, not a decrease in 

royalties due. The net impact of the 

proposed amendments is an estimated 

annual increase in royalty collections of 

between $72.9 million and $87.3 

million. This net impact represents a 

slight increase of between 0.8 percent 

and 1.0 percent of the total Federal oil, 

gas, and coal royalties ONRR collected 

in 2010. We also estimate that industry 

would experience reduced annual 

administrative costs of $3.61 million. 

Please note that, unless otherwise 

indicated, numbers in the following 

tables are rounded to three significant 

digits. 

A. Industry 

The table below lists ONRR’s low, 

mid-range, and high estimates of the 

costs, by component, industry would 

incur in the first year. Industry would 

incur these costs in the same amount 

each year thereafter. 

SUMMARY OF ROYALTY IMPACTS TO INDUSTRY

Rule provision Low Mid High 

Gas—replace benchmarks 

Affiliate Resale .................................................................................................... $0 $2,010,000 $4,030,000 

Index ................................................................................................................... 11,300,000 11,300,000 11,300,000 

NGLs—replace benchmarks 

Affiliate Resale .................................................................................................... 0 256,000 510,000 

Index ................................................................................................................... 1,200,000 1,200,000 1,200,000 

Gas transportation limited to 50% ............................................................................. 4,170,000 4,170,000 4,170,000 

Processing allowance limited to 662⁄3% .................................................................... 5,440,000 5,440,000 5,440,000 

POP contracts limited to 662⁄3% processing allowance ............................................ 0 0 0 

Extraordinary processing allowance .......................................................................... 18,500,000 18,500,000 18,500,000 

BBB bond rate change for gas transportation ........................................................... 1,640,000 1,640,000 1,640,000 

Eliminate deepwater gathering .................................................................................. 17,400,000 20,500,000 23,600,000 

Oil Transportation limited to 50% .............................................................................. 6,430,000 6,430,000 6,430,000 

Oil and gas line losses .............................................................................................. 4,570,000 4,570,000 4,570,000 

Oil line fill ................................................................................................................... 978,000 1,710,000 2,450,000 

BBB bond rate change for oil transportation ............................................................. 2,380,000 2,380,000 2,380,000 

Coal—non-arm’s length netback & coop sales ......................................................... (1,060,000) 0 1,060,000 

Total .................................................................................................................... 72,900,000 80,100,000 87,300,000 

Note: Totals from this table and others in this analysis may not add due to rounding. 

ONRR identified two proposed rule 

changes that would benefit industry by 

reducing their administrative costs. The 

benefits industry would realize for each 

of these components are as follows: 

Rule provision Benefit 

Replace benchmarks— 

Gas & NGLs ................ $247,000 

Eliminate deepwater 

gathering ..................... 3,360,000 

Total ......................... 3,610,000 

The table below lists the overall 

economic impact to industry from the 

proposed changes, based on the midrange estimate of costs: 

Description Annual (cost)/benefit amount 

Cost—All Rule Provisions ($80,100,000) 

Benefit—Administrative 

Savings ....................... 3,610,000 

Net Cost or Benefit to Industry .......................... (76,500,000) 

Cost—Using First Arm’s-Length Sale To 

Value Non-Arm’s-Length Sales of 

Federal Unprocessed Gas, Residue Gas, 

and Coalbed Methane 

As discussed above, we propose 

replacing the current benchmarks in 30 

CFR 1206.152(c) (unprocessed gas) and 

1206.152(c) (processed gas) with a 

methodology that uses the gross 

proceeds under the lessee’s affiliate’s 

first arm’s-length sale to value gas for 

royalty purposes. The lessee also would 

have the option to elect to pay royalties 

based on a value using the monthly high 

index price, less a standard deduction 

for transportation. 

To perform this economic analysis, 

ONRR first extracted royalty data that 

we collected on residue gas, 

unprocessed gas, and coalbed methane 

(product codes 03, 04, 39, respectively) 

for calendar year 2010. We chose 

calendar year 2010 because the Royaltyin-Kind (RIK) volumes were minimal 

due to the 2010 termination of the RIK 

program. In previous years, RIK 

volumes were substantial. Data from 

RIK production is not representative of 

industry sales, so we excluded any 


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remaining RIK volumes from our 

analysis. We excluded calendar year 

2011 because lessees are still adjusting 

reports for that year and the data 

reported is still going through ONRR’s 

edits. 

We then extracted gas royalty data for 

non-arm’s-length transactions reported 

with a sales type code of NARM. We 

also extracted gas royalty data for sales 

type code POOL, because royalty 

reporters may also use this code to 

report non-arm’s-length transactions. 

Based on ONRR’s experience auditing 

transactions that use sales type code 

POOL, we know that only a relatively 

small portion of them are non-arm’s 

length. Therefore, we used only 10 

percent of the POOL volumes in our 

economic analysis of the volumes of gas 

sold non-arm’s length. 

Based on ONRR’s experience auditing 

production sold under non-arm’s-length 

contracts, we believe industry would 

incur a royalty increase in the range of 

0 to 5 cents per MMBtu under our 

proposal to use the affiliate’s first arm’slength resale to value gas production for 

royalty purposes. ONRR created a range 

of potential royalty increases by 

assuming no royalty increase for the low 

estimate, 2.5 cents per MMBtu for the 

mid-range estimate, and 5 cents per 

MMBtu for the high estimate. We then 

multiplied the NARM volume and 10 

percent of the POOL volume reported to 

ONRR in 2010 by the potential royalty 

increases. 

The results provided below are an 

estimated cost to industry due to an 

annual royalty increase of between zero 

and approximately $8 million. We 

reduced this estimate by one-half to 

$4.03 million, assuming 50 percent of 

the non-arm’s-length lessees would 

choose this option. 

2010 MMBtu 

(non-rounded) 

Royalty increase ($) 

Low 

(0 cents) 

Mid 

(2.5 cents) 

High 

(5 cents) 

NAL Volume ................................................................................................. 149,348,561 $0 $3,730,000 $7,470,000 

10% of POOL Volume ................................................................................. 11,606,523 0 290,000 580,000

Total ...................................................................................................... 160,955,084 0 4,020,000 8,050,000 

50% of lessees choose this option 0 2,010,000 4,030,000 

Cost—Using Index Price Option To 

Value Non-Arm’s-Length Sales of 

Federal Unprocessed Gas, Residue Gas, 

and Coalbed Methane 

To estimate the royalty impact of the 

index-based option, we calculated a 

monthly weighted average price net of 

transportation using NARM and 10 

percent of the POOL gas royalty data 

from six major geographic areas with 

active index prices—the Green River 

Basin, San Juan Basin, Piceance and 

Uinta Basins, Powder River and Wind 

River Basins, Permian Basin, and 

Offshore Gulf of Mexico (GOM). These 

six areas account for approximately 95 

percent of all Federal gas produced. To 

calculate the estimated impact, we 

performed the following steps: 

(1) Identified the Platts Inside FERC 

highest reported monthly price for the 

index price applicable to each area— 

Northwest Pipeline Rockies for Green 

River, El Paso San Juan for San Juan, 

Northwest Pipeline Rockies for Piceance 

and Uinta, Colorado Interstate Gas for 

Powder River and Wind River, El Paso 

Permian for Permian, and Henry Hub for 

GOM. 

(2) Subtracted the transportation 

deduction we specified in the proposed 

rule from the highest index price that 

we identified in step (1). 

(3) Subtracted the average monthly 

net royalty price reported to us for 

unprocessed gas from the highest index 

price for the same month we calculated 

in step (2). 

(4) Multiplied the royalty volume by 

the monthly difference that we 

calculated in step (3) to calculate a 

monthly royalty difference for each 

region. 

(5) Totaled the difference we 

calculated in step (4) for the regions. 

Although the index-based 

methodology resulted in an annual 

increase in royalties due, the current 

average royalty prices reported to us 

were higher than the index-based option 

for 3 months in 2010. 

ONRR estimates the cost to industry 

due to this change would be an increase 

in royalty collections of approximately 

$11.3 million annually. This estimate 

represents a small average increase of 

approximately 3.6 percent or 14 cents 

per MMBtu, based on an annual royalty 

volume of 160,955,084 MMBtu (for 

NARM and 10 percent POOL reported 

sales type codes). Because this is the 

first time we have offered this option, 

we don’t know how many payors will 

choose it. For purposes of this analysis, 

we are assuming that 50 percent of 

lessees with non-arm’s-length sales 

would choose this option and, therefore, 

have reduced this estimate by one-half. 

We would like to know from 

commenters if this 50-percent 

assumption is reasonable. 

2010 Index analysis GOM gas Other gas Total 

Current Royalties (rounded to the nearest dollar) ........................................................... $167,291,148 $435,222,354 $602,513,502 

Royalty under Index Option ............................................................................................. 180,000,000 445,000,000 625,000,000 

Difference ......................................................................................................................... 12,700,000 9,780,000 22,500,000 

Per Unit Uplift ($/MMBtu) ................................................................................................ 0.297 0.083 0.140 

% change ......................................................................................................................... 7.06 2.20 3.60 

50% of lessees choose this option $11,300,000 


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Cost—Using First Arm’s-Length Sale To 

Value Non-Arm’s-Length Sales of 

Federal NGLs 

Like the valuation changes we 

discussed above, for Federal 

unprocessed, residue, and coalbed 

methane gas valuation changes, the 

proposed rule would value processed 

Federal NGLs based on the first arm’slength sale rather than the current 

benchmarks. The lessee would also have 

the option to pay royalties using an 

index price value derived from an NGL 

commercial price bulletin less a 

theoretical processing allowance that 

includes transportation and 

fractionation of the NGLs. We again 

used the 2010 NARM and POOL NGL 

data reported to ONRR for this analysis. 

We performed the same analysis for 

valuation using the first arm’s-length 

sale for Federal unprocessed, residue, 

and coalbed methane gas, as we 

discussed above. We identified the nonarm’s-length volumes that would qualify 

for this option (for NARM and 10 

percent POOL reported sales type codes) 

and estimated a cents-per-gallon royalty 

increase. Based on our experience, we 

believe that the NGLs resale margin is, 

similar to gas, relatively small, ranging 

from zero to 3 cents per gallon. Thus, 

our estimated royalty increase is zero for 

the low, 1.5 cents per gallon for the midrange, and 3 cents per gallon for the 

high range. The results provided below 

show a mid-range royalty increase of 

$256,000 using these assumptions, and, 

again, we reduced them by one-half 

under the assumption that 50 percent of 

the lessees would choose this option. 

Again, we would ask for comments on 

the reasonableness of this 50-percent 

assumption. 

2010 Gallons 

(rounded to the 

nearest gallon) 

Royalty increase ($) 

Low 

(0 cents) 

Mid 

(1.5 cents) 

High 

(3 cents) 

NAL Volume ..................................................................................... 6,170,341 $0 $92,600 $185,000 

10% of POOL Volume ..................................................................... 27,913,486 0 419,000 837,000 

Total .......................................................................................... 34,083,827 0 512,000 1,020,000 

50% of lessees choose this option 0 256,000 510,000 

Cost—Using Index Price Option To 

Value Non-Arm’s-Length Sales of 

Federal NGLs 

Like the Federal unprocessed, 

residue, and coalbed methane gas 

changes we discuss above, lessees also 

would have the option to pay royalties 

on Federal NGLs using an index-based 

value less a theoretical processing 

allowance that includes transportation 

and fractionation. We used the same 

2010 NARM and POOL transaction data 

for NGLs for this analysis. We were 

unable to compare NGLs prices reported 

on the Form ONRR–2014 to those in 

commercial price bulletins because 

prices lessees report on the Form 

ONRR–2014 are one rolled-up price for 

all NGLs, but the bulletins price each 

NGLs product (such as ethane and 

propane) separately. Therefore, we base 

our analysis on the royalty changes that 

would result from the theoretical 

processing allowance proscribed under 

this new option. 

We chose a conservative number as a 

proxy for the processing allowance 

deduction that we would allow for this 

index option. To determine the cost of 

this option for NGLs, we calculated the 

difference between the average 

processing allowance reported on the 

Form ONRR–2014 and the proxy 

allowance we would allow under this 

option. That difference equaled an 

increase in value of approximately 7 

cents per gallon. We then multiplied the 

total NAL volume of 34,083,827 gallons 

reported to us by the 7 cents per gallon, 

for an estimated royalty increase of $2.4 

million. We reduced this number by 

one-half under the assumption that 50 

percent of lessees would choose this 

option, resulting in a total cost to 

industry of $1.2 million. Again, we 

would ask for comments on the 

reasonableness of this 50-percent 

assumption. 

Benefit—Using Index Price Option To 

Value Non-Arm’s-Length Federal 

Unprocessed Gas, Residue Gas, 

Coalbed Methane, and NGLs 

ONRR expects that industry would 

benefit by realizing administrative 

savings if they choose to use the indexbased option to value non-arm’s-length 

sales of Federal unprocessed gas, 

residue gas, coalbed methane, and 

NGLs. Lessees would know the price to 

use to value their production, saving the 

time it currently takes to calculate the 

correct price based on the current 

benchmarks. They would also save time 

using the ONRR-specified transportation 

rate for gas and the ONRR-specified 

processing allowance for NGLs, rather 

than having to calculate those values 

themselves. 

Of the lessees that we estimate would 

use this option, we estimate the indexbased option would shorten the time 

burden per line reported by 50 percent 

to 1.5 minutes for lines industry 

electronically submits and 3.5 minutes 

for lines they manually submit. We used 

tables from the Bureau of Labor 

Statistics (www.bls.gov/oes132011.htm) 

to estimate the hourly cost for industry 

accountants in a metropolitan area. We 

added a multiplier of 1.4 for industry 

benefits. The industry labor cost factor 

for accountants would be approximately 

$50.53 per hour = $36.09 [mean hourly 

wage] × 1.4 [benefits cost factor]. Using 

a labor cost factor of $50.53 per hour, 

we estimate the annual administrative 

benefit to industry would be 

approximately $247,000. 

Time burden per 

line reported 

Estimated lines 

reported using 

index option 

(50%) 

Annual burden 

hours 

Electronic Reporting (99%) .............................................................................................. 1.5 min 190,872 4,772 

Manual Reporting (1%) .................................................................................................... 3.5 min 1,928 112 

Industry Labor Cost/hour ................................................................................................. ............................ ............................ $50.53 


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Time burden per 

line reported 

Estimated lines 

reported using 

index option 

(50%) 

Annual burden 

hours 

Total Benefit to Industry ........................................................................................... ............................ ............................ $247,000 

Cost—Elimination of Transportation 

Allowances in Excess of 50 Percent of 

the Value of Federal Gas 

The current Federal gas valuation 

regulations limit lessees’ transportation 

allowances to 50 percent of the value of 

the gas unless they request and receive 

approval to exceed that limit. The 

proposed rule would eliminate the 

lessees’ ability to exceed that limit. To 

estimate the costs associated with this 

change, we first identified all calendar 

year 2010 reported gas transportation 

allowances rates that exceeded the 50- 

percent limit. We then adjusted those 

allowances down to the 50-percent limit 

and totaled that value to estimate the 

economic impact of this provision. The 

result was an annual estimated cost to 

industry of $4.17 million in additional 

royalties. 

Cost—Elimination of Transportation 

Allowances in Excess of 50 Percent of 

the Value of Federal Oil 

The current Federal oil valuation 

regulations limit lessees’ transportation 

allowances to 50 percent of the value of 

the oil unless they request and receive 

approval to exceed that limit. The 

proposed rule would eliminate the 

lessees’ ability to exceed that limit. To 

estimate the costs associated with this 

change, we first identified all calendar 

year 2010 reported oil transportation 

allowance rates that exceeded the 50- 

percent limit. We then adjusted those 

allowances down to the 50-percent limit 

and totaled that value to estimate the 

economic impact of this provision. The 

result was an annual estimated cost to 

industry of $6.43 million in additional 

royalties. 

Cost—Elimination of Processing 

Allowances in Excess of 662⁄3 Percent of 

the Value of the NGLs for Federal Gas 

The current Federal gas valuation 

regulations limit lessees’ processing 

allowances to 662⁄3 percent of the value 

of the NGLs unless they request and 

receive approval to exceed that limit. 

The proposed rule would eliminate the 

lessees’ ability to exceed that limit. To 

estimate the cost to industry associated 

with this change, we first identified all 

calendar year 2010 reported processing 

allowances greater than 662⁄3 percent. 

We then adjusted those allowances 

down to the 662⁄3-percent limit and 

totaled that value to estimate the 

economic impact of this provision. The 

result was an annual estimated cost to 

industry of $5.44 million in additional 

royalties. 

Cost—POP Contracts now Subject to the 

662⁄3 Percent Processing Allowance 

Limit for Federal Gas 

Lessees with POP contracts currently 

pay royalties based on their gross 

proceeds as long as they pay a minimum 

value equal to 100 percent of the residue 

gas. Under the proposed rule, we also 

would not allow lessees with POP 

contracts to deduct more than the 662⁄3

percent of the value of the NGLs. For 

example, a lessee with a 70-percent POP 

contract receives 70 percent of the value 

of the residue gas and 70 percent of the 

value of the NGLs. The 30 percent of 

each product the lessee gives up to the 

processing plant in the past could not, 

when combined, exceed an equivalent 

value of 100 percent of the NGLs’ value. 

Under the proposed rule, the combined 

value of each product the lessee gives 

up to the processing plant cannot 

exceed two-thirds of the NGLs’ value. 

Lessees report POP contracts to ONRR 

using sales type code APOP for arm’slength POP contracts and NPOP for nonarm’s-length POP contracts. Because 

lessees report APOP sales as 

unprocessed gas, there are no reported 

processing allowances for us to analyze 

and we cannot determine the breakout 

between residue gas and NGLs. Lessees 

do report residue gas and NGLs 

separately for NPOPs. However, NPOP 

volumes constitute only 0.02 percent of 

all the natural gas royalty volumes 

reported to ONRR. We deemed the 

NPOP volume to be too low to 

adequately assess the impact of this 

provision on both APOP and NPOP 

contracts. 

Therefore, we decided to examine all 

reported calendar year 2010 onshore 

residue gas and NGLs royalty data and 

assumed it was processed and that 

lessees paid royalties as if they sold the 

residue gas and NGLs under a POP 

contract. We restricted our analysis to 

residue gas and NGLs volumes 

produced onshore because we are not 

aware of any offshore POP contracts. We 

first totaled the residue gas and NGLs’ 

royalty value for calendar year 2010 for 

all onshore royalties. We then assumed 

that these royalties were subject to a 70- 

percent POP contract. Based on our 

experience, a 70/30 split is typical for 

POP contracts. We calculated 30 percent 

of both the value of residue gas and 

NGLs to approximate a theoretical 30- 

percent processing deduction. We then 

compared the 30-percent total of residue 

gas and NGLs values to 662⁄3 percent of 

the NGLs value (the maximum 

allowance under the proposed rule). 

The table below summarizes these 

calculations which we rounded to the 

nearest dollar: 

2010 

Royalty value 70% 30% 

Residue Gas .................................................................................................................... $602,194,031 $421,535,822 $180,658,209 

NGLs ................................................................................................................................ 506,818,440 354,772,908 152,045,532 

Total .......................................................................................................................... 1,109,012,471 776,308,730 332,703,741 

66.67% Limit .................................................................................................................... 337,878,960 (506,818,440 × 2⁄3) 

Our analysis shows that the 

theoretical processing deduction for 30 

percent of the value of residue gas and 

NGLs ($333 million) under our assumed 

onshore POP contract allowance would 

not exceed the 662⁄3 cap ($338 million) 

under the proposed rule and, thus, we 

estimate that this change would be 

revenue neutral. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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Cost—Termination of Policy Allowing 

Transportation Allowances for 

Deepwater Gathering Systems for 

Federal Oil and Gas 

The Deep Water Policy we discuss 

above allows companies to deduct 

certain expenses for subsea gathering 

from their royalty payments, even 

though those costs do not meet ONRR’s 

definition of transportation. The 

proposed rule would rescind and 

supersede the Deep Water Policy, and 

lessees would have to pay royalties 

under our proposed valuation 

regulations applicable to Federal oil and 

gas transportation allowances 

prospectively. To analyze the cost 

impact to industry of rescinding this 

policy, we used data from BSEE’s Arc 

GIS TIMS (Technical Information 

Management System) database to 

estimate that 113 subsea pipeline 

segments serving 108 leases currently 

qualify for an allowance under the 

policy. We assumed all segments were 

the same—in other words, we did not 

take into account the size, length, or 

type of pipeline. We also considered 

only pipeline segments that were in 

active status and leases in producing 

status for our analysis. To determine a 

range (shown in the tables below as low, 

mid, and high estimates) for the cost to 

industry, ONRR estimated a 15-percent 

error rate in our identification of the 113 

eligible pipeline segments, resulting in 

a range of 96 to 130 eligible pipeline 

segments. 

Historical ONRR audit data is 

available for 13 subsea gathering 

segments serving 15 leases covering 

time periods from 1999 through 2010. 

We used this data to determine an 

average initial capital investment in 

pipeline segments. We used the initial 

capital investment amount to calculate 

depreciation and a return on 

undepreciated capital investment (ROI) 

for the eligible pipeline segments. We 

calculated depreciation using a straightline depreciation schedule based on a 

20-year useful life of the pipeline. We 

calculated ROI using 1.0 times the 

average BBB Bond rate for January 2012, 

which was the most recent full month 

of data when we performed this 

analysis. We based the calculations for 

depreciation and ROI on the first year a 

pipeline was in service. 

From the same audit data, we 

calculated an average annual operating 

and maintenance (O&M) cost. We 

increased the O&M cost by 12 percent 

to account for overhead expenses. Based 

on experience and audit data, we 

assumed 12 percent is a reasonable 

increase for overhead. We then 

decreased the total annual O&M cost per 

pipeline segment by 9 percent because 

an average of 9 percent of offshore 

wellhead oil and gas production is 

water, which is not royalty bearing. 

Finally, we used an average royalty rate 

of 14 percent, which is the volume 

weighted average royalty rate for all 

non-Section 6 leases in the GOM. Based 

on these calculations, the average 

annual allowance per pipeline segment 

is approximately $226,000. This 

represents the estimated amount per 

pipeline segment ONRR will no longer 

allow a lessee to take as a transportation 

allowance based on our rescission of the 

Deep Water Policy in this proposed 

rulemaking. 

The total cost to industry would be 

the $226,000 annual allowance per 

pipeline segment that we would 

disallow under this proposed 

rulemaking times the number of eligible 

segments. To calculate a range for the 

total cost, we 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 we would 

disallow are $21.8 million, $25.6 

million, and $29.5 million, respectively. 

Of currently eligible leases, 42 out of 

108, or about 40 percent, qualify for 

deep water royalty relief. However, due 

to varying lease terms, royalty relief 

programs, price thresholds, volume 

thresholds, and other factors, ONRR 

estimated that only half of the 42 leases 

eligible for royalty relief (20 percent) 

actually received royalty relief. 

Therefore, we decreased the low, mid, 

and high estimated annual cost to 

industry by 20 percent. The table below 

shows the estimated royalty impact of 

this section of the proposed rule based 

on the allowances we would no longer 

allow under this proposed rule. 

Low Mid High 

Estimated Royalty Impact ................................................................................................ $17,400,000 $20,500,000 $23,600,000 

Benefit—Termination of Policy 

Allowing Transportation Allowances 

for Deepwater Gathering Systems for 

Offshore Federal Oil and Gas 

ONRR estimates the elimination of 

transportation allowances for deepwater 

gathering systems would provide 

industry with an administrative benefit 

because they would no longer have to 

perform this calculation. We believe the 

cost to perform this calculation is 

significant because industry has often 

hired outside consultants to calculate 

their subsea transportation allowances. 

Using this information, we estimated 

each company with leases eligible for 

transportation allowances for deepwater 

gathering systems would allocate one 

full-time FTE annually to perform this 

calculation, if they use consultants or 

perform the calculation in-house. We 

used the Bureau of Labor Statistics to 

estimate the hourly cost for industry 

accountants in a metropolitan area 

[$36.09 mean hourly wage] with a 

multiplier of 1.4 for industry benefits to 

equal approximately $50.53 per hour 

[$36.09 × 1.4]. Using this labor cost per 

hour, we estimate the annual 

administrative benefit to industry would 

be approximately $3,360,000. 

Annual burden 

hours per 

company 

Industry labor 

cost/hour 

Companies reporting eligible 

leases 

Estimated 

benefit to industry 

Deepwater Gathering ....................................................................................... 2,080 $50.53 32 $3,360,000 

Cost—Elimination of Extraordinary 

Cost Gas Processing Allowances for 

Federal Gas 

As we discuss above, we are 

proposing to eliminate the provision in 

our current regulations that allow a 

lessee to request an extraordinary 

processing cost allowance and to 

terminate any extraordinary cost 

processing allowances we previously 

granted. We have granted two such 

approvals in the past, so we know the 

lease universe that is claiming this 

allowance and were able to retrieve the 

processing allowance data lessees 


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deducted from the value of residue gas 

produced from the leases. We then 

calculated the annual total processing 

allowance lessees have claimed for 2007 

through 2010 for the leases at issue. We 

then averaged the yearly totals for those 

4 years to estimate an annual cost to 

industry of $18.5 million in increased 

royalties. 

Cost—Decrease Rate of Return Used to 

Calculate Non-Arm’s Length 

Transportation Allowances from 1.3 to 

1 Times the Standard and Poor’s BBB 

Bond for Federal Oil and Gas 

For Federal oil transportation, ONRR 

does not maintain or request data 

identifying if transportation allowances 

are arm’s length or non-arm’s length. 

However, based on our experience, we 

believe that a large portion of GOM oil 

is transported through lessee-owned 

pipelines. In addition, many onshore 

transportation allowances include costs 

of trucking and rail and, most likely, 

this change would not impact those. 

Therefore, to calculate the costs 

associated with this change, we 

assumed that 50 percent of the GOM 

transportation allowances are non-arm’s 

length and 10 percent of transportation 

allowances everywhere else (onshore 

and offshore other than the GOM) are 

non-arm’s length. We also assumed that, 

over the life of the pipeline, allowance 

rates are made up of one-third rate of 

return on undepreciated capital 

investment, one-third depreciation 

expenses, and one-third operation, 

maintenance, and overhead expenses. 

These are the same assumptions we 

made when analyzing changes to both 

the Federal oil and Federal gas 

valuation rules in 2004. 

In 2010, the total oil transportation 

allowances Federal lessees deducted 

were approximately $60 million from 

the GOM and $11 million from 

everywhere else. Based on these totals 

and our assumptions about the 

allowance components, the portion of 

the non-arm’s-length allowances 

attributable to the rate of return would 

be approximately $10,000,000 for the 

GOM ($60,000,000 x 1⁄3 × 50%) and 

$367,000 ($11,000,000 × 1⁄3 × 10%) for 

the rest of the country. Therefore, we 

estimate that decreasing the basis for the 

rate of return by 23 percent could result 

in decreased yearly oil transportation 

allowance deductions of approximately 

$2,380,000 ($10,367,000 × 0.23). Thus, 

we estimate the net cost to industry as 

a result of this change would be an 

approximately $2,380,000 increase in 

royalties due. 

With respect to Federal gas, like oil, 

ONRR does not maintain or request 

information on whether gas 

transportation allowances are arm’s 

length or non-arm’s length. However, 

unlike oil, we believe that it is not 

common for GOM gas to be transported 

through lessee-owned pipelines. 

Therefore, we assumed that only 10 

percent of all gas transportation 

allowances are non-arm’s length and 

made no distinction between the GOM 

and everywhere else. All other 

assumptions for natural gas are the same 

as those we made for oil above. 

In 2010, the total gas transportation 

allowances Federal lessees deducted 

were approximately $214 million. Based 

on that total and our assumptions 

regarding the makeup of the allowance 

components, the portion of the nonarm’s-length allowances attributable to 

the rate of return would be 

approximately $7.13 million 

($214,000,000 × 1⁄3 × 10%). Therefore, 

we estimate that decreasing the basis for 

the rate of return by 23 percent could 

result in decreased yearly gas 

transportation allowance deductions of 

approximately $1.64 million ($7.13 

million × 0.23). That is, the net 

increased cost to industry, based on this 

change, would be approximately 

$1,640,000 in additional royalties. 

Cost—Allow a Rate of Return on 

Reasonable Salvage Value for Federal 

Oil, Gas, and Coal 

For Federal oil and gas, after a 

transportation system or a processing 

plant has been depreciated to its 

reasonable salvage value, we propose to 

allow a lessee a return on that 

reasonable salvage value of the 

transportation system or processing 

plant as long as the lessee uses that 

system or plant for its Federal oil or gas 

production. We estimate the economic 

impact on industry would be small 

because we would continue the 

requirements of the current regulations 

that a lessee must base depreciation of 

a system or plant upon the useful life of 

the equipment or the expected life of the 

reserves served by the system or plant. 

Thus, when properly established, the 

depreciation schedule should reflect the 

useful life of the system or plant, and 

ONRR would not expect a lessee to 

continue to use a system or plant for 

periods significantly longer than the 

period reflected by the depreciation 

schedule the lessee established for 

royalty purposes. This assumption is 

true especially if the lessee did not 

make additional capital expenditures 

that extended the life of the system or 

plant. In that case, the lessee should 

have extended the depreciation 

schedule to reflect the extended life of 

the system or plant, and, possibly, the 

salvage value, itself. In other words, we 

believe the vast majority of systems 

would not be depreciated to salvage 

value while royalty is being paid 

because the system still has a useful life 

while production occurs. Thus, we do 

not believe there would be any costs to 

industry associated with this change. 

With respect to Federal coal, we 

believe that the royalty impact for coal 

would be equally small for the same 

reasons we mention above. 

Cost—Disallow Line Loss as a 

Component of Arm’s-Length and NonArm’s-Length Oil and Gas 

Transportation 

ONRR also proposes to eliminate the 

current regulatory provision allowing a 

lessee to deduct costs of pipeline losses, 

both actual and theoretical, when 

calculating non-arm’s-length 

transportation allowances. For this 

analysis, we assumed that pipeline 

losses are 0.2 percent of the volume 

transported through the pipeline, based 

on a survey of pipeline tariff. This 0.2 

percent of the volume transported also 

equates to 0.2 percent of the value of the 

Federal royalty volume of oil and gas 

production transported. 

For Federal oil produced in calendar 

year 2010, the total value of the Federal 

royalty volume subject to transportation 

allowances was $3,796,827,823 in the 

GOM and $1,204,177,633 everywhere 

else. Using our previous assumption 

that 50 percent of GOM and 10 percent 

of everywhere else’s transportation 

allowances are non-arm’s length, we 

estimated that the value of the line loss 

would be $4.04 million, as we detailed 

in the table below. Therefore, the annual 

cost to industry would be approximately 

$4.04 million in additional royalties. 


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OIL LINE LOSS ROYALTY IMPACT

Line loss (%) Royalty increase 

50% of GOM royalty value ........................................................................................ $1,898,413,912 0.2 $3,800,000 

10% of everywhere else royalty value ...................................................................... 120,417,763 0.2 241,000 

Total .................................................................................................................... .............................. .............................. 4,040,000 

For Federal gas produced in calendar 

year 2010, the royalty value of the 

Federal gas royalty volume subject to 

transportation allowances was 

$2,656,843,158. Using our previous 

assumption that 10 percent of Federal 

gas transportation allowances are nonarm’s length, we estimated the value of 

the line loss would be $530,000. 

Therefore, the annual cost to industry 

would be approximately $530,000 in 

increased royalties. 

GAS LINE LOSS ROYALTY IMPACT

Line loss (%) Royalty increase 

10% of royalty value .................................................................................................. $265,684,316 0.2 $531,000 

The total estimated royalty increase 

for both oil and gas due to this change 

would be $4.57 million [$4,040,000 (oil) 

plus $531,000 (gas) = $4,570,000]. 

Cost—Disallow Line Fill as a 

Component of Non-Arm’s-Length Oil 

Transportation Allowances 

We estimated that oil line fill costs 

ranged from a low $0.02 to a high of 

$0.05 per barrel, with a mid-range of 

$0.035. These are the same estimates we 

made in our 2004 oil valuation rule 

when we made a change to allow this 

component as a cost of oil 

transportation, and we believe these 

cost estimates are still valid. We 

restricted our analysis to only oil 

production from the GOM because we 

believe that including line fill as a 

component of transportation allowances 

is uncommon everywhere else. We then 

applied these estimates to the total 2010 

GOM Federal oil royalty volume of 

48,910,000 barrels to estimate the range 

of reduced transportation costs included 

in allowance calculations, as we detail 

in the table below. 

LINE FILL ROYALTY IMPACT ESTIMATE

2010 Federal GOM Royalty Oil Volume (barrels) 

Low Mid High 

($0.02 per barrel) ($0.035 per barrel) ($0.05 per barrel) 

48,910,000 ................................................................................................................. $978,000 $1,710,000 $2,450,000 

In other words, based on this analysis, 

the proposed rule would not allow 

lessees to include the amounts in the 

table above as a component of their 

transportation allowance. 

Cost—Depreciating Oil Pipeline Assets 

Only Once 

ONRR proposes to allow depreciation 

of oil pipeline assets only one time. 

Under our current valuation regulations 

for Federal oil, if an oil pipeline is sold, 

ONRR allows the purchasing company 

to include the purchase price to 

establish a new depreciation schedule 

and, in essence, depreciate the same 

piece of pipe twice or more if it is sold 

again. Under this proposed rulemaking, 

we would allow depreciation only once. 

In theory, this change could result in 

additional royalties. However, based on 

our experience monitoring the oil 

markets, we believe that the sale of oil 

pipeline assets is rare, and we are not 

aware of any such sales in the last 5 

calendar years. We are also not aware of 

any planned future sales of oil pipelines 

that this proposed rule change would 

impact. Therefore, although ONRR 

believes that there will be a cost to 

industry under this proposal, we cannot 

quantify the cost at this time. 

Cost—Using First Arm’s-Length Sale To 

Value Non-Arm’s-Length Sales of 

Federal Coal and Sales of Federal Coal 

Between Coal Cooperatives and Coal 

Cooperative Members and Between 

Coal Cooperative Members 

We discuss this cost in the next 

section. 

Cost—Using Sales of Electricity To 

Value Non-Arm’s-Length Sales of 

Federal Coal and Sales of Federal Coal 

Between Coal Cooperatives and Coal 

Cooperative Members and Between 

Coal Cooperative Members 

In ONRR’s experience, non-arm’slength sales of Federal coal that is then 

resold at arm’s length are rare. Under 

the current valuation regulations, such 

sales result in royalty values equivalent 

to values that result under the proposed 

regulation at § 1206.252(a) based on 

arm’s-length resale prices. Thus, ONRR 

estimates that there will be no royalty 

effect for these types of sales. In other 

words, there is no cost to lessees who 

produce Federal coal due to this 

valuation change in the proposed rule. 

The remaining non-arm’s-length 

dispositions of Federal coal (including 

lessees, their affiliates, coal 

cooperatives, and members of coal 

cooperatives) are when the lessee, its 

affiliate, coal cooperatives, or members 

of coal cooperatives consume(s) the 

Federal coal produced to generate 

electricity. These dispositions typically 

constitute from about one to two percent 

of royalties paid on Federal coal 

produced. 

Under the proposed rule, a lessee, its 

affiliates, a coal cooperative, and a 

member of a coal cooperative generally 

would base the royalty value of such 

sales on the sales value of the 

electricity, less costs to generate and, in 

some cases, transmit the electricity to 

the buyers, and less applicable coal 

washing and transportation costs. ONRR 

has limited experience determining 

lease product royalty values using the 


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methodology under proposed 

§ 1206.252(b)(1). Therefore, to perform 

an economic analysis, ONRR first 

determined the average royalties paid to 

ONRR in calendar years 2009 through 

2011 for these Federal coal dispositions. 

Based on our experience with other 

dispositions of Federal coal, ONRR 

estimated that, at most, royalty values 

under the proposed rule would increase 

or decrease by 10 percent, compared to 

royalty values we determined under 

current regulations. Using these 

assumptions, ONRR estimated the 

annual average royalty impact and, thus, 

the cost or benefit to industry from the 

proposed rule. 

Our methodology is the same for 

estimating the royalty impact of using 

sales of electricity to value non-arm’slength sales of Federal coal, sales of 

Federal coal between coal cooperatives 

and coal cooperative members, and 

sales between coal cooperative 

members. Therefore, the estimated 

royalty impact would be a combined 

figure covering all such valuation of 

Federal coal under the proposed rule. 

Accordingly, ONRR estimates the 

combined average annual royalty 

impacts for these coal dispositions 

would range from a royalty decrease of 

$1.06 million (benefit) to a royalty 

increase of $1.06 million (cost). 

ONRR requests comments on its 

estimates of the cost regarding valuation 

of these dispositions of Federal coal 

under the proposed rule. In particular, 

we seek information on the costs of 

electric power generation and 

transmission and whether the proposed 

rule would result in royalty increases or 

decreases. 

Cost—Using Default Provision To Value 

Non-Arm’s-Length Sales of Federal 

Coal in Lieu of Sales of Electricity 

If ONRR were unable to establish 

royalty values of Federal coal using the 

sales value of electricity generated from 

coal produced, royalty value would be 

based on a method the lessee proposes 

under § 1206.252(b)(2)(i), which ONRR 

approves, or on a method that ONRR 

determines under § 1206.254. In either 

case, ONRR would accept or would 

assign a royalty value that would 

approximate the market value of the 

coal. Whether valuing under 

§§ 1206.252(b)(2)(i) or 1206.254, the 

lessee and ONRR would employ a 

valuation method that uses or 

approximates market value. Current coal 

valuation regulations also attempt to 

provide royalty values that would 

approximate the market value of this 

coal. Thus, given the low percentage of 

non-arm’s-length dispositions of Federal 

coal and the use of market-based 

methods to determine royalty value 

under the current regulations and the 

proposed rule, if valuation does not 

follow § 1206.252(a) or § 1206.252(b)(1), 

ONRR estimates that the royalty effect of 

the proposed rule on lessees of Federal 

coal would be nominal. 

Cost—Using First Arm’s-Length Sale To 

Value Non-Arm’s-Length Sales of 

Indian Coal 

Currently, lessees of Indian coal sell 

their entire production at arm’s-length 

so this proposed change would have no 

cost impact on lessees of Indian coal. 

Cost—Using Sales of Electricity To 

Value Non-Arm’s-Length Sales of 

Indian Coal 

Currently, lessees of Indian coal sell 

their entire production at arm’s-length 

so this proposed change would have no 

cost impact on lessees of Indian coal. 

Cost—Using First Arm’s-Length Sale To 

Value Sales of Indian Coal Between 

Coal Cooperative Members 

Currently, no coal cooperatives are 

lessees of Indian coal, so we do not 

expect there to be any royalty impact as 

a result of the proposed rule change. 

Cost—DOI Use of Default Provision To 

Value Federal Oil, Gas, or Coal and 

Indian Coal 

As we discussed above, we propose to 

add a ‘‘default provision’’ that addresses 

valuation when the Secretary cannot 

determine the value of production 

because of a variety of factors, or the 

Secretary determined the value is wrong 

for a multitude of reasons (for example, 

misconduct). In those cases, the 

Secretary would exercise his/her 

authority, and considerable discretion, 

to establish the reasonable value of 

production using a variety of 

discretionary factors and any other 

information the Secretary believes is 

appropriate. This default provision 

covers all products (Federal oil, gas and 

coal, and Indian coal) and all pertinent 

valuation factors (sales, transportation, 

processing, and washing). 

Based on our experience, ONRR 

believes it would rarely use the default 

option. We also believe that assigning a 

royalty impact figure to any of the 

default provisions is speculative 

because (1) each instance would be 

case-specific, (2) we cannot anticipate 

when we would use the option, and (3) 

we cannot anticipate the value we 

would require companies to pay. 

Additionally, we believe the royalty 

impact would be relatively small 

because the default provisions would 

always establish a reasonable value of 

production using market-based 

transaction data, which has always been 

the basis for our royalty valuation rules 

in the first instance. 

B. State and Local Governments 

This proposed rule would not impose 

any additional burden on local 

governments. ONRR estimates that the 

States this rule impacts would receive 

an overall increase in royalties as 

follows: 

States receiving revenues for offshore 

Outer Continental Shelf Lands Act 

Section 8(g) leases would share in a 

portion of the increased royalties 

resulting from this proposed rule, as 

would States receiving revenues from 

onshore Federal lands. Based on the 

ratio of Federal revenues disbursed to 

States for section 8(g) leases and 

onshore States we detail in the table 

below, ONRR assumed the same 

proportion of revenue increases for each 

proposal that would impact those State 

revenues for most of the provisions. 

ROYALTY DISTRIBUTIONS BY LEASE

TYPE

Onshore 

(%) 

Offshore 

(%) 

8(g) 

(%) 

Fed .................. 50 100 73 

State ............... 50 0 0 

State (8g) ........ 0 0 27 

Some provisions, such as deepwater 

gathering allowances, affect only 

Federal revenues, while others, such as 

the extraordinary processing allowance, 

affect only onshore States and Federal 

revenues. The table summarizing the 

State and local government royalty 

increases we provide in section E details 

these differences. 

The State distribution for offshore 

royalties would increase at some point 

in time because of the provisions of the 

Gulf of Mexico Energy Security Act of 

2006 (GOMESA) (Pub. Law No. 109– 

432, 120 Stat. 2922). Section 105 of 

GOMESA provides Outer Continental 

Shelf (OCS) oil and gas revenue sharing 

provisions for the four Gulf producing 

States (Alabama, Louisiana, Mississippi, 

and Texas) and their eligible coastal 

political subdivisions. Through fiscal 

year 2016, the only shareable qualified 

revenues originate from leases issued 

within two small geographic areas. 

Beginning in fiscal year 2017, qualified 

revenues originating from leases issued 

since the passing of GOMESA located 

within the balance of the GOM acreage 

will also become shareable. The 

majority of these leases are not yet 

producing. The time necessary to start 

production operations and to produce 

royalty-bearing quantities varies from 


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lease to lease, and these factors directly 

influence how the distribution of 

offshore royalties will change over time. 

None of the leases in these frontier areas 

have begun producing, and we believe 

it is speculative to anticipate when they 

will begin producing royalty-bearing 

quantities and impact the distribution of 

revenues to States. 

C. Indian Lessors 

ONRR estimates that the proposed 

changes to the coal regulations that 

apply to Indian lessors would have no 

impact on their royalties. 

D. Federal Government 

The impact to the Federal 

Government, like the States, would be a 

net overall increase in royalties as a 

result of these proposed changes. In fact, 

the royalty increase anticipated by the 

Federal Government would be the 

difference between the total royalty 

increase from industry and the royalty 

increase affecting the States. The net 

yearly impact on the Federal 

Government would be approximately 

$61.8 million we detail in section E. 

E. Summary of Royalty Impacts and 

Costs to Industry, State and Local 

Governments, Indian Lessors, and the 

Federal Government. 

In the table below, the negative values 

in the Industry column represent their 

estimated royalty increases, while the 

positive values in the other columns 

represent the increase in royalty receipts 

by each affected group. For purposes of 

this summary table, we assumed that 

the average for royalty increases is the 

midpoint of our range. 

Rule provision Industry Federal State State 8(g) 

Gas—replace benchmarks 

Affiliate Resale .......................................................................................... ($2,010,000) $1,390,000 $605,000 $13,500 

Index ......................................................................................................... (11,300,000) 7,820,000 3,400,000 75,700 

NGLs—replace benchmarks 

Affiliate Resale .......................................................................................... (256,000) 191,000 63,000 1,850 

Index ......................................................................................................... (1,200,000) 896,000 295,000 8,650 

Gas transportation limited to 50% ................................................................... (4,170,000) 2,890,000 1,260,000 27,900 

Processing allowance limited to 662⁄3 % ......................................................... (5,440,000) 4,060,000 1,340,000 39,200 

POP contracts limited to 662⁄3 % ..................................................................... 0 0 0 0 

Extraordinary processing allowance ................................................................ (18,500,000) 9,250,000 9,250,000 0 

BBB bond rate change for gas transportation ................................................. (1,640,000) 1,140,000 494,000 11,000 

Eliminate deepwater gathering ........................................................................ (20,500,000) 20,500,000 0 0 

Oil Transportation limited to 50% .................................................................... (6,430,000) 5,810,000 594,000 27,100 

Oil and gas line losses .................................................................................... (4,570,000) 4,130,000 422,000 19,200 

Oil line fill ......................................................................................................... (1,710,000) 1,540,000 158,000 7,190 

BBB bond rate change for oil transportation ................................................... (2,380,000) 2,150,000 220,000 10,000 

Coal—non-arm’s length netback & coop sales ............................................... 0 0 0 0 

Total .......................................................................................................... (80,100,000) 61,800,000 18,100,000 241,000 

2. Regulatory Planning and Review (E.O. 

12866) 

This document is a significant rule, 

and the Office of Management and 

Budget (OMB) has reviewed this 

proposed rule under Executive Order 

12866. We made the assessments that 

E.O. 12866 requires, and we provide the 

results below. 

a. This proposed rule would not have 

an effect of $100 million or more on the 

economy. It would not adversely affect 

in a material way the economy, 

productivity, competition, jobs, the 

environment, public health or safety, or 

state, local, or tribal governments or 

communities. The Summary of Royalty 

Impacts table, in item 1 above, 

demonstrates that the economic impact 

on industry, State and local 

governments, and the Federal 

Government would be well below the 

$100 million threshold the Federal 

Government uses to define a rule as 

having a significant impact on the 

economy. 

b. This proposed rule would not 

create a serious inconsistency or 

otherwise interfere with an action 

another agency has taken or planned. 

ONRR is the only agency that 

promulgates rules for royalty valuation 

on Federal oil and gas leases and 

Federal and Indian coal leases. 

c. This proposed rule would not alter 

the budgetary effects of entitlements, 

grants, user fees, or loan programs or the 

rights or obligations of their recipients. 

The scope of this proposed rule does not 

have a material impact in any of these 

areas. 

d. This proposed rule would raise 

novel legal or policy issues but would 

simplify the valuation regulations, thus 

reducing the possibility of impacts as a 

result of any novel legal and policy 

issues. 

3. Regulatory Flexibility Act 

The Department of the Interior 

certifies that this proposed rule would 

not have a significant economic effect 

on a substantial number of small entities 

under the Regulatory Flexibility Act (5 

U.S.C. 601 et seq.); see item 1 above for 

analysis. 

4. Small Business Regulatory 

Enforcement Fairness Act 

This proposed rule is not a major rule 

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

Business Regulatory Enforcement 

Fairness Act. This proposed rule: 

a. Would not have an annual effect on 

the economy of $100 million or more. 

We estimate the maximum effect would 

be $87,300,000. See item 1 above. 

b. Would not cause a major increase 

in costs or prices for consumers, 

individual industries, Federal, State, or 

local government agencies, or 

geographic regions. See item 1 above. 

c. Would not have significant adverse 

effects on competition, employment, 

investment, productivity, innovation, or 

the ability of U.S.-based enterprises to 

compete with foreign-based enterprises. 

This proposed rule would be to the 

benefit of U.S.-based enterprises and 

would be a result of suggestions made 

through the Royalty Policy Committee 

made up, in part, of industry 

representatives. 

5. Unfunded Mandates Reform Act 

This proposed rule would not impose 

an unfunded mandate on state, local, or 

tribal governments, or the private sector 

of more than $100 million per year. This 

proposed rule would not have a 

significant or unique effect on State, 

local, or tribal governments, or the 

private sector. Therefore, we are not 

providing a statement containing the 

information that the Unfunded 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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Mandates Reform Act (2 U.S.C. 1501 et 

seq.) requires. See item 1 above. 

6. Takings Implication Assessment (E.O. 

12630) 

Under the criteria in E.O. 12630, this 

proposed rule would not have 

significant takings implications. This 

proposed rule would apply to Federal 

oil, Federal gas, Federal coal, and Indian 

coal leases only. This proposed rule 

would not be a governmental action 

capable of interference with 

constitutionally protected property 

rights. This proposed rule does not 

require a Takings Implication 

Assessment. 

7. Federalism (E.O. 13132) 

Under the criteria in E.O. 13132, this 

proposed rule would not have sufficient 

federalism implications to warrant the 

preparation of a Federalism Assessment. 

The management of Federal oil leases, 

Federal gas leases, and Federal and 

Indian coal leases is the responsibility 

of the Secretary of the Interior. This 

proposed rule would not impose 

administrative costs on States or local 

governments. Therefore, this proposed 

rule would not require a Federalism 

Assessment. 

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

This proposed rule would comply 

with the requirements of E.O. 12988, for 

the reasons we outline in the following 

paragraphs. 

The proposed rule would meet the 

criteria of section 3(a), which requires 

that we write and review all regulations 

to eliminate errors and ambiguity in 

order to minimize litigation. 

The proposed rule would meet the 

criteria of section 3(b)(2), which 

requires that we write all regulations in 

clear language with clear legal 

standards. 

9. Consultation with Indian Tribes (E.O. 

13175) 

Under the criteria in E.O. 13175, we 

evaluated this proposed rule and 

determined it would have potential 

effects on federally recognized Indian 

tribes. Specifically, this rule would 

change the valuation methodology for 

coal produced from Indian leases as 

discussed above. Accordingly: 

(a) We consulted with the affected 

tribes on a government-to-government 

basis. 

(b) We will fully consider tribal views 

in the final rule. 

10. Paperwork Reduction Act 

This proposed rule also refers to, but 

does not change, the information 

collection requirements that OMB 

already approved under OMB Control 

Numbers 1012–0004, 1012–0005, and 

1012–0010. Since the proposed rule is 

reorganizing our current regulations, 

please refer to the Derivations Table in 

Section III for specifics. The 

corresponding information collection 

burden tables will be updated during 

their normal renewal cycle. See 5 CFR 

1320.4(a)(2). 

11. National Environmental Policy Act 

This proposed rule would not 

constitute a major Federal action 

significantly affecting the quality of the 

human environment. A detailed 

statement under the National 

Environmental Policy Act of 1969 

(NEPA) is not required because this rule 

is categorically excluded under: ‘‘(i) 

Policies, directives, regulations, and 

guidelines: that are of an administrative, 

financial, legal, technical, or procedural 

nature.’’ See 43 CFR 46.210(i) and the 

DOI Departmental Manual, part 516, 

section 15.4.D. We also have determined 

that this rule is not involved in any of 

the extraordinary circumstances listed 

in 43 CFR 46.215 that would require 

further analysis under NEPA. The 

procedural changes resulting from these 

amendments would have no 

consequences with respect to the 

physical environment. This proposed 

rule would not alter in any material way 

natural resource exploration, 

production, or transportation. 

12. Data Quality Act 

In developing this proposed rule, we 

did not conduct or use a study, 

experiment, or survey requiring peer 

review under the Data Quality Act (Pub. 

L. 106–554), also known as the 

Information Quality Act. The 

Department of the Interior has issued 

guidance regarding the quality of 

information that it relies on for 

regulatory decisions. This guidance is 

available on DOI’s Web site at 

www.doi.gov/ocio/iq.html. 

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

13211) 

This proposed rule would not be a 

significant energy action under the 

definition in E.O. 13211, and, therefore, 

would not require a Statement of Energy 

Effects. 

14. Clarity of this Regulation 

Executive Orders 12866 and 12988 

and the Presidential Memorandum of 

June 1, 1998, require us to write all rules 

in Plain Language. This means that each 

rule that we publish must: (a) Have 

logical organization; (b) use the active 

voice to address readers directly; (c) use 

clear language rather than jargon; (d) use 

short sections and sentences; and (e) use 

lists and tables wherever possible. 

If you feel that we have not met these 

requirements, send your comments to 

armand.southall@onrr.gov. To better 

help us revise the rule, make your 

comments as specific as possible. For 

example, you should tell us the 

numbers of the sections or paragraphs 

that you think we wrote unclearly, 

which sections or sentences are too 

long, the sections where you feel lists or 

tables would be useful, etc. 

15. Public Availability of Comments 

Before including your address, phone 

number, email address, or other 

personal identifying information in your 

comment, you should be aware that 

your entire comment—including your 

personal identifying information—may 

be made publicly available at any time. 

While you can ask us, in your comment, 

to withhold your personal identifying 

information from public view, we 

cannot guarantee that we will be able to 

do so. 

List of Subjects in 30 CFR Parts 1202 

and 1206 

Coal, Continental shelf, Government 

contracts, Indian lands, Mineral 

royalties, Natural gas, Petroleum, Public 

lands—mineral resources, Reporting 

and recordkeeping requirements. 

Dated: December 18, 2014. 

Kris Sarri, 

Principal Deputy Assistant Secretary for 

Policy, Management and Budget. 

Authority and Issuance 

For the reasons stated in the 

preamble, the Office of Natural 

Resources Revenue proposes to amend 

30 CFR parts 1202 and 1206 as set forth 

below: 

PART 1202—ROYALTIES 

■ 1. The authority citation for part 1202 

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 B—Oil, Gas, and OCS Sulfur, 

General 

■ 2. In § 1202.51,revise paragraph (b) to 

read as follows: 

§ 1202.51 Scope and definitions. 

* * * * * 

(b) The de ́finitions in § 1206.20 of this 

chapter are applicable to subparts B, C, 

D, and J of this part. 


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Subpart F—Coal 

■ 3. Add § 1202.251 to subpart F to read 

as follows: 

§ 1202.251 What coal is subject to 

royalties? 

(a) All coal (except coal unavoidably 

lost as determined by BLM under 43 

CFR part 3400) from a Federal or Indian 

lease is subject to royalty. This includes 

coal used, sold, or otherwise disposed of 

by you on or off the lease. 

(b) If you receive compensation for 

unavoidably lost coal through insurance 

coverage or other arrangements, you 

must pay royalties at the rate specified 

in the lease on the amount of 

compensation you receive for the coal. 

No royalty is due on insurance 

compensation you received for other 

losses. 

(c) If you rework waste piles or slurry 

ponds to recover coal, you must pay 

royalty at the rate specified in the lease 

at the time you use, sell, or otherwise 

finally dispose of the recovered coal. 

(1) The applicable royalty rate 

depends on the production method you 

used to initially mine the coal contained 

in the waste pile or slurry pond (i.e., 

underground mining method or surface 

mining method). 

(2) You must allocate coal in waste 

pits or slurry ponds you initially mined 

from Federal or Indian leases to those 

Federal or Indian leases regardless of 

whether it is stored on Federal or Indian 

lands. 

(3)You must maintain accurate 

records demonstrating how to allocate 

the coal in the waste pit or slurry pond 

to each individual Federal or Indian 

coal lease. 

PART 1206—PRODUCT VALUATION 

■ 4. 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. 

■ 5. Revise subpart A to read as follows: 

Subpart A—General Provisions and 

Definitions 

Sec. 

1206.10 Has the Office of Management and 

Budget (OMB) approved the information 

collection requirements in this part? 

1206.20 What definitions apply to this part? 

Subpart A—General Provisions 

§ 1206.10 Has the Office of Management 

and Budget (OMB) approved the 

information collection requirements in this 

part? 

OMB has approved the information 

collection requirement contained in this 

part under 44 U.S.C. 3501 et seq. See 30 

CFR part 1210 for details concerning the 

estimated reporting burden and how to 

comment on the accuracy of the burden 

estimate. 

§ 1206.20 What definitions apply to this 

part? 

Ad valorem lease means a lease where 

the royalty due to the lessor is based 

upon a percentage of the amount or 

value of the coal. 

Affiliate means a person who 

controls, is controlled by, or is under 

common control with another person. 

For purposes of this subpart: 

(1) Ownership or common ownership 

of more than 50 percent of the voting 

securities, or instruments of ownership, 

or other forms of ownership, of another 

person constitutes control. Ownership 

of less than 10 percent constitutes a 

presumption of noncontrol that ONRR 

may rebut. 

(2) If there is ownership or common 

ownership of 10 through 50 percent of 

the voting securities or instruments of 

ownership, or other forms of ownership, 

of another person, ONRR will consider 

the following factors to determine if 

there is control under the circumstances 

of a particular case: 

(i) The extent to which there are 

common officers or directors; 

(ii) With respect to the voting 

securities, or instruments of ownership, 

or other forms of ownership: the 

percentage of ownership or common 

ownership, the relative percentage of 

ownership or common ownership 

compared to the percentage(s) of 

ownership by other persons, if a person 

is the greatest single owner, or if there 

is an opposing voting bloc of greater 

ownership; 

(iii) Operation of a lease, plant, 

pipeline, or other facility; 

(iv) The extent of participation by 

other owners in operations and day-today management of a lease, plant, or 

other facility; and 

(v) Other evidence of power to 

exercise control over or common control 

with another person. 

(3) Regardless of any percentage of 

ownership or common ownership, 

relatives, either by blood or marriage, 

are affiliates. 

ANS means Alaska North Slope 

(ANS). 

Area means a geographic region at 

least as large as the limits of an oil and/ 

or gas field, in which oil and/or gas 

lease products have similar quality and 

economic characteristics. Area 

boundaries are not officially designated 

and the areas are not necessarily named. 

Arm’s-length contract means a 

contract or agreement between 

independent persons who are not 

affiliates and who have opposing 

economic interests regarding that 

contract. To be considered arm’s length 

for any production month, a contract 

must satisfy this definition for that 

month, as well as when the contract was 

executed. 

Audit means an examination, 

conducted under the generally accepted 

Governmental Auditing Standards, of 

royalty reporting and payment 

compliance activities of lessees, 

designees or other persons who pay 

royalties, rents, or bonuses on Federal 

leases or Indian leases. 

BIA means the Bureau of Indian 

Affairs, Department of the Interior. 

BLM means the Bureau of Land 

Management, Department of the 

Interior. 

BOEM means the Bureau of Ocean 

Energy Management, Department of the 

Interior. 

BSEE means the Bureau of Safety and 

Environmental Enforcement, 

Department of the Interior. 

Coal means coal of all ranks from 

lignite through anthracite. 

Coal cooperative means an entity 

organized to provide coal or coal-related 

services to the entity’s members (who 

may also be owners of the entity), 

partners, and others. The entity’s 

members are commonly electric power 

generation companies, electric utilities, 

and electric generation and transmission 

cooperatives. The entity may operate as 

a coal lessee, operator, payor, or affiliate 

of these, and may or may not be 

organized to make a profit. 

Coal washing means any treatment to 

remove impurities from coal. Coal 

washing may include, but is not limited 

to, operations such as flotation, air, 

water, or heavy media separation; 

drying; and related handling (or 

combination thereof). 

Compression means the process of 

raising the pressure of gas. 

Condensate means liquid 

hydrocarbons (normally exceeding 40 

degrees of API gravity) recovered at the 

surface without processing. Condensate 

is the mixture of liquid hydrocarbons 

resulting from condensation of 

petroleum hydrocarbons existing 

initially in a gaseous phase in an 

underground reservoir. 

Constraint means a reduction in, or 

elimination of, gas flow, deliveries or 

sales required by the delivery system. 

Contract means any oral or written 

agreement, including amendments or 

revisions, between two or more persons, 

that is enforceable by law and that with 

due consideration creates an obligation. 


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Designee means the person the lessee 

designates to report and pay the lessee’s 

royalties for a lease. 

Exchange agreement means an 

agreement where one person agrees to 

deliver oil to another person at a 

specified location in exchange for oil 

deliveries at another location. Exchange 

agreements may or may not specify 

prices for the oil involved. They 

frequently specify dollar amounts 

reflecting location, quality, or other 

differentials. Exchange agreements 

include buy/sell agreements, which 

specify prices to be paid at each 

exchange point and may appear to be 

two separate sales within the same 

agreement. Examples of other types of 

exchange agreements include, but are 

not limited to, exchanges of produced 

oil for specific types of crude oil (e.g., 

West Texas Intermediate); exchanges of 

produced oil for other crude oil at other 

locations (Location Trades); exchanges 

of produced oil for other grades of oil 

(Grade Trades); and multi-party 

exchanges. 

FERC means Federal Energy 

Regulatory Commission. 

Field means a geographic region 

situated over one or more subsurface oil 

and gas reservoirs and encompassing at 

least the outermost boundaries of all oil 

and gas accumulations known within 

those reservoirs, vertically projected to 

the land surface. State oil and gas 

regulatory agencies usually name 

onshore fields and designate their 

official boundaries. BOEM names and 

designates boundaries of OCS fields. 

Gas means any fluid, either 

combustible or noncombustible, 

hydrocarbon or nonhydrocarbon, which 

is extracted from a reservoir and which 

has neither independent shape nor 

volume, but tends to expand 

indefinitely. It is a substance that exists 

in a gaseous or rarefied state under 

standard temperature and pressure 

conditions. 

Gas plant products means separate 

marketable elements, compounds, or 

mixtures, whether in liquid, gaseous, or 

solid form, resulting from processing 

gas, excluding residue gas. 

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 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. 

Geographic region means, for Federal 

gas, an area at least as large as the 

defined limits of an oil and or gas field 

in which oil and/or gas lease products 

have similar quality and economic 

characteristics. 

Gross proceeds means the total 

monies and other consideration 

accruing for the disposition of any of the 

following: 

(1) Oil. Gross proceeds also include, 

but are not limited to, the following 

examples: 

(i) Payments for services such as 

dehydration, marketing, measurement, 

or gathering which the lessee must 

perform at no cost to the Federal 

Government; 

(ii) The value of services, such as salt 

water disposal, that the producer 

normally performs but that the buyer 

performs on the producer’s behalf; 

(iii) Reimbursements for harboring or 

terminalling fees, royalties, and any 

other reimbursements; 

(iv) Tax reimbursements, even though 

the Federal royalty interest may be 

exempt from taxation; 

(v) Payments made to reduce or buy 

down the purchase price of oil 

produced in later periods, by allocating 

such payments over the production 

whose price the payment reduces and 

including the allocated amounts as 

proceeds for the production as it occurs; 

and 

(vi) Monies and all other 

consideration to which a seller is 

contractually or legally entitled but does 

not seek to collect through reasonable 

efforts; 

(2) Gas, residue gas, and gas plant 

products. Gross proceeds also include, 

but are not limited to, the following 

examples: 

(i) Payments for services such as 

dehydration, marketing, measurement, 

or gathering that the lessee must 

perform at no cost to the Federal 

Government; 

(ii) Reimbursements for royalties, fees, 

and any other reimbursements; 

(iii) Tax reimbursements, even though 

the Federal royalty interest may be 

exempt from taxation; and 

(iv) Monies and all other 

consideration to which a seller is 

contractually or legally entitled, but 

does not seek to collect through 

reasonable efforts; or 

(3) Coal. Gross proceeds also include, 

but are not limited to, the following 

examples: 

(i) Payments for services such as 

crushing, sizing, screening, storing, 

mixing, loading, treatment with 

substances including chemicals or oil, 

and other preparation of the coal that 

the lessee must perform at no cost to the 

Federal Government or Indian lessor; 

(ii) Reimbursements for royalties, fees, 

and any other reimbursements; 

(iii) Tax reimbursements even though 

the Federal or Indian royalty interest 

may be exempt from taxation; and 

(iv) Monies and all other 

consideration to which a seller is 

contractually or legally entitled, but 

does not seek to collect through 

reasonable efforts. 

Index means: 

(1) For gas, the calculated composite 

price ($/MMBtu) of spot market sales a 

publication that meets ONRRestablished criteria for acceptability at 

the index pricing point publishes; or 

(2) For oil, the calculated composite 

price ($/barrel) of spot market sales a 

publication that meets ONRRestablished criteria for acceptability at 

the index pricing point publishes. 

Index pricing point means any point 

on a pipeline for which there is an 

index, which ONRR-approved 

publications may refer to as a trading 

location. 

Index zone means a field or an area 

with an active spot market and 

published indices applicable to that 

field or an area that is acceptable to 

ONRR under § 1206.141(d)(1). 

Indian Tribe means any Indian Tribe, 

band, nation, pueblo, community, 

rancheria, colony, or other group of 

Indians for which any minerals or 

interest in minerals is held in trust by 

the United States or that is subject to 

Federal restriction against alienation. 

Individual Indian mineral owner 

means any Indian for whom minerals or 

an interest in minerals is held in trust 

by the United States or who holds title 

subject to Federal restriction against 

alienation. 

Keepwhole contract means a 

processing agreement under which the 

processor delivers to the lessee a 

quantity of gas after processing 

equivalent to the quantity of gas the 

processor received from the lessee prior 

to processing, normally based on heat 

content, less gas used as plant fuel and 

gas unaccounted for and/or lost. This 

includes but is not limited to 

agreements under which the processor 

retains all NGLs it recovered from the 

lessee’s gas. 

Lease means any contract, profitsharing arrangement, joint venture, or 

other agreement issued or approved by 

the United States under any mineral 

leasing law, including the Indian 

Mineral Development Act, 25 U.S.C. 

2101–2108, that authorizes exploration 

for, extraction of, or removal of lease 

products, or the geographical area 

covered by that authorization, 

whichever is required by the context. 

Lease products mean any leased 

minerals, attributable to, originating 


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from, or allocated to a lease or produced 

in association with a lease. 

Lessee means any person to whom the 

United States, an Indian tribe, and/or 

individual Indian mineral owner issues 

a lease, and any person who has been 

assigned all or a part of record title, 

operating rights, or an obligation to 

make royalty or other payments 

required by the lease. This includes: 

(1) Any person who has an interest in 

a lease; and 

(2) In the case of leases for Indian coal 

or Federal coal, an operator, payor, or 

other person with no lease interest who 

makes royalty payments on the lessee’s 

behalf. 

Like quality means similar chemical 

and physical characteristics. 

Location differential means an 

amount paid or received (whether in 

money or in barrels of oil) under an 

exchange agreement that results from 

differences in location between oil 

delivered in exchange and oil received 

in the exchange. A location differential 

may represent all or part of the 

difference between the price received 

for oil delivered and the price paid for 

oil received under a buy/sell exchange 

agreement. 

Market center means a major point 

ONRR recognizes for oil sales, refining, 

or transshipment. Market centers 

generally are locations where ONRRapproved publications publish oil spot 

prices. 

Marketable condition means lease 

products which are sufficiently free 

from impurities and otherwise in a 

condition that they will be accepted by 

a purchaser under a sales contract 

typical for the field or area for Federal 

oil and gas, and region for Federal and 

Indian coal. 

Mine means an underground or 

surface excavation or series of 

excavations and the surface or 

underground support facilities that 

contribute directly or indirectly to 

mining, production, preparation, and 

handling of lease products. 

Misconduct means 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. 

Net output means the quantity of: 

(1) Residue gas and each gas plant 

product that a processing plant 

produces; or 

(2) The quantity of washed coal that 

a coal wash plant produces. 

Netting means reducing the reported 

sales value to account for an allowance 

instead of reporting the allowance as a 

separate entry on Form ONRR–2014 or 

Form ONRR–4430. 

NGLs means natural gas liquids. 

NYMEX price means the average of 

the New York Mercantile Exchange 

(NYMEX) settlement prices for light 

sweet crude oil delivered at Cushing, 

Oklahoma, calculated as follows: 

(1) Sum the prices published for each 

day during the calendar month of 

production (excluding weekends and 

holidays) for oil to be delivered in the 

prompt month corresponding to each 

such day; and 

(2) Divide the sum by the number of 

days on which those prices are 

published (excluding weekends and 

holidays). 

Oil means a mixture of hydrocarbons 

that existed in the liquid phase in 

natural underground reservoirs, remains 

liquid at atmospheric pressure after 

passing through surface separating 

facilities, and is marketed or used as a 

liquid. Condensate recovered in lease 

separators or field facilities is oil. 

ONRR means the Office of Natural 

Resources Revenue, Department of the 

Interior. 

ONRR-approved commercial price 

bulletin means a publication ONRR 

approves for determining NGLs prices. 

ONRR-approved publication means: 

(1) For oil, a publication ONRR 

approves for determining ANS spot 

prices or WTI differentials; or 

(2) For gas, a publication ONRR 

approves for determining index pricing 

points. 

Outer Continental Shelf (OCS) means 

all submerged lands lying seaward and 

outside of the area of lands beneath 

navigable waters as defined in Section 

2 of the Submerged Lands Act (43 

U.S.C. 1301) and of which the subsoil 

and seabed appertain to the United 

States and are subject to its jurisdiction 

and control. 

Payor means any person who reports 

and pays royalties under a lease, 

regardless of whether that person also is 

a lessee. 

Person means any individual, firm, 

corporation, association, partnership, 

consortium, or joint venture (when 

established as a separate entity). 

Processing means any process 

designed to remove elements or 

compounds (hydrocarbon and 

nonhydrocarbon) from gas, including 

absorption, adsorption, or refrigeration. 

Field processes which normally take 

place on or near the lease, such as 

natural pressure reduction, mechanical 

separation, heating, cooling, 

dehydration, and compression, are not 

considered processing. The changing of 

pressures and/or temperatures in a 

reservoir is not considered processing. 

The use of a Joules-Thompson (JT) unit 

to remove NGLs from gas is considered 

processing regardless of where the JT 

unit is located provided that you market 

the NGLs as NGLs. 

Processing allowance means a 

deduction in determining royalty value 

for the reasonable, actual costs the 

lessee incurs for processing gas. 

Prompt month means the nearest 

month of delivery for which NYMEX 

futures prices are published during the 

trading month. 

Quality differential means an amount 

paid or received under an exchange 

agreement (whether in money or in 

barrels of oil) that results from 

differences in API gravity, sulfur 

content, viscosity, metals content, and 

other quality factors between oil 

delivered and oil received in the 

exchange. A quality differential may 

represent all or part of the difference 

between the price received for oil 

delivered and the price paid for oil 

received under a buy/sell agreement. 

Region for coal means the eight 

Federal coal production regions, which 

the Bureau of Land Management 

designates as follows: Denver-Raton 

Mesa Region, Fort Union Region, Green 

River-Hams Fork Region, Powder River 

Region, San Juan River Region, 

Southern Appalachian Region, UintaSouthwestern Utah Region, and Western 

Interior Region. See 44 FR 65197 (1979). 

Residue gas means that hydrocarbon 

gas consisting principally of methane 

resulting from processing gas. 

Rocky Mountain Region means the 

States of Colorado, Montana, North 

Dakota, South Dakota, Utah, and 

Wyoming, except for those portions of 

the San Juan Basin and other oilproducing fields in the ‘‘Four Corners’’ 

area that lie within Colorado and Utah. 

Roll means an adjustment to the 

NYMEX price that is calculated as 

follows: Roll = .6667 × (P0¥P1) + .3333 

× (P0¥P2), where: P0 = the average of the 

daily NYMEX settlement prices for 

deliveries during the prompt month that 

is the same as the month of production, 

as published for each day during the 

trading month for which the month of 

production is the prompt month; P1 = 

the average of the daily NYMEX 

settlement prices for deliveries during 

the month following the month of 

production, published for each day 

during the trading month for which the 

month of production is the prompt 

month; and P2 = the average of the daily 

NYMEX settlement prices for deliveries 

during the second month following the 

month of production, as published for 

each day during the trading month for 

which the month of production is the 

prompt month. Calculate the average of 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
646 Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 

the daily NYMEX settlement prices 

using only the days on which such 

prices are published (excluding 

weekends and holidays). 

(1) Example 1. Prices in Out Months are 

Lower Going Forward: The month of 

production for which you must determine 

royalty value is December. December was the 

prompt month (for year 2011) from October 

21 through November 18. January was the 

first month following the month of 

production, and February was the second 

month following the month of production. P0

therefore is the average of the daily NYMEX 

settlement prices for deliveries during 

December published for each business day 

between October 21 and November 18. P1 is 

the average of the daily NYMEX settlement 

prices for deliveries during January 

published for each business day between 

October 21 and November 18. P2 is the 

average of the daily NYMEX settlement 

prices for deliveries during February 

published for each business day between 

October 21 and November 18. In this 

example, assume that P0 = $95.08 per bbl, P1

= $95.03 per bbl, and P2 = $94.93 per bbl. In 

this example (a declining market), Roll = 

.6667 × ($95.08¥$95.03) + .3333 × 

($95.08¥$94.93) = $0.03 + $0.05 = $0.08. 

You add this number to the NYMEX price. 

(2) Example 2. Prices in Out Months are 

Higher Going Forward: The month of 

production for which you must determine 

royalty value is November. November was 

the prompt month (for year 2012) from 

September 21 through October 22. December 

was the first month following the month of 

production, and January was the second 

month following the month of production. P0

therefore is the average of the daily NYMEX 

settlement prices for deliveries during 

November published for each business day 

between September 21 and October 22. P1 is 

the average of the daily NYMEX settlement 

prices for deliveries during December 

published for each business day between 

September 21 and October 22. P2 is the 

average of the daily NYMEX settlement 

prices for deliveries during January 

published for each business day between 

September 21 and October 22. In this 

example, assume that P0 = $91.28 per bbl, P1

= $91.65 per bbl, and P2 = $92.10 per bbl. In 

this example (a rising market), Roll = .6667 

× ($91.28¥$91.65) + .3333 × 

($91.28¥$92.10) = (¥$0.25) + (¥$0.27) = 

(¥$0.52). You add this negative number to 

the NYMEX price (effectively a subtraction 

from the NYMEX price). 

Sale means a contract between two 

persons where: 

(1) The seller unconditionally 

transfers title to the oil, gas, gas plant 

product, or coal to the buyer and does 

not retain any related rights such as the 

right to buy back similar quantities of 

oil, gas, gas plant product, or coal from 

the buyer elsewhere; 

(2) The buyer pays money or other 

consideration for the oil, gas, gas plant 

product, or coal; and 

(3) The parties’ intent is for a sale of 

the oil, gas, gas plant product, or coal 

to occur. 

Section 6 lease means an OCS lease 

subject to section 6 of the Outer 

Continental Shelf Lands Act, as 

amended, 43 U.S.C. 1335. 

Short tons means 2000 pounds. 

Spot price means the price under a 

spot sales contract where: 

(1) A seller agrees to sell to a buyer 

a specified amount of oil at a specified 

price over a specified period of short 

duration; 

(2) No cancellation notice is required 

to terminate the sales agreement; and 

(3) There is no obligation or implied 

intent to continue to sell in subsequent 

periods. 

Tonnage means tons of coal measured 

in short tons. 

Trading month means the period 

extending from the second business day 

before the 25th day of the second 

calendar month preceding the delivery 

month (or, if the 25th day of that month 

is a non-business day, the second 

business day before the last business 

day preceding the 25th day of that 

month) through the third business day 

before the 25th day of the calendar 

month preceding the delivery month 

(or, if the 25th day of that month is a 

non-business day, the third business 

day before the last business day 

preceding the 25th day of that month), 

unless the NYMEX publishes a different 

definition or different dates on its 

official Web site, www.nymex.com, in 

which case the NYMEX definition will 

apply. 

Transportation allowance means a 

deduction in determining royalty value 

for the reasonable, actual costs the 

lessee incurs for moving: 

(1) Oil to a point of sale or delivery 

off the lease, unit area, or communitized 

area. The transportation allowance does 

not include gathering costs; or 

(2) Unprocessed gas, residue gas, or 

gas plant products to a point of sale or 

delivery off the lease, unit area, or 

communitized area, or away from a 

processing plant. The transportation 

allowance does not include gathering 

costs; or 

(3) Coal to a point of sale remote from 

both the lease and mine or wash plant. 

Washing allowance means a 

deduction in determining royalty value 

for the reasonable, actual costs the 

lessee incurs for coal washing. 

WTI differential means the average of 

the daily mean differentials for location 

and quality between a grade of crude oil 

at a market center and West Texas 

Intermediate (WTI) crude oil at Cushing 

published for each day for which price 

publications perform surveys for 

deliveries during the production month, 

calculated over the number of days on 

which those differentials are published 

(excluding weekends and holidays). 

Calculate the daily mean differentials by 

averaging the daily high and low 

differentials for the month in the 

selected publication. Use only the days 

and corresponding differentials for 

which such differentials are published. 

■ 6. Revise subpart C to read as follows: 

Subpart C—Federal Oil 

Sec. 

1206.100 What is the purpose of this 

subpart? 

1206.101 How do I calculate royalty value 

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

arm’s-length contract? 

1206.102 How do I value oil that is not sold 

under an arm’s-length contract? 

1206.103 What publications does ONRR 

approve? 

1206.104 How will ONRR determine if my 

royalty payments are correct? 

1206.105 How will ONRR determine the 

value of my oil for royalty purposes? 

1206.106 What records must I keep to 

support my calculations of value under 

this subpart? 

1206.107 What are my responsibilities to 

place production into marketable 

condition and to market production? 

1206.108 How do I request a value 

determination? 

1206.109 Does ONRR protect information I 

provide? 

1206.110 What general transportation 

allowance requirements apply to me? 

1206.111 How do I determine a 

transportation allowance if I have an 

arm’s-length transportation contract? 

1206.112 How do I determine a 

transportation allowance if I do not have 

an arm’s-length transportation contract? 

1206.113 What adjustments and 

transportation allowances apply when I 

value oil production from my lease using 

NYMEX prices or ANS spot prices? 

1206.114 How will ONRR identify market 

centers? 

1206.115 What are my reporting 

requirements under an arm’s-length 

transportation contract? 

1206.116 What are my reporting 

requirements under a non-arm’s-length 

transportation contract? 

1206.117 What interest and penalties apply 

if I improperly report a transportation 

allowance? 

1206.118 What reporting adjustments must 

I make for transportation allowances? 

1206.119 How do I determine royalty 

quantity and quality? 

Subpart C—Federal Oil 

§ 1206.100 What is the purpose of this 

subpart? 

(a) This subpart applies to all oil 

produced from Federal oil and gas 

leases onshore and on the OCS. It 

explains how you as a lessee must 

calculate the value of production for 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 647 

royalty purposes consistent with 

mineral leasing laws, other applicable 

laws, and lease terms. 

(b) If you are a designee and if you 

dispose of production on behalf of a 

lessee, the terms ‘‘you’’ and ‘‘your’’ in 

this subpart refer to you and not to the 

lessee. In this circumstance, you must 

determine and report royalty value for 

the lessee’s oil by applying the rules in 

this subpart to your disposition of the 

lessee’s oil. 

(c) If you are a designee and only 

report for a lessee and do not dispose of 

the lessee’s production, references to 

‘‘you’’ and ‘‘your’’ in this subpart refer 

to the lessee and not the designee. In 

this circumstance, you as a designee 

must determine and report royalty value 

for the lessee’s oil by applying the rules 

in this subpart to the lessee’s 

disposition of its oil. 

(d) If the regulations in this subpart 

are inconsistent with: 

(1) A Federal statute; 

(2) A settlement agreement between 

the United States and a lessee resulting 

from administrative or judicial 

litigation; 

(3) A written agreement between the 

lessee and the ONRR Director 

establishing a method to determine the 

value of production from any lease that 

ONRR expects at least would 

approximate the value established 

under this subpart; or 

(4) An express provision of an oil and 

gas lease subject to this subpart, then 

the statute, settlement agreement, 

written agreement, or lease provision 

will govern to the extent of the 

inconsistency. 

(e) ONRR may audit, monitor, or 

review and adjust all royalty payments. 

§ 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 ONRR decides to value 

your oil under § 1206.105. You must use 

this paragraph (a) to value oil when: 

(1) You sell under an arm’s-length 

sales contract; or 

(2) You sell or transfer to your affiliate 

or another person under a non-arm’slength contract and that affiliate or 

person, or another affiliate of either of 

them, then sells the oil under an arm’slength contract, unless you exercise the 

option provided in paragraph (c)(2)(i) of 

this section. 

(b) If you have multiple arm’s-length 

contracts to sell oil produced from a 

lease that is valued under paragraph (a) 

of this section, the value of the oil is the 

volume-weighted average of the values 

established under this section for each 

contract for the sale of oil produced 

from that lease. 

(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) you or your affiliate sell(s) 

the oil received in the exchange(s) 

under an arm’s-length contract, then 

you may use either § 1206.101(a) 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 

and ONRR may decide your value under 

§ 1206.105. 

(i) If you use § 1206.101(a), 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, 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 decide your 

value under § 1206.105. You may not 

otherwise use the price or differential 

specified in an arm’s-length exchange 

agreement to value your production. 

(ii) When you elect under 

§ 1206.101(c)(1) to use § 1206.101(a) or 

§ 1206.102, you must make the same 

election for all of your production from 

the same unit, communitization 

agreement, or lease (if the lease is not 

part of a unit or communitization 

agreement) sold under arm’s-length 

contracts following arm’s-length 

exchange agreements. You may not 

change your election more often than 

once every 2 years. 

(2)(i) If you sell or transfer your oil 

production to your affiliate and that 

affiliate or another affiliate then sells the 

oil under an arm’s-length contract, you 

may use either § 1206.101(a) or 

§ 1206.102 to value your production for 

royalty purposes. 

(ii) When you elect under 

§ 1206.101(c)(2)(i) to use § 1206.101(a) 

or § 1206.102, you must make the same 

election for all of your production from 

the same unit, communitization 

agreement, or lease (if the lease is not 

part of a unit or communitization 

agreement) that your affiliates resell at 

arm’s-length. You may not change your 

election more often than once every 2 

years. 

§ 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, unless ONRR decides to value 

your oil under 1206.105. 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 

approval. 

(a) Production from leases in 

California or Alaska. Value is the 

average of the daily mean ANS spot 

prices published in any ONRR-approved 

publication during the trading month 

most concurrent with the production 

month. For example, if the production 

month is June, calculate the average of 

the daily mean prices using the daily 

ANS spot prices published in the 

ONRR-approved publication for all the 

business days in June. 

(1) To calculate the daily mean spot 

price, you must average the daily high 

and low prices for the month in the 

selected publication. 

(2) You must use only the days and 

corresponding spot prices for which 

such prices are published. 

(3) You must adjust the value for 

applicable location and quality 

differentials, and you may adjust it for 

transportation costs, under § 1206.111. 

(4) After you select an ONRRapproved publication, you may not 

select a different publication more often 

than once every 2 years, unless the 

publication you use is no longer 

published or ONRR revokes its approval 

of the publication. If you must change 

publications, you must begin a new 2- 

year period. 

(b) Production from leases in the 

Rocky Mountain Region. This paragraph 

provides methods and options for 

valuing your production under different 

factual situations. You must 

consistently apply paragraph (b)(2) or 

(3) of this section to value all of your 

production from the same unit, 

communitization agreement, or lease (if 

the lease or a portion of the lease is not 

part of a unit or communitization 

agreement) that you cannot value under 

§ 1206.101 or that you elect under 

§ 1206.101(c)(1) to value under this 

section. 

(1) You may elect to value your oil 

under either paragraph (b)(2) or (3) of 

this section. After you select either 

paragraph (b)(2) or (3) of this section, 

you may not change to the other method 

more often than once every 2 years, 

unless the method you have been using 

is no longer applicable and you must 

apply the other paragraph. If you change 


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methods, you must begin a new 2-year 

period. 

(2) Value is the volume-weighted 

average of the gross proceeds accruing 

to the seller under your or your 

affiliate’s arm’s-length contracts for the 

purchase or sale of production from the 

field or area during the production 

month. 

(i) The total volume purchased or sold 

under those contracts must exceed 50 

percent of your and your affiliate’s 

production from both Federal and nonFederal leases in the same field or area 

during that month. 

(ii) Before calculating the volumeweighted average, you must normalize 

the quality of the oil in your or your 

affiliate’s arm’s-length purchases or 

sales to the same gravity as that of the 

oil produced from the lease. 

(3) Value is the NYMEX price 

(without the roll), adjusted for 

applicable location and quality 

differentials and transportation costs 

under § 1206.113. 

(4) If you demonstrate to ONRR’s 

satisfaction that paragraphs (b)(2) 

through (3) of this section result in an 

unreasonable value for your production 

as a result of circumstances regarding 

that production, the ONRR Director may 

establish an alternative valuation 

method. 

(c) Production from leases not located 

in California, Alaska, or the Rocky 

Mountain Region. (1) Value is the 

NYMEX price, plus the roll, adjusted for 

applicable location and quality 

differentials and transportation costs 

under § 1206.113. 

(2) If the ONRR Director determines 

that use of the roll no longer reflects 

prevailing industry practice in crude oil 

sales contracts or that the most common 

formula used by industry to calculate 

the roll changes, ONRR may terminate 

or modify use of the roll under 

paragraph (c)(1) of this section at the 

end of each 2-year period [EFFECTIVE 

DATE OF THE FINAL RULE], through 

notice published in the Federal Register 

not later than 60 days before the end of 

the 2-year period. ONRR will explain 

the rationale for terminating or 

modifying the use of the roll in this 

notice. 

(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 decide to 

value your oil under § 1206.105. 

(e) Production delivered to your 

refinery and the NYMEX price or ANS 

spot price is an 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 decide 

to value under § 1206.105. 

§ 1206.103 What publications does ONRR 

approve? 

(a) ONRR periodically will publish to 

www.onrr.gov a list of ONRR-approved 

publications for the NYMEX price and 

ANS spot price based on certain criteria 

including, but not limited to: 

(1) Publications buyers and sellers 

frequently use; 

(2) Publications frequently mentioned 

in purchase or sales contracts; 

(3) Publications that use adequate 

survey techniques, including 

development of estimates based on daily 

surveys of buyers and sellers of crude 

oil, and, for ANS spot prices, buyers and 

sellers of ANS crude oil; and 

(4) Publications independent from 

ONRR, other lessors, and lessees. 

(b) Any publication may petition 

ONRR to be added to the list of 

acceptable publications. 

(c) ONRR will specify the tables you 

must use in the acceptable publications. 

(d) ONRR may revoke its approval of 

a particular publication if it determines 

that the prices or differentials published 

in the publication do not accurately 

represent NYMEX prices or differentials 

or ANS spot market prices or 

differentials. 

§ 1206.104 How will ONRR determine if my 

royalty payments are correct? 

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

audit the royalties you report, and, if 

ONRR determines that your reported 

value is inconsistent with the 

requirements of this subpart, ONRR may 

direct you to use a different measure of 

royalty value or decide your value 

under § 1206.105. 

(2) If ONRR directs you to use a 

different royalty value, you must either 

pay any additional royalties due, plus 

late payment interest calculated under 

§§ 1218.54 and 1218.102 of this chapter) 

or report a credit for, or request a refund 

of, any overpaid royalties. 

(b) When the provisions in this 

subpart refer to gross proceeds, in 

conducting reviews and audits, ONRR 

will examine if your or your affiliate’s 

contract reflects the total consideration 

actually transferred, either directly or 

indirectly, from the buyer to you or your 

affiliate for the oil. If ONRR determines 

that a contract does not reflect the total 

consideration, ONRR may decide your 

value under § 1206.105. 

(c) ONRR may decide your value 

under § 1206.105 if ONRR determines 

that the gross proceeds accruing to you 

or your affiliate under a contract do not 

reflect reasonable consideration 

because: 

(1) There is misconduct by or between 

the contracting parties; 

(2) You have breached your duty to 

market the oil for the mutual benefit of 

yourself and the lessor by selling your 

oil at a value that is unreasonably low. 

ONRR may consider a sales price to be 

unreasonably low if it is 10 percent less 

than the lowest reasonable measures of 

market price, including but not limited 

to, index prices and prices reported to 

ONRR for like quality oil; or 

(3) ONRR cannot determine if you 

properly valued your oil under 

§ 1206.101 or § 1206.102 for any reason, 

including but not limited to, you or your 

affiliate’s failure to provide documents 

ONRR requests under 30 CFR part 1212, 

subpart B. 

(d) You have the burden of 

demonstrating that your or your 

affiliate’s contract is arm’s-length. 

(e) ONRR may require you to certify 

that the provisions in your or your 

affiliate’s contract include all of the 

consideration the buyer paid you or 

your affiliate, either directly or 

indirectly, for the oil. 

(f)(1) Absent contract revision or 

amendment, if you or your affiliate 

fail(s) to take proper or timely action to 

receive prices or benefits to which you 

or your affiliate are entitled, you must 

pay royalty based upon that obtainable 

price or benefit. 

(2) If you or your affiliate make timely 

application for a price increase or 

benefit allowed under your or your 

affiliate’s contract but the purchaser 

refuses and you or your affiliate take 

reasonable documented measures to 

force purchaser compliance, you will 

not owe additional royalties unless or 

until you or your affiliate receive 

additional monies or consideration 

resulting from the price increase. You 

may not construe this paragraph to 

permit you to avoid your royalty 

payment obligation in situations where 

a purchaser fails to pay, in whole or in 

part, or timely, for a quantity of oil. 

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

all contracts, contract revisions, or 

amendments in writing and all parties 

to the contract must sign the contract, 

contract revisions, or amendments. 

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

comply with paragraph (g)(1) of this 

section, ONRR may determine your 

value under § 1206.105. 

(3) This provision applies 

notwithstanding any other provisions in 

this title 30 to the contrary. 

§ 1206.105 How will ONRR determine the 

value of my oil for royalty purposes? 

If ONRR decides that it will value 

your oil for royalty purposes under 

§ 1206.104, or any other provision in 


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this subpart, then ONRR will determine 

value, for royalty purposes, by 

considering any information we deem 

relevant, which may include, but is not 

limited to: 

(a) The value of like-quality oil in the 

same field or nearby fields or areas; 

(b) The value of like-quality oil from 

the refinery or area; 

(c) Public sources of price or market 

information that ONRR deems reliable; 

(d) Information available and reported 

to ONRR, including but not limited to, 

on Form ONRR–2014 and Form ONRR– 

4054; 

(e) Costs of transportation or 

processing if ONRR determines they are 

applicable; or 

(f) Any information ONRR deems 

relevant regarding the particular lease 

operation or the salability of the oil. 

§ 1206.106 What records must I keep to 

support my calculations of value under this 

subpart? 

If you determine the value of your oil 

under this subpart, you must retain all 

data relevant to the determination of 

royalty value. 

(a) You must show: 

(1) How you calculated the value you 

reported, including all adjustments for 

location, quality, and transportation; 

and 

(2) How you complied with these 

rules. 

(b) You can find recordkeeping 

requirements in parts 1207 and 1212 of 

this chapter. 

(c) ONRR may review and audit your 

data, and ONRR will direct you to use 

a different value if it determines that the 

reported value is inconsistent with the 

requirements of this subpart. 

§ 1206.107 What are my responsibilities to 

place production into marketable condition 

and to market production? 

(a) You must place oil in marketable 

condition and market the oil for the 

mutual benefit of the lessee and the 

lessor at no cost to the Federal 

Government. 

(b) If you use gross proceeds under an 

arm’s-length contract in determining 

value, you must increase those gross 

proceeds to the extent that the 

purchaser, or any other person, provides 

certain services that the seller normally 

would be responsible to perform to 

place the oil in marketable condition or 

to market the oil. 

§ 1206.108 How do I request a value 

determination? 

(a) You may request a value 

determination from ONRR regarding any 

oil produced. Your request must: 

(1) Be in writing; 

(2) Identify specifically all leases 

involved, all interest owners of those 

leases, the designee(s), and the 

operator(s) for those leases; 

(3) Completely explain all relevant 

facts. You must inform ONRR of any 

changes to relevant facts that occur 

before we respond to your request; 

(4) Include copies of all relevant 

documents; 

(5) Provide your analysis of the 

issue(s), including citations to all 

relevant precedents (including adverse 

precedents); and 

(6) Suggest your proposed valuation 

method. 

(b) In response to your request, ONRR 

may: 

(1) Request that the Assistant 

Secretary for Policy, Management and 

Budget issue a valuation determination; 

(2) Decide that ONRR will issue 

guidance; or 

(3) Inform you in writing that ONRR 

will not provide a determination or 

guidance. Situations in which ONRR 

typically will not provide any 

determination or guidance include, but 

are not limited to: 

(i) Requests for guidance on 

hypothetical situations; and 

(ii) Matters that are the subject of 

pending litigation or administrative 

appeals. 

(c)(1) A value determination the 

Assistant Secretary for Policy, 

Management and Budget signs is 

binding on both you and ONRR until 

the Assistant Secretary modifies or 

rescinds it. 

(2) After the Assistant Secretary issues 

a value determination, you must make 

any adjustments to royalty payments 

that follow from the determination and, 

if you owe additional royalties, you 

must pay the additional royalties due, 

plus late payment interest calculated 

under §§ 1218.54 and 1218.102 of this 

chapter. 

(3) A value determination the 

Assistant Secretary signs is the final 

action of the Department and is subject 

to judicial review under 5 U.S.C. 701– 

706. 

(d) Guidance ONRR issues is not 

binding on ONRR, delegated States, or 

you with respect to the specific 

situation addressed in the guidance. 

(1) Guidance and ONRR’s decision 

whether or not to issue guidance or 

request an Assistant Secretary 

determination, or neither, under 

paragraph (b) of this section, are not 

appealable decisions or orders under 30 

CFR part 1290. 

(2) If you receive an order requiring 

you to pay royalty on the same basis as 

the guidance, you may appeal that order 

under 30 CFR part 1290. 

(e) ONRR or the Assistant Secretary 

may use any of the applicable valuation 

criteria in this subpart to provide 

guidance or make a determination. 

(f) A change in an applicable statute 

or regulation on which ONRR or the 

Assistant Secretary based any 

determination or guidance takes 

precedence over the determination or 

guidance, regardless of whether ONRR 

or the Assistant Secretary modifies or 

rescinds the determination or guidance. 

(g) ONRR or the Assistant Secretary 

generally will not retroactively modify 

or rescind a value 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 § 1206.109. 

§ 1206.109 Does ONRR protect information 

I provide? 

(a) Certain information you or your 

affiliate submit(s) to ONRR regarding 

valuation of oil, including 

transportation allowances, may be 

exempt from disclosure. 

(b) To the extent applicable laws and 

regulations permit, ONRR will keep 

confidential any data you or your 

affiliate submit(s) that is privileged, 

confidential, or otherwise exempt from 

disclosure. 

(c) You and others must submit all 

requests for information under the 

Freedom of Information Act regulations 

of the Department of the Interior at 43 

CFR part 2. 

§ 1206.110 What general transportation 

allowance requirements apply to me? 

(a) ONRR will allow a deduction for 

the reasonable, actual costs to transport 

oil from the lease to the point off the 

lease under § 1206.110, § 1206.111, or 

§ 1206.112, as applicable. You may not 

deduct transportation costs you incur to 

move a particular volume of production 

to reduce royalties you owe on 

production for which you did not incur 

those costs. This paragraph applies 

when: 

(1) You value oil under § 1206.101 

based on a sale at a point off the lease, 

unit, or communitized area where the 

oil is produced; 

(2)(i) The movement to the sales point 

is not gathering. 

(ii) For oil produced on the OCS, the 

movement of oil from the wellhead to 

the first platform is not transportation; 

and 

(3) You do not value your oil under 

§ 1206.102(a)(3) or (b)(3). 


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(b) You must calculate the deduction 

for transportation costs based on your or 

your affiliate’s cost of transporting each 

product through each individual 

transportation system. If your or your 

affiliate’s transportation contract 

includes more than one liquid product, 

you must allocate costs consistently and 

equitably to each of the liquid products 

transported. Your allocation must use 

the same proportion as the ratio of the 

volume of each liquid product 

(excluding waste products with no 

value) to the volume of all liquid 

products (excluding waste products 

with no value). 

(1) You may not take an allowance for 

transporting lease production that is not 

royalty-bearing. 

(2) You may propose to ONRR a 

prospective cost allocation method 

based on the values of the liquid 

products transported. ONRR will 

approve the method if it is consistent 

with the purposes of the regulations in 

this subpart. 

(3) You may use your proposed 

procedure to calculate a transportation 

allowance beginning with the 

production month following the month 

ONRR received your proposed 

procedure until ONRR accepts or rejects 

your cost allocation. If ONRR rejects 

your cost allocation, you must amend 

your Form ONRR–2014 for the months 

that you used the rejected method and 

pay any additional royalty due, plus late 

payment interest. 

(c)(1) Where you or your affiliate 

transport(s) both gaseous and liquid 

products through the same 

transportation system, you must 

propose a cost allocation procedure to 

ONRR. 

(2) You may use your proposed 

procedure to calculate a transportation 

allowance until ONRR accepts or rejects 

your cost allocation. If ONRR rejects 

your cost allocation, you must amend 

your Form ONRR–2014 for the months 

that you used the rejected method and 

pay any additional royalty and interest 

due. 

(3) You must submit your initial 

proposal, including all available data, 

within 3 months after you first claim the 

allocated deductions on Form ONRR– 

2014. 

(d)(1) Your transportation allowance 

may not exceed 50 percent of the value 

of the oil as determined under 

§ 1206.101 of this subpart. 

(2) If ONRR approved your request to 

take a transportation allowance in 

excess of the 50-percent limitation 

under former § 1206.109(c), that 

approval is terminated as of [effective 

date of final rule]. 

(e) You must express transportation 

allowances for oil as a dollar-value 

equivalent. If your or your affiliate’s 

payments for transportation under a 

contract are not on a dollar-per-unit 

basis, you must convert whatever 

consideration you or your affiliate are 

paid to a dollar-value equivalent. 

(f) ONRR may determine your 

transportation allowance under 

§ 1206.105 because: 

(1) There is misconduct by or between 

the contracting parties; 

(2) ONRR determines that the 

consideration 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. We may 

consider a transportation allowance to 

be unreasonably high if it is 10 percent 

higher than the highest reasonable 

measures of transportation costs, 

including but not limited to, 

transportation allowances reported to 

ONRR and tariffs for gas, residue gas, or 

gas plant product transported through 

the same system; or 

(3) ONRR cannot determine if you 

properly calculated a transportation 

allowance under § 1206.111 or 

§ 1206.112 for any reason, including, 

but not limited to, your or your 

affiliate’s failure to provide documents 

ONRR requests under 30 CFR part 1212, 

subpart B. 

(g) You do not need ONRR approval 

before reporting a transportation 

allowance. 

§ 1206.111 How do I determine a 

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

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

transportation costs under an arm’slength transportation contract, you may 

claim a transportation allowance for the 

reasonable, actual costs incurred as 

more fully explained in paragraph (b) of 

this section, except as provided in 

§ 1206.110(f) and subject to the 

limitation in § 1206.110(d). 

(2) You must be able to demonstrate 

that your or your affiliate’s contract is at 

arm’s-length. 

(3) You do not need ONRR approval 

before reporting a transportation 

allowance for costs incurred under an 

arm’s-length transportation contract. 

(b) Subject to the requirements of 

paragraph (c) of this section, you may 

include, but are not limited to the 

following costs to determine your 

transportation allowance under 

paragraph (a) of this section. You may 

not use any cost as a deduction that 

duplicates all or part of any other cost 

that you use under this section. 

(1) The amount that you pay under 

your arm’s-length transportation 

contract or tariff. 

(2) Fees paid (either in volume or in 

value) for actual or theoretical line 

losses. 

(3) Fees paid for administration of a 

quality bank. 

(4) Fees paid to a terminal operator for 

loading and unloading of crude oil into 

or from a vessel, vehicle, pipeline, or 

other conveyance. 

(5) Fees paid for short-term storage 

(30 days or less) incidental to 

transportation as required by a 

transporter. 

(6) Fees paid to pump oil to another 

carrier’s system or vehicles as required 

under a tariff. 

(7) Transfer fees paid to a hub 

operator associated with physical 

movement of crude oil through the hub 

when you do not sell the oil at the hub. 

These fees do not include title transfer 

fees. 

(8) Payments for a volumetric 

deduction to cover shrinkage when 

high-gravity petroleum (generally in 

excess of 51 degrees API) is mixed with 

lower gravity crude oil for 

transportation. 

(9) Costs of securing a letter of credit, 

or other surety, that the pipeline 

requires you as a shipper to maintain. 

(10) Hurricane surcharges you or your 

affiliate actually pay(s). 

(c) You may not include the following 

costs to determine your transportation 

allowance under paragraph (a) of this 

section: 

(1) Fees paid for long-term storage 

(more than 30 days); 

(2) Administrative, handling, and 

accounting fees associated with 

terminalling; 

(3) Title and terminal transfer fees; 

(4) Fees paid to track and match 

receipts and deliveries at a market 

center or to avoid paying title transfer 

fees; 

(5) Fees paid to brokers; 

(6) Fees paid to a scheduling service 

provider; 

(7) Internal costs, including salaries 

and related costs, rent/space costs, 

office equipment costs, legal fees, and 

other costs to schedule, nominate, and 

account for sale or movement of 

production; 

(8) Gauging fees; and 

(9) The cost of carrying on your books 

as inventory a volume of oil that you or 

your affiliate, as the pipeline operator, 

maintain(s) in the line as line fill. 

(d) If you have no written contract for 

the arm’s-length transportation of oil, 

then ONRR will determine your 


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Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 651 

transportation allowance under 

§ 1206.105. You may not use this 

paragraph (d) if you or your affiliate 

perform(s) your own transportation. 

(1) You must propose to ONRR a 

method to determine the allowance 

using the procedures in § 1206.108(a). 

(2) You may use that method to 

determine your allowance until ONRR 

issues its determination. 

§ 1206.112 How do I determine a 

transportation allowance if I do not have an 

arm’s-length transportation contract? 

(a) This section applies if you or your 

affiliate do(es) not have an arm’s-length 

transportation contract, including 

situations where you or your affiliate 

provide your own transportation 

services. You must calculate your 

transportation allowance based on your 

or your affiliate’s reasonable, actual 

costs for transportation during the 

reporting period using the procedures 

prescribed in this section. 

(b) Your or your affiliate’s actual costs 

may include: 

(1) Capital costs and operating and 

maintenance expenses under paragraphs 

(e), (f), and (g) of this section; 

(2) Overhead under paragraph (h) of 

this section; and 

(3)(i) Depreciation and a return on 

undepreciated capital investment under 

paragraph (i)(1) of this section, or you 

may elect to use a cost equal to a return 

on the initial depreciable capital 

investment in the transportation system 

under paragraph (i)(2) of this section. 

After you have elected to use either 

method for a transportation system, you 

may not later elect to change to the 

other alternative without ONRR 

approval. If ONRR accepts your request 

to change methods, you may use your 

changed method beginning with the 

production month following the month 

ONRR received your change request; 

and 

(ii) A return on the reasonable salvage 

value under paragraph (i)(1)(iii) of this 

section, after you have depreciated the 

transportation system to its reasonable 

salvage value. 

(c) To the extent not included in costs 

identified in paragraphs (e) through (h) 

of this section; 

(1) If you or your affiliate incur(s) the 

following actual costs under your or 

your affiliate’s non-arm’s-length 

contract, you may include these costs in 

your calculations under this section. 

(i) Fees paid to a non-affiliated 

terminal operator for loading and 

unloading of crude oil into or from a 

vessel, vehicle, pipeline, or other 

conveyance. 

(ii) Transfer fees paid to a hub 

operator associated with physical 

movement of crude oil through the hub 

when you do not sell the oil at the hub. 

These fees do not include title transfer 

fees. 

(iii) A volumetric deduction to cover 

shrinkage when high-gravity petroleum 

(generally in excess of 51 degrees API) 

is mixed with lower gravity crude oil for 

transportation. 

(iv) Fees paid to a non-affiliated 

quality bank administrator for 

administration of a quality bank. 

(2) You may not include in your 

transportation allowance: 

(i) Any of the costs identified under 

§ 1206.111(c); and 

(ii) Fees paid (either in volume or in 

value) for actual or theoretical line 

losses. 

(d) You may not use any cost as a 

deduction that duplicates all or part of 

any other cost that you use under this 

section. 

(e) Allowable capital investment costs 

are generally those for depreciable fixed 

assets (including costs of delivery and 

installation of capital equipment) that 

are an integral part of the transportation 

system. 

(f) Allowable operating expenses 

include: 

(i) Operations supervision and 

engineering; 

(ii) Operations labor; 

(iii) Fuel; 

(iv) Utilities; 

(v) Materials; 

(vi) Ad valorem property taxes; 

(vii) Rent; 

(viii) Supplies; and 

(ix) Any other directly allocable and 

attributable operating expense that you 

can document. 

(g) Allowable maintenance expenses 

include: 

(1) Maintenance of the transportation 

system; 

(2) Maintenance of equipment; 

(3) Maintenance labor; and 

(4) Other directly allocable and 

attributable maintenance expenses that 

you can document. 

(h) Overhead, directly attributable and 

allocable to the operation and 

maintenance of the transportation 

system, is an allowable expense. State 

and Federal income taxes and severance 

taxes and other fees, including royalties, 

are not allowable expenses. 

(i)(1) To calculate depreciation and a 

return on undepreciated capital 

investment, you may elect to use either 

a straight-line depreciation method 

(based on the life of equipment or on the 

life of the reserves that the 

transportation system services) or a unit 

of production method. After you make 

an election, you may not change 

methods without ONRR approval. If 

ONRR accepts your request to change 

methods, you may use your changed 

method beginning with the production 

month following the month ONRR 

received your change request. 

(i) A change in ownership of a 

transportation system will not alter the 

depreciation schedule the original 

transporter/lessee established for 

purposes of the allowance calculation. 

(ii) You may depreciate a 

transportation system, with or without a 

change in ownership, only once. 

(iii)(A) To calculate the return on 

undepreciated capital investment, you 

may use an amount equal to the 

undepreciated capital investment in the 

transportation system multiplied by the 

rate of return you determine under 

paragraph (i)(3) of this section. 

(B) After you have depreciated a 

transportation system to the reasonable 

salvage value, you may continue to 

include in the allowance calculation a 

cost equal to the reasonable salvage 

value multiplied by a rate of return 

under paragraph (i)(3) of this section. 

(2) As an alternative to using 

depreciation and a return on 

undepreciated capital investment, as 

provided under paragraph (b)(3) of this 

section, you may use as a cost an 

amount equal to the allowable initial 

capital investment in the transportation 

system multiplied by the rate of return 

determined under paragraph (i)(3) of 

this section. You may not include 

depreciation in your allowance. 

(3) The rate of return is the industrial 

rate associated with Standard & Poor’s 

BBB rating. 

(i) You must use the monthly average 

BBB rate that Standard & Poor’s 

publishes for the first month for which 

the allowance is applicable. 

(ii) You must redetermine the rate at 

the beginning of each subsequent 

calendar year. 

§ 1206.113 What adjustments and 

transportation allowances apply when I 

value oil production from my lease using 

NYMEX prices or ANS spot prices? 

This section applies when you use 

NYMEX prices or ANS spot prices to 

calculate the value of production under 

§ 1206.102. As specified in this section, 

you must adjust the NYMEX price to 

reflect the difference in value between 

your lease and Cushing, Oklahoma, or 

adjust the ANS spot price to reflect the 

difference in value between your lease 

and the appropriate ONRR-recognized 

market center at which the ANS spot 

price is published (for example, Long 

Beach, California, or San Francisco, 

California). Paragraph (a) of this section 

explains how you adjust the value 

between the lease and the market center, 


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and paragraph (b) of this section 

explains how you adjust the value 

between the market center and Cushing 

when you use NYMEX prices. Paragraph 

(c) of this section explains how 

adjustments may be made for quality 

differentials that are not accounted for 

through exchange agreements. 

Paragraph (d) of this section gives some 

examples. References in this section to 

‘‘you’’ include your affiliates as 

applicable. 

(a) To adjust the value between the 

lease and the market center: 

(1)(i) For oil that you exchange at 

arm’s-length between your lease and the 

market center (or between any 

intermediate points between those 

locations), you must calculate a lease-tomarket center differential by the 

applicable location and quality 

differentials derived from your arm’slength exchange agreement applicable to 

production during the production 

month. 

(ii) For oil that you exchange between 

your lease and the market center (or 

between any intermediate points 

between those locations) under an 

exchange agreement that is not at arm’slength, you must obtain approval from 

ONRR for a location and quality 

differential. Until you obtain such 

approval, you may use the location and 

quality differential derived from that 

exchange agreement applicable to 

production during the production 

month. If ONRR prescribes a different 

differential, you must apply ONRR’s 

differential to all periods for which you 

used your proposed differential. You 

must pay any additional royalties due 

resulting from using ONRR’s 

differential, plus late payment interest 

from the original royalty due date, or 

you may report a credit for any overpaid 

royalties, plus interest, under 30 U.S.C. 

1721(h). 

(2) For oil that you transport between 

your lease and the market center (or 

between any intermediate points 

between those locations), you may take 

an allowance for the cost of transporting 

that oil between the relevant points as 

determined under § 1206.111 or 

§ 1206.112, as applicable. 

(3) If you transport or exchange at 

arm’s-length (or both transport and 

exchange) at least 20 percent, but not 

all, of your oil produced from the lease 

to a market center, you must determine 

the adjustment between the lease and 

the market center for the oil that is not 

transported or exchanged (or both 

transported and exchanged) to or 

through a market center as follows: 

(i) Determine the volume-weighted 

average of the lease-to-market center 

adjustment calculated under paragraphs 

(a)(1) and (2) of this section for the oil 

that you do transport or exchange (or 

both transport and exchange) from your 

lease to a market center. 

(ii) Use that volume-weighted average 

lease-to-market center adjustment as the 

adjustment for the oil that you do not 

transport or exchange (or both transport 

and exchange) from your lease to a 

market center. 

(4) If you transport or exchange (or 

both transport and exchange) less than 

20 percent of the crude oil produced 

from your lease between the lease and 

a market center, you must propose to 

ONRR an adjustment between the lease 

and the market center for the portion of 

the oil that you do not transport or 

exchange (or both transport and 

exchange) to a market center. Until you 

obtain such approval, you may use your 

proposed adjustment. If ONRR 

prescribes a different adjustment, you 

must apply ONRR’s adjustment to all 

periods for which you used your 

proposed adjustment. You must pay any 

additional royalties due resulting from 

using ONRR’s adjustment, plus late 

payment interest from the original 

royalty due date, or you may report a 

credit for any overpaid royalties plus 

interest under 30 U.S.C. 1721(h). 

(5) You may not both take a 

transportation allowance and use a 

location and quality adjustment or 

exchange differential for the same oil 

between the same points. 

(b) For oil that you value using 

NYMEX prices, you must adjust the 

value between the market center and 

Cushing, Oklahoma, as follows: 

(1) If you have arm’s-length exchange 

agreements between the market center 

and Cushing under which you exchange 

to Cushing at least 20 percent of all the 

oil you own at the market center during 

the production month, you must use the 

volume-weighted average of the location 

and quality differentials from those 

agreements as the adjustment between 

the market center and Cushing for all 

the oil that you produce from the leases 

during that production month for which 

that market center is used. 

(2) If paragraph (b)(1) of this section 

does not apply, you must use the WTI 

differential published in an ONRRapproved publication for the market 

center nearest your lease, for crude oil 

most similar in quality to your 

production, as the adjustment between 

the market center and Cushing. For 

example, for light sweet crude oil 

produced offshore of Louisiana, you 

must use the WTI differential for Light 

Louisiana Sweet crude oil at St. James, 

Louisiana. After you select an ONRRapproved publication, you may not 

select a different publication more often 

than once every 2 years, unless the 

publication you use is no longer 

published or ONRR revokes its approval 

of the publication. If you must change 

publications, you must begin a new 2- 

year period. 

(3) If neither paragraph (b)(1) nor (2) 

of this section applies, you may propose 

an alternative differential to ONRR. 

Until you obtain such approval, you 

may use your proposed differential. If 

ONRR prescribes a different differential, 

you must apply ONRR’s differential to 

all periods for which you used your 

proposed differential. You must pay any 

additional royalties due resulting from 

using ONRR’s differential, plus late 

payment interest from the original 

royalty due date, or you may report a 

credit for any overpaid royalties plus 

interest under 30 U.S.C. 1721(h). 

(c)(1) If you adjust for location and 

quality differentials or for transportation 

costs under paragraphs (a) and (b) of 

this section, you also must adjust the 

NYMEX price or ANS spot price for 

quality based on premiums or penalties 

determined by pipeline quality bank 

specifications at intermediate 

commingling points or at the market 

center if those points are downstream of 

the royalty measurement point 

approved by BSEE or BLM, as 

applicable. You must make this 

adjustment only if and to the extent that 

such adjustments were not already 

included in the location and quality 

differentials determined from your 

arm’s-length exchange agreements. 

(2) If the quality of your oil as 

adjusted is still different from the 

quality of the representative crude oil at 

the market center after making the 

quality adjustments described in 

paragraphs (a), (b), and (c)(1) of this 

section, you may make further gravity 

adjustments using posted price gravity 

tables. If quality bank adjustments do 

not incorporate or provide for 

adjustments for sulfur content, you may 

make sulfur adjustments, based on the 

quality of the representative crude oil at 

the market center, of 5.0 cents per onetenth percent difference in sulfur 

content. 

(i) You may request prior ONRR 

approval to use a different adjustment. 

(ii) If ONRR approves your request to 

use a different quality adjustment, you 

may begin using that adjustment the 

production month following the month 

ONRR received your request. 

(d) The examples in this paragraph 

illustrate how to apply the requirement 

of this section. 

(1) Example. Assume that a Federal 

lessee produces crude oil from a lease 

near Artesia, New Mexico. Further, 

assume that the lessee transports the oil 


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to Roswell, New Mexico, and then 

exchanges the oil to Midland, Texas. 

Assume the lessee refines the oil 

received in exchange at Midland. 

Assume that the NYMEX price is 

$86.21/bbl, adjusted for the roll; that the 

WTI differential (Cushing to Midland) is 

¥$2.27/bbl; that the lessee’s exchange 

agreement between Roswell and 

Midland results in a location and 

quality differential of ¥$0.08/bbl; and 

that the lessee’s actual cost of 

transporting the oil from Artesia to 

Roswell is $0.40/bbl. In this example, 

the royalty value of the oil is $86.21 ¥ 

$2.27 ¥ $0.08 ¥ $0.40 = $83.46/bbl. 

(2) Example. Assume the same facts as 

in the example in paragraph (d)(1) of 

this section, except that the lessee 

transports and exchanges to Midland 40 

percent of the production from the lease 

near Artesia, and transports the 

remaining 60 percent directly to its own 

refinery in Ohio. In this example, the 40 

percent of the production would be 

valued at $83.46/bbl, as explained in the 

previous example. In this example, the 

other 60 percent also would be valued 

at $83.46/bbl. 

(3) Example. Assume that a Federal 

lessee produces crude oil from a lease 

near Bakersfield, California. Further, 

assume that the lessee transports the oil 

to Hynes Station and then exchanges the 

oil to Cushing, which it further 

exchanges with oil it refines. Assume 

that the ANS spot price is $105.65/bbl 

and that the lessee’s actual cost of 

transporting the oil from Bakersfield to 

Hynes Station is $0.28/bbl. The lessee 

must request approval from ONRR for a 

location and quality adjustment 

between Hynes Station and Long Beach. 

For example, the lessee likely would 

propose using the tariff on Line 63 from 

Hynes Station to Long Beach as the 

adjustment between those points. 

Assume that adjustment to be $0.72, 

including the sulfur and gravity bank 

adjustments, and that ONRR approves 

the lessee’s request. In this example, the 

preliminary (because the location and 

quality adjustment is subject to ONRR 

review) royalty value of the oil is 

$105.65 ¥ $0.72 ¥ $0.28 = $104.65/bbl. 

The fact that oil was exchanged to 

Cushing does not change use of ANS 

spot prices for royalty valuation. 

§ 1206.114 How will ONRR identify market 

centers? 

ONRR will monitor market activity 

and, if necessary, add to or modify the 

list of market centers published to 

www.onrr.gov. ONRR will consider the 

following factors and conditions in 

specifying market centers: 

(a) Points where ONRR-approved 

publications publish prices useful for 

index purposes; 

(b) Markets served; 

(c) Input from industry and others 

knowledgeable in crude oil marketing 

and transportation; 

(d) Simplification; and 

(e) Other relevant matters. 

§ 1206.115 What are my reporting 

requirements under an arm’s-length 

transportation contract? 

(a) You must use a separate entry on 

Form ONRR–2014 to notify ONRR of an 

allowance based on transportation costs 

you or your affiliate incur(s). 

(b) ONRR may require you or your 

affiliate to submit arm’s-length 

transportation contracts, production 

agreements, operating agreements, and 

related documents. 

(c) You can find recordkeeping 

requirements in parts 1207 and 1212 of 

this chapter. 

§ 1206.116 What are my reporting 

requirements under a non-arm’s-length 

transportation contract? 

(a) You must use a separate entry on 

Form ONRR–2014 to notify ONRR of an 

allowance based on transportation costs 

you or your affiliate incur(s). 

(b)(1) For new non-arm’s-length 

transportation facilities or arrangements, 

you must base your initial deduction on 

estimates of allowable transportation 

costs for the applicable period. 

(2) You must use your or your 

affiliate’s most recently available 

operations data for the transportation 

system as your estimate, if available. If 

such data is not available, you must use 

estimates based on data for similar 

transportation systems. 

(3) Section 1206.118 applies when 

you amend your report based on the 

actual costs. 

(c) ONRR may require you or your 

affiliate to submit all data used to 

calculate the allowance deduction. You 

may find recordkeeping requirements in 

parts 1207 and 1212 of this chapter. 

(d) If you are authorized under 

§ 1206.112(j) to use an exception to the 

requirement to calculate your actual 

transportation costs, you must follow 

the reporting requirements of 

§ 1206.115. 

§ 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, 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 

that amount is taken to the date you pay 

the additional royalties due. 

(b) If you improperly net a 

transportation allowance against the oil 

instead of reporting the allowance as a 

separate entry on Form ONRR–2014, 

ONRR may assess a civil penalty under 

30 CFR part 1241. 

§ 1206.118 What reporting adjustments 

must I make for transportation allowances? 

(a) If your actual transportation 

allowance is less than the amount you 

claimed on Form ONRR–2014 for each 

month during the allowance reporting 

period, you must pay additional 

royalties due, plus late payment interest 

calculated under §§ 1218.54 and 

1218.102 of this chapter from the date 

you took the deduction to the date you 

repay the difference. 

(b) If the actual transportation 

allowance is greater than the amount 

you claimed on Form ONRR–2014 for 

any month during the period reported 

on the allowance form, you are entitled 

to a credit plus interest. 

§ 1206.119 How do I determine royalty 

quantity and quality? 

(a) You must calculate royalties based 

on the quantity and quality of oil as 

measured at the point of royalty 

settlement that BLM or BSEE approves 

for onshore leases and OCS leases, 

respectively. 

(b) If you base the value of oil 

determined under this subpart on a 

quantity and/or quality that is different 

from the quantity and/or quality at the 

point of royalty settlement that BLM or 

BSEE approves, you must adjust that 

value for the differences in quantity 

and/or quality. 

(c) You may not make any deductions 

from the royalty volume or royalty value 

for actual or theoretical losses. Any 

actual loss that you sustain before the 

royalty settlement metering or 

measurement point is not subject to 

royalty if BLM or BSEE, whichever is 

appropriate, determines that such loss 

was unavoidable. 

(d) You must pay royalties on 100 

percent of the volume measured at the 

approved point of royalty settlement. 

You may not claim a reduction in that 

measured volume for actual losses 

beyond the approved point of royalty 

settlement or for theoretical losses that 

you claim to have taken place either 

before or after the approved point of 

royalty settlement. 

■ 7. Revise subpart D to read as follows: 

Subpart D—Federal Gas 

Sec. 

1206.140 What is the purpose and scope of 

this subpart? 


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1206.141 How do I calculate royalty value 

for unprocessed gas I or my affiliate 

sell(s) under an arm’s-length or nonarm’s-length contract? 

1206.142 How do I calculate royalty value 

for processed gas I or my affiliate sell(s) 

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

1206.143 How will ONRR determine if my 

royalty payments are correct? 

1206.144 How will ONRR determine the 

value of my gas for royalty purposes? 

1206.145 What records must I keep to 

support my calculations of royalty under 

this subpart? 

1206.146 What are my responsibilities to 

place production into marketable 

condition and to market production? 

1206.147 When is an ONRR audit, review, 

reconciliation, monitoring, or other like 

process considered final? 

1206.148 How do I request a valuation 

determination or guidance? 

1206.149 Does ONRR protect information I 

provide? 

1206.150 How do I determine royalty 

quantity and quality? 

1206.151 How do I perform accounting for 

comparison? 

1206.152 What general transportation 

allowance requirements apply to me? 

1206.153 How do I determine a 

transportation allowance if I have an 

arm’s-length transportation contract? 

1206.154 How do I determine a 

transportation allowance if I have a nonarm’s-length transportation contract? 

1206.155 What are my reporting 

requirements under an arm’s-length 

transportation contract? 

1206.156 What are my reporting 

requirements under a non-arm’s-length 

transportation contract? 

1206.157 What interest and penalties apply 

if I improperly report a transportation 

allowance? 

1206.158 What reporting adjustments must 

I make for transportation allowances? 

1206.159 What general requirements 

regarding processing allowances apply to 

me? 

1206.160 How do I determine a processing 

allowance, if I have an arm’s-length 

processing contract? 

1206.161 How do I determine a processing 

allowance if I have a non-arm’s-length 

processing contract? 

1206.162 What are my reporting 

requirements under an arm’s-length 

processing contract? 

1206.163 What are my reporting 

requirements under a non-arm’s-length 

processing contract? 

1206.164 What interest and penalties apply 

if I improperly report a processing 

allowance? 

1206.165 What reporting adjustments must 

I make for processing allowances? 

Subpart D—Federal Gas 

§ 1206.140 What is the purpose and scope 

of this subpart? 

(a) This subpart applies to all gas 

produced from Federal oil and gas 

leases onshore and on the Outer 

Continental Shelf (OCS). It explains 

how you, as a lessee, must calculate the 

value of production for royalty purposes 

consistent with mineral leasing laws, 

other applicable laws, and lease terms. 

(b) The terms ‘‘you’’ and ‘‘your’’ in 

this subpart refer to the lessee. 

(c) If the regulations in this subpart 

are inconsistent with: 

(1) A Federal statute; 

(2) A settlement agreement between 

the United States and a lessee resulting 

from administrative or judicial 

litigation; 

(3) A written agreement between the 

lessee and the ONRR Director 

establishing a method to determine the 

value of production from any lease that 

ONRR expects, at least, would 

approximate the value established 

under this subpart; or 

(4) An express provision of an oil and 

gas lease subject to this subpart; then 

the statute, settlement agreement, 

written agreement, or lease provision 

will govern to the extent of the 

inconsistency. 

(d) ONRR may audit and order you to 

adjust all royalty payments. 

§ 1206.141 How do I calculate royalty value 

for unprocessed gas I or my affiliate sell(s) 

under an arm’s-length or non-arm’s-length 

contract? 

(a) This section applies to 

unprocessed gas. Unprocessed gas is: 

(1) Gas that is not processed; 

(2) Any gas that you are not required 

to value under § 1206.142 or that ONRR 

does not value under § 1206.144; 

(3) Processed gas that you must value 

prior to processing under § 1206.151 of 

this part; and 

(4) Any gas you sell prior to 

processing based on a price per MMBtu 

or Mcf when the price is not based on 

the residue gas and gas plant products. 

(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 an applicable 

transportation allowance determined 

under § 1206.152. This value does not 

apply if you may exercise the option 

provided in paragraph (c) of this section 

or if ONRR decides to value your gas 

under § 1206.144. You must use this 

paragraph (b) to value gas when: 

(1) You sell under an arm’s-length 

contract; 

(2) You sell or transfer to your affiliate 

or another person under a non-arm’slength contract and that affiliate or 

person, or another affiliate of either of 

them, then sells the gas under an arm’slength contract, unless you exercise the 

option provided in paragraph (c) of this 

section; 

(3) You, your affiliate, or another 

person sell(s) under multiple arm’slength contracts for gas produced from 

a lease that is valued under this 

paragraph. In that case, unless you 

exercise the option provided in 

paragraph (c) of this section, because 

you sold non-arm’s length to your 

affiliate or another person, the value of 

the gas is the volume-weighted average 

of the value established under this 

paragraph for each contract for the sale 

of gas produced from that lease; or 

(4) You or your affiliate sell(s) under 

a pipeline cash-out program. In that 

case, for over-delivered volumes within 

the tolerance under a pipeline cash-out 

program, the value is the price the 

pipeline must pay you or your affiliate 

under the transportation contract. You 

must use the same value for volumes 

that exceed the over-delivery tolerances, 

even if those volumes are subject to a 

lower price under the transportation 

contract. 

(c) If you do not sell under an arm’slength contract, you may elect to value 

your gas under this paragraph (c). 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 highest reported 

monthly bidweek price for that index 

pricing point for the 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 

reported monthly bidweek price for the 

index pricing points to which your gas 

could be transported for the production 

month, whether or not there are 

constraints for that production month. 

(iii) If there are sequential index 

pricing points on a pipeline, you must 

use the first index pricing point at or 

after your gas enters the pipeline. 

(iv) You must reduce the number 

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

and (c)(1)(ii) of this section by 5 percent 

for sales from the OCS Gulf of Mexico 

and by 10 percent for sales from all 

other areas, but not by less than 10 cents 

per MMBtu or more than 30 cents per 

MMBtu. 

(v) After you select an ONRRapproved publication available at 

www.onrr.gov, you may not select a 

different publication more often than 

once every two years. 

(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 


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production. ONRR will publish a list of 

excluded index pricing points available 

at www.onrr.gov. 

(2) You may not take any other 

deductions from the value calculated 

under this paragraph (c). 

(d) If you have no written contract for 

the sale of gas or no sale of gas subject 

to this section and: 

(1) There is an index pricing point for 

the gas, then you must value your gas 

under paragraph (c) of this section; 

(2) There is not an index pricing point 

for the gas, then ONRR will decide the 

value under § 1206.144. 

(i) You must propose to ONRR a 

method to determine the value using the 

procedures in § 1206.148(a). 

(ii) You may use that method to 

determine value, for royalty purposes, 

until ONRR issues its decision. 

(iii) After ONRR issues its 

determination, you must make the 

adjustments under § 1206.143(a)(2). 

§ 1206.142 How do I calculate royalty value 

for processed gas I or my affiliate sell(s) 

under an arm’s-length or non-arm’s-length 

contract? 

(a) This section applies to the 

valuation of processed gas, including 

but not limited to: 

(1) Gas you or your affiliate do not 

sell, or otherwise dispose of, under an 

arm’s-length contract prior to 

processing; 

(2) Gas where your or your affiliate’s 

arm’s-length contract for the sale of gas 

prior to processing provides for 

payment to be determined on the basis 

of the value of any products resulting 

from processing, including residue gas 

or natural gas liquids; 

(3) Gas you or your affiliate process 

under an arm’s-length keepwhole 

contract; and 

(4) Gas where your or your affiliate’s 

arm’s-length contract includes a 

reservation of the right to process the 

gas and you or your affiliate exercise(s) 

that right. 

(b) The value of gas subject to this 

section, for royalty purposes, is: 

(1) The combined value of the residue 

gas and all gas plant products you 

determine under this section; 

(2) Plus the value of any condensate 

recovered downstream of the point of 

royalty settlement without resorting to 

processing you determine under 

§ 1206.141 of this part; 

(3) Less applicable transportation and 

processing allowances you determine 

under this subpart, unless you exercise 

the option provided in paragraph (d) of 

this section. 

(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, or if ONRR decides to value 

your residue gas or any gas plant 

product under § 1206.144. You must use 

this paragraph (c) to value residue gas 

or any gas plant product when: 

(1) You sell under an arm’s-length 

contract; 

(2) You sell or transfer to your affiliate 

or another person under a non-arm’slength 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, unless you exercise the option 

provided in paragraph (d) of this 

section; 

(3) You, your affiliate, or another 

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

gas plant products recovered from gas 

produced from a lease that you value 

under this paragraph. In that case, 

unless you exercise the option provided 

in paragraph (d) of this section, 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 

(4) You or your affiliate sell(s) under 

a pipeline cash-out program. In that 

case, for over-delivered volumes within 

the tolerance under a pipeline cash-out 

program, the value is the price the 

pipeline must pay you or your affiliate 

under the transportation contract. You 

must use the same value for volumes 

that exceed the over-delivery tolerances, 

even if those volumes are subject to a 

lower price under the transportation 

contract. 

(d) If you do not sell under an arm’slength contract, you may elect to value 

your residue gas and natural gas liquids 

(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 highest 

reported monthly bidweek price for that 

index pricing point for the 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 reported monthly bidweek price 

for the index pricing points to which 

your gas could be transported for the 

production month, whether or not there 

are constraints, for the production 

month. 

(iii) If there are sequential index 

pricing points on a pipeline, you must 

use the first index pricing point at or 

after your residue gas enters the 

pipeline. 

(iv) You must reduce the number 

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

and (ii) of this section by 5 percent for 

sales from the OCS Gulf of Mexico and 

by 10 percent for sales from all other 

areas, but not by less than 10 cents per 

MMBtu or more than 30 cents per 

MMBtu. 

(v) After you select an ONRRapproved publication available at 

www.onrr.gov, you may not select a 

different publication more often than 

once every two years. 

(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 a list of 

excluded index pricing points available 

at www.onrr.gov. 

(2)(i) If you sell NGLs in an area with 

one or more ONRR-approved 

commercial price bulletins available at 

www.onrr.gov, you must choose one 

bulletin and your value, for royalty 

purposes, is the monthly average price 

for that bulletin for the production 

month. 

(ii) You must reduce the number 

calculated under paragraph (d)(2)(i) of 

this section by the amounts ONRR posts 

at www.onrr.gov for the geographic 

location of your lease. The methodology 

ONRR will use to calculate the amounts 

is set forth in the preamble to this 

regulation. This methodology is binding 

on you and ONRR. ONRR will update 

the amounts periodically using this 

methodology. 

(iii) After you select an ONRRapproved commercial price bulletin 

available at www.onrr.gov, you may not 

select a different commercial price 

bulletin more often than once every 2 

years. 

(3) You may not take any other 

deductions from the value calculated 

under this paragraph (d). 

(4) ONRR will post changes to any of 

the rates in this paragraph (d) on its 

Web site. 

(e) If you have no written contract for 

the sale of gas or no sale of gas subject 

to this section and: 

(1) There is an index pricing point or 

commercial price bulletin for the gas, 

then you must value your gas under 

paragraph (d) of this section. 


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(2) There is not an index pricing point 

or commercial price bulletin for the gas, 

then ONRR will determine the value 

under § 1206.144. 

(i) You must propose to ONRR a 

method to determine the value using the 

procedures in § 1206.148(a). 

(ii) You may use that method to 

determine value, for royalty purposes, 

until ONRR issues its decision. 

(iii) After ONRR issues its 

determination, you must make the 

adjustments under § 1206.143(a)(2). 

§ 1206.143 How will ONRR determine if my 

royalty payments are correct? 

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

audit the royalties 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 

or decide your value under § 1206.144. 

(2) If ONRR directs you to use a 

different royalty value, you must either 

pay any additional royalties due, plus 

late payment interest calculated under 

§§ 1218.54 and 1218.102 of this chapter 

or report a credit for, or request a refund 

of, any overpaid royalties. 

(b) When the provisions in this 

subpart refer to gross proceeds, in 

conducting reviews and audits, ONRR 

will examine if your or your affiliate’s 

contract reflects the total consideration 

actually transferred, either directly or 

indirectly, from the buyer to you or your 

affiliate for the gas, residue gas, or gas 

plant products. If ONRR determines that 

a contract does not reflect the total 

consideration, ONRR may decide your 

value under § 1206.144. 

(c) ONRR may decide your value 

under § 1206.144, if ONRR determines 

that the gross proceeds accruing to you 

or your affiliate under a contract do not 

reflect reasonable consideration 

because: 

(1) There is misconduct by or between 

the contracting parties; 

(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 by selling your 

gas, residue gas, or gas plant products at 

a value that is unreasonably low. ONRR 

may consider a sales price unreasonably 

low, if it is 10 percent less than the 

lowest reasonable measures of market 

price, including but not limited to, 

index prices and prices reported to 

ONRR for like-quality gas, residue gas, 

or gas plant products; or 

(3) ONRR cannot determine if you 

properly valued your gas, residue gas, or 

gas plant products under § 1206.141 or 

§ 1206.142 for any reason, including but 

not limited to, your or your affiliate’s 

failure to provide documents ONRR 

requests under 30 CFR part 1212, 

subpart B. 

(d) You have the burden of 

demonstrating that your or your 

affiliate’s contract is arm’s length. 

(e) ONRR may require you to certify 

that the provisions in your or your 

affiliate’s contract include(s) all of the 

consideration the buyer paid you or 

your affiliate, either directly or 

indirectly, for the gas, residue gas, or gas 

plant products. 

(f)(1) Absent contract revision or 

amendment, if you or your affiliate 

fail(s) to take proper or timely action to 

receive prices or benefits to which you 

or your affiliate are entitled, you must 

pay royalty based upon that obtainable 

price or benefit. 

(2) If you or your affiliate make timely 

application for a price increase or 

benefit allowed under your or your 

affiliate’s contract, but the purchaser 

refuses, and you or your affiliate take 

reasonable documented measures to 

force purchaser compliance, you will 

not owe additional royalties unless or 

until you or your affiliate receive 

additional monies or consideration 

resulting from the price increase. You 

may not construe this paragraph to 

permit you to avoid your royalty 

payment obligation in situations where 

a purchaser fails to pay, in whole or in 

part, or timely, for a quantity of gas, 

residue gas, or gas plant products. 

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

all contracts, contract revisions, or 

amendments in writing, and all parties 

to the contract must sign the contract, 

contract revisions, or amendments. 

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

comply with paragraph (g)(1) of this 

section, ONRR may decide your value 

under § 1206.144. 

(3) This provision applies 

notwithstanding any other provisions in 

this title 30 to the contrary. 

§ 1206.144 How will ONRR determine the 

value of my gas for royalty purposes? 

If ONRR decides to value your gas, 

residue gas, or gas plant products for 

royalty purposes under § 1206.143, or 

any other provision in this subpart, then 

ONRR will determine the value, for 

royalty purposes, by considering any 

information we deem relevant, which 

may include, but is not limited to: 

(a) The value of like-quality gas in the 

same field or nearby fields or areas; 

(b) The value of like-quality residue 

gas or gas plant products from the same 

plant or area; 

(c) Public sources of price or market 

information that ONRR deems reliable; 

(d) Information available or reported 

to ONRR, including but not limited to, 

on Form ONRR–2014 and Form ONRR– 

4054; 

(e) Costs of transportation or 

processing, if ONRR determines they are 

applicable; or 

(f) Any information ONRR deems 

relevant regarding the particular lease 

operation or the salability of the gas. 

§ 1206.145 What records must I keep to 

support my calculations of royalty under 

this subpart? 

If you value your gas under this 

subpart, you must retain all data 

relevant to the determination of the 

royalty you paid. You can find 

recordkeeping requirements in parts 

1207 and 1212 of this chapter. 

(a) You must show: 

(1) How you calculated the royalty 

value, including all allowable 

deductions; and 

(2) How you complied with this 

subpart. 

(b) Upon request, you must submit all 

data to ONRR. You must comply with 

any such requirement within the time 

ONRR specifies. 

§ 1206.146 What are my responsibilities to 

place production into marketable condition 

and to market production? 

(a) You must place gas, residue gas, 

and gas plant products in marketable 

condition and market the gas, residue 

gas, and gas plant products for the 

mutual benefit of the lessee and the 

lessor at no cost to the Federal 

Government. 

(b) If you use gross proceeds under an 

arm’s-length contract to determine 

royalty, you must increase those gross 

proceeds to the extent that the 

purchaser, or any other person, provides 

certain services that you normally are 

responsible to perform to place the gas, 

residue gas, and gas plant products in 

marketable condition or to market the 

gas. 

§ 1206.147 When is an ONRR audit, review, 

reconciliation, monitoring, or other like 

process considered final? 

Notwithstanding any provision in 

these regulations to the contrary, ONRR 

does not consider any audit, review, 

reconciliation, monitoring, or other like 

process that results in ONRR 

redetermining royalty due, under this 

subpart, final or binding as against the 

Federal Government or its beneficiaries 

unless ONRR chooses to formally close 

the audit period in writing. 

§ 1206.148 How do I request a valuation 

determination or guidance? 

(a) You may request a valuation 

determination or guidance from ONRR 

regarding any gas produced. Your 

request must: 

(1) Be in writing; 

(2) Identify specifically all leases 

involved, all interest owners of those 


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leases, the designee(s), and the 

operator(s) for those leases; 

(3) Completely explain all relevant 

facts. You must inform ONRR of any 

changes to relevant facts that occur 

before we respond to your request; 

(4) Include copies of all relevant 

documents; 

(5) Provide your analysis of the 

issue(s), including citations to all 

relevant precedents (including adverse 

precedents); and 

(6) Suggest your proposed valuation 

method. 

(b) In response to your request, ONRR 

may: 

(1) Request that the Assistant 

Secretary for Policy, Management and 

Budget issue a determination; or 

(2) Decide that ONRR will issue 

guidance; or 

(3) Inform you in writing that ONRR 

will not provide a determination or 

guidance. Situations in which ONRR 

typically will not provide any 

determination or guidance include, but 

are not limited to: 

(i) Requests for guidance on 

hypothetical situations; and 

(ii) Matters that are the subject of 

pending litigation or administrative 

appeals. 

(c)(1) A determination the Assistant 

Secretary for Policy, Management and 

Budget signs is binding on both you and 

ONRR until the Assistant Secretary 

modifies or rescinds it. 

(2) After the Assistant Secretary issues 

a determination, you must make any 

adjustments to royalty payments that 

follow from the determination and, if 

you owe additional royalties, you must 

pay the additional royalties due, plus 

late payment interest calculated under 

§§ 1218.54 and 1218.102 of this chapter. 

(3) A determination the Assistant 

Secretary signs is the final action of the 

Department and is subject to judicial 

review under 5 U.S.C. 701–706. 

(d) Guidance ONRR issues is not 

binding on ONRR, delegated States, or 

you with respect to the specific 

situation addressed in the guidance. 

(1) Guidance and ONRR’s decision 

whether or not to issue guidance or 

request an Assistant Secretary 

determination, or neither, under 

paragraph (b) of this section, are not 

appealable decisions or orders under 30 

CFR part 1290. 

(2) If you receive an order requiring 

you to pay royalty on the same basis as 

the guidance, you may appeal that order 

under 30 CFR part 1290. 

(e) ONRR or the Assistant Secretary 

may use any of the applicable criteria in 

this subpart to provide guidance or 

make a determination. 

(f) A change in an applicable statute 

or regulation on which ONRR based any 

guidance, or the Assistant Secretary 

based any determination, takes 

precedence over the determination or 

guidance after the effective date of the 

statute or regulation, regardless of 

whether ONRR or the Assistant 

Secretary modifies or rescinds the 

guidance or determination. 

(g) ONRR may make requests and 

replies under this section available to 

the public, subject to the confidentiality 

requirements under § 1206.149. 

§ 1206.149 Does ONRR protect information 

I provide? 

(a) Certain information you or your 

affiliate submit(s) to ONRR regarding 

royalties on gas, including deductions 

and allowances, may be exempt from 

disclosure. 

(b) To the extent applicable laws and 

regulations permit, ONRR will keep 

confidential any data you or your 

affiliate submit(s) that is privileged, 

confidential, or otherwise exempt from 

disclosure. 

(c) You and others must submit all 

requests for information under the 

Freedom of Information Act regulations 

of the Department of the Interior at 43 

CFR part 2. 

§ 1206.150 How do I determine royalty 

quantity and quality? 

(a)(1) You must calculate royalties 

based on the quantity and quality of 

unprocessed gas as measured at the 

point of royalty settlement that BLM or 

BSEE approves for onshore leases and 

OCS leases, respectively. 

(2) If you base the value of gas 

determined under this subpart on a 

quantity and/or quality that is different 

from the quantity and/or quality at the 

point of royalty settlement that BLM or 

BSEE approves, you must adjust that 

value for the differences in quantity 

and/or quality. 

(b)(1) For residue gas and gas plant 

products, the quantity basis for 

computing royalties due is the monthly 

net output of the plant, even though 

residue gas and/or gas plant products 

may be in temporary storage. 

(2) If you value residue gas and/or gas 

plant products determined under this 

subpart on a quantity and/or quality of 

residue gas and/or gas plant products 

that is different from that which is 

attributable to a lease determined under 

paragraph (c) of this section, you must 

adjust that value for the differences in 

quantity and/or quality. 

(c) You must determine the quantity 

of the residue gas and gas plant 

products attributable to a lease based on 

the following procedure: 

(1) When you derive the net output of 

the processing plant from gas obtained 

from only one lease, you must base the 

quantity of the residue gas and gas plant 

products for royalty computation on the 

net output of the plant. 

(2) When you derive the net output of 

a processing plant from gas obtained 

from more than one lease producing gas 

of uniform content, you must base the 

quantity of the residue gas and gas plant 

products allocable to each lease on the 

same proportions as the ratios obtained 

by dividing the amount of gas delivered 

to the plant from each lease by the total 

amount of gas delivered from all leases. 

(3) When the net output of a 

processing plant is derived from gas 

obtained from more than one lease 

producing gas of non-uniform content: 

(i) You must determine the quantity of 

the residue gas allocable to each lease 

by multiplying the amount of gas 

delivered to the plant from the lease by 

the residue gas content of the gas, and 

dividing that arithmetical product by 

the sum of the similar arithmetical 

products separately obtained for all 

leases from which gas is delivered to the 

plant, and then multiplying the net 

output of the residue gas by the 

arithmetic quotient obtained. 

(ii) You must determine the net 

output of gas plant products allocable to 

each lease by multiplying the amount of 

gas delivered to the plant from the lease 

by the gas plant product content of the 

gas, and dividing that arithmetical 

product by the sum of the similar 

arithmetical products separately 

obtained for all leases from which gas is 

delivered to the plant, and then 

multiplying the net output of each gas 

plant product by the arithmetic quotient 

obtained. 

(4) You may request prior ONRR 

approval of other methods for 

determining the quantity of residue gas 

and gas plant products allocable to each 

lease. If approved, you must apply that 

method to all gas production from 

Federal leases that is processed in the 

same plant beginning with the 

production month following the month 

ONRR received your request to use 

another method. 

(d)(1) You may not make any 

deductions from the royalty volume or 

royalty value for actual or theoretical 

losses. Any actual loss of unprocessed 

gas that you sustain before the royalty 

settlement meter or measurement point 

is not subject to royalty; if BLM or 

BSEE, whichever is appropriate, 

determines that such loss was 

unavoidable. 

(2) Except as provided in paragraph 

(d)(1) of this section and § 1202.151(c), 

you must pay royalties due on 100 

percent of the volume determined under 

paragraphs (a) through (c) of this 


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section. You may not reduce that 

determined volume for actual losses 

after you have determined the quantity 

basis, or for theoretical losses that you 

claim to have taken place. Royalties are 

due on 100 percent of the value of the 

unprocessed gas, residue gas, and/or gas 

plant products, as provided in this 

subpart, less applicable allowances. You 

may not take any deduction from the 

value of the unprocessed gas, residue 

gas, and/or gas plant products to 

compensate for actual losses after you 

have determined the quantity basis or 

for theoretical losses that you claim to 

have taken place. 

§ 1206.151 How do I perform accounting 

for comparison? 

(a) Except as provided in paragraph 

(b) of this section, if you or your affiliate 

(or a person to whom you have 

transferred gas under a non-arm’s-length 

contract or without a contract) processes 

your or your affiliate’s gas and after 

processing the gas, you or your affiliate 

do not sell the residue gas under an 

arm’s-length contract, the value, for 

royalty purposes, will be the greater of: 

(1) The combined value, for royalty 

purposes, of the residue gas and gas 

plant products resulting from processing 

the gas determined under § 1206.142 of 

this subpart, plus the value, for royalty 

purposes, of any condensate recovered 

downstream of the point of royalty 

settlement without resorting to 

processing determined under § 1206.102 

of this subpart; or 

(2) The value, for royalty purposes, of 

the gas prior to processing as 

determined under § 1206.141 of this 

subpart. 

(b) The requirement for accounting for 

comparison contained in the terms of 

leases will govern as provided in 

§ 1206.142(a)(2) of this subpart. 

(c) When lease terms require 

accounting for comparison, you must 

perform accounting for comparison 

under paragraph (a) of this section. 

§ 1206.152 What general transportation 

allowance requirements apply to me? 

(a) 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 the lease under § 1206.153 or 

§ 1206.154, as applicable. You may not 

deduct transportation costs you incur to 

move a particular volume of production 

to reduce royalties you owe on 

production for which you did not incur 

those costs. This paragraph applies 

when: 

(1) 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 the lease, 

unit, or communitized area where the 

residue gas, gas plant products, or 

unprocessed gas is produced; and 

(2)(i) The movement to the sales point 

is not gathering. 

(ii) For gas produced on the OCS, the 

movement of gas from the wellhead to 

the first platform is not transportation. 

(b) You must calculate the deduction 

for transportation costs based on your or 

your affiliate’s cost of transporting each 

product through each individual 

transportation system. If your or your 

affiliate’s transportation contract 

includes more than one product in a 

gaseous phase, you must allocate costs 

consistently and equitably to each of the 

products transported. Your allocation 

must use the same proportion as the 

ratio of the volume of each product 

(excluding waste products with no 

value) to the volume of all products in 

the gaseous phase (excluding waste 

products with no value). 

(1) You may not take an allowance for 

transporting lease production that is not 

royalty-bearing. 

(2) You may propose to ONRR a 

prospective cost allocation method 

based on the values of the products 

transported. ONRR will approve the 

method, if it is consistent with the 

purposes of the regulations in this 

subpart. 

(3) You may use your proposed 

procedure to calculate a transportation 

allowance beginning with the 

production month following the month 

ONRR received your proposed 

procedure until ONRR accepts or rejects 

your cost allocation. If ONRR rejects 

your cost allocation, you must amend 

your Form ONRR–2014 for the months 

that you used the rejected method and 

pay any additional royalty due, plus late 

payment interest calculated under 

§§ 1218.54 and 1218.102 of this chapter. 

(c)(1) Where you or your affiliate 

transport(s) both gaseous and liquid 

products through the same 

transportation system, you must 

propose a cost allocation procedure to 

ONRR. 

(2) You may use your proposed 

procedure to calculate a transportation 

allowance until ONRR accepts or rejects 

your cost allocation. If ONRR rejects 

your cost allocation, you must amend 

your Form ONRR–2014 for the months 

that you used the rejected method and 

pay any additional royalty due, plus late 

payment interest calculated under 

§§ 1218.54 and 1218.102 of this chapter. 

(3) You must submit your initial 

proposal, including all available data, 

within 3 months after you first claim the 

allocated deductions on Form ONRR– 

2014. 

(d) If you value unprocessed gas 

under § 1206.141(c) or residue gas and 

gas plant products under § 1206.142 (d), 

you may not take a transportation 

allowance. 

(e)(1) Your transportation allowance 

may not exceed 50 percent of the value 

of the residue gas, gas plant products, or 

unprocessed gas as determined under 

§ 1206.141 or § 1206.142 of this subpart. 

(2) If ONRR approved your request to 

take a transportation allowance in 

excess of the 50-percent limitation 

under former § 1206.156(c)(3), that 

approval is terminated as of the effective 

date of the final rule. 

(f) You must express transportation 

allowances for residue gas, gas plant 

products, or unprocessed gas as a dollarvalue equivalent. If your or your 

affiliate’s payments for transportation 

under a contract are not on a dollar-perunit basis, you must convert whatever 

consideration you or your affiliate are 

paid to a dollar-value equivalent. 

(g) ONRR may determine your 

transportation allowance under 

§ 1206.144 because: 

(1) There is misconduct by or between 

the contracting parties; 

(2) ONRR determines that the 

consideration 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 

by transporting your gas, residue gas, or 

gas plant products at a cost that is 

unreasonably high. We may consider a 

transportation allowance unreasonably 

high if it is 10-percent higher than the 

highest reasonable measures of 

transportation costs including, but not 

limited to, transportation allowances 

reported to ONRR and tariffs for gas, 

residue gas, or gas plant products 

transported through the same system; or 

(3) ONRR cannot determine if you 

properly calculated a transportation 

allowance under § 1206.153 or 

§ 1206.154 for any reason, including but 

not limited to, you or your affiliate’s 

failure to provide documents ONRR 

requests under 30 CFR part 1212, 

subpart B. 

(h) You do not need ONRR approval 

before reporting a transportation 

allowance. 

§ 1206.153 How do I determine a 

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

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

transportation costs under an arm’slength transportation contract, you may 

claim a transportation allowance for the 

reasonable, actual costs incurred as 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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more fully explained in paragraph (b) of 

this section, except as provided in 

§ 1206.152(g) and subject to the 

limitation in § 1206.152(e). 

(2) You must be able to demonstrate 

that your or your affiliate’s contract is 

arm’s-length. 

(b) Subject to the requirements of 

paragraph (c) of this section, you may 

include, but are not limited to, the 

following costs to determine your 

transportation allowance under 

paragraph (a) of this section. You may 

not use any cost as a deduction that 

duplicates all or part of any other cost 

that you use under this section. 

(1) Firm demand charges paid to 

pipelines. You may deduct firm demand 

charges or capacity reservation fees you 

or your affiliate paid to a pipeline, 

including charges or fees for unused 

firm capacity you or your affiliate have 

not sold before you report your 

allowance. If you or your affiliate 

receive(s) a payment from any party for 

release or sale of firm capacity after 

reporting a transportation allowance 

that included the cost of that unused 

firm capacity, or if you or your affiliate 

receive(s) a payment or credit from the 

pipeline for penalty refunds, rate case 

refunds, or other reasons, you must 

reduce the firm demand charge claimed 

on the Form ONRR–2014 by the amount 

of that payment. You must modify the 

Form ONRR–2014 by the amount 

received or credited for the affected 

reporting period, and pay any resulting 

royalty due, plus late payment interest 

calculated under §§ 1218.54 and 

1218.102 of this chapter; 

(2) Gas supply realignment (GSR) 

costs. The GSR costs result from a 

pipeline reforming or terminating 

supply contracts with producers to 

implement the restructuring 

requirements of FERC Orders in 18 CFR 

part 284; 

(3) Commodity charges. The 

commodity charge allows the pipeline 

to recover the costs of providing service; 

(4) Wheeling costs. Hub operators 

charge a wheeling cost for transporting 

gas from one pipeline to either the same 

or another pipeline through a market 

center or hub. A hub is a connected 

manifold of pipelines through which a 

series of incoming pipelines are 

interconnected to a series of outgoing 

pipelines; 

(5) Gas Research Institute (GRI) fees. 

The GRI conducts research, 

development, and commercialization 

programs on natural gas related topics 

for the benefit of the U.S. gas industry 

and gas customers. GRI fees are 

allowable provided such fees are 

mandatory in FERC-approved tariffs; 

(6) Annual Charge Adjustment (ACA) 

fees. FERC charges these fees to 

pipelines to pay for its operating 

expenses; 

(7) Payments (either volumetric or in 

value) for actual or theoretical losses. 

However, theoretical losses are not 

deductible in transportation 

arrangements unless the transportation 

allowance is based on arm’s-length 

transportation rates charged under a 

FERC- or State regulatory-approved 

tariff, or ONRR approves your use of a 

FERC or State regulatory-approved tariff 

as an exception from the requirement to 

calculate actual costs under 

§ 1206.154(l) of this subpart. If you or 

your affiliate receive(s) volumes or 

credit for line gain, you must reduce 

your transportation allowance 

accordingly and pay any resulting 

royalties, plus late payment interest 

calculated under §§ 1218.54 and 

1218.102 of this chapter; 

(8) Temporary storage services. This 

includes short duration storage services 

offered by market centers or hubs 

(commonly referred to as ‘‘parking’’ or 

‘‘banking’’), or other temporary storage 

services provided by pipeline 

transporters, whether actual or provided 

as a matter of accounting. Temporary 

storage is limited to 30 days or less; 

(9) Supplemental costs for 

compression, dehydration, and 

treatment of gas. ONRR allows these 

costs only if such services are required 

for transportation and exceed the 

services necessary to place production 

into marketable condition required 

under § 1206.146 of this part; 

(10) Costs of surety. You may deduct 

the costs of securing a letter of credit, or 

other surety, that the pipeline requires 

you or your affiliate as a shipper to 

maintain under a transportation 

contract; and 

(11) Hurricane Surcharges. You may 

deduct hurricane surcharges you or your 

affiliate actually pay(s). 

(c) You may not include the following 

costs to determine your transportation 

allowance under paragraph (a) of this 

section: 

(1) Fees or costs incurred for storage. 

This includes storing production in a 

storage facility, whether on or off the 

lease, for more than 30 days; 

(2) Aggregator/marketer fees. This 

includes fees you or your affiliate pay(s) 

to another person (including your 

affiliates) to market your gas, including 

purchasing and reselling the gas, or 

finding or maintaining a market for the 

gas production; 

(3) Penalties you or your affiliate 

incur(s) as shipper. These penalties 

include, but are not limited to: 

(i) Over-delivery cash-out penalties. 

This includes the difference between 

the price the pipeline pays you or your 

affiliate for over-delivered volumes 

outside the tolerances and the price you 

or your affiliate receive(s) for overdelivered volumes within the 

tolerances; 

(ii) Scheduling penalties. This 

includes penalties you or your affiliate 

incur(s) for differences between daily 

volumes delivered into the pipeline and 

volumes scheduled or nominated at a 

receipt or delivery point; 

(iii) Imbalance penalties. This 

includes penalties you or your affiliate 

incur(s) (generally on a monthly basis) 

for differences between volumes 

delivered into the pipeline and volumes 

scheduled or nominated at a receipt or 

delivery point; and 

(iv) Operational penalties. This 

includes fees you or your affiliate 

incur(s) for violation of the pipeline’s 

curtailment or operational orders issued 

to protect the operational integrity of the 

pipeline. 

(4) Intra-hub transfer fees. These are 

fees you or your affiliate pay(s) to hub 

operators for administrative services 

(e.g., title transfer tracking) necessary to 

account for the sale of gas within a hub; 

(5) Fees paid to brokers. This includes 

fees you or your affiliate pay(s) to 

parties who arrange marketing or 

transportation, if such fees are 

separately identified from aggregator/

marketer fees; 

(6) Fees paid to scheduling service 

providers. This includes fees you or 

your affiliate pay(s) to parties who 

provide scheduling services, if such fees 

are separately identified from 

aggregator/marketer fees; 

(7) Internal costs. This includes 

salaries and related costs, rent/space 

costs, office equipment costs, legal fees, 

and other costs to schedule, nominate, 

and account for sale or movement of 

production; and 

(8) Other nonallowable costs. Any 

cost you or your affiliate incur(s) for 

services you are required to provide at 

no cost to the lessor, including but not 

limited to, costs to place your gas, 

residue gas, or gas plant products into 

marketable condition disallowed under 

§ 1206.146 and costs of boosting residue 

gas disallowed under 30 CFR 

1202.151(b). 

(d) If you have no written contract for 

the transportation of gas, then ONRR 

will determine your transportation 

allowance under § 1206.144. You may 

not use this paragraph (d), if you or your 

affiliate perform(s) your own 

transportation. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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(1) You must propose to ONRR a 

method to determine the allowance 

using the procedures in § 1206.148(a). 

(2) You may use that method to 

determine your allowance until ONRR 

issues its determination. 

§ 1206.154 How do I determine a 

transportation allowance if I have a nonarm’s-length transportation contract? 

(a) This section applies if you or your 

affiliate do(es) not have an arm’s-length 

transportation contract, including 

situations where you or your affiliate 

provide your own transportation 

services. You must calculate your 

transportation allowance based on your 

or your affiliate’s reasonable, actual 

costs for transportation during the 

reporting period using the procedures 

prescribed in this section. 

(b) Your or your affiliate’s actual costs 

may include: 

(1) Capital costs and operating and 

maintenance expenses under paragraphs 

(e), (f), and (g) of this section; 

(2) Overhead under paragraph (h) of 

this section; 

(3) Depreciation and a return on 

undepreciated capital investment under 

paragraph (i)(1) of this section, or you 

may elect to use a cost equal to a return 

on the initial depreciable capital 

investment in the transportation system 

under paragraph (i)(2) of this section. 

After you have elected to use either 

method for a transportation system, you 

may not later elect to change to the 

other alternative without ONRR 

approval. If ONRR accepts your request 

to change methods, you may use your 

changed method beginning with the 

production month following the month 

ONRR received your change request; 

and 

(4) A return on the reasonable salvage 

value under paragraph (i)(1)(iii) of this 

section, after you have depreciated the 

transportation system to its reasonable 

salvage value. 

(c)(1) To the extent not included in 

costs identified in paragraphs (e) 

through (g) of this section, if you or your 

affiliate incur(s) the actual 

transportation costs listed under 

§ 1206.153(b)(2), (5), and (6) of this 

subpart under your or your affiliate’s 

non-arm’s-length contract, you may 

include those costs in your calculations 

under this section. You may not include 

any of the other costs identified under 

§ 1206.153 (b); and 

(2) You may not include in your 

calculations under this section any of 

the nonallowable costs listed under 

§ 1206.153(c). 

(d) You may not use any cost as a 

deduction that duplicates all or part of 

any other cost that you use under this 

section. 

(e) Allowable capital investment costs 

are generally those for depreciable fixed 

assets (including costs of delivery and 

installation of capital equipment) that 

are an integral part of the transportation 

system. 

(f) Allowable operating expenses 

include: 

(1) Operations supervision and 

engineering; 

(2) Operations labor; 

(3) Fuel; 

(4) Utilities; 

(5) Materials; 

(6) Ad valorem property taxes; 

(7) Rent; 

(8) Supplies; and 

(9) Any other directly allocable and 

attributable operating expense that you 

can document. 

(g) Allowable maintenance expenses 

include: 

(i) Maintenance of the transportation 

system; 

(ii) Maintenance of equipment; 

(iii) Maintenance labor; and 

(iv) Other directly allocable and 

attributable maintenance expenses that 

you can document. 

(h) Overhead, directly attributable and 

allocable to the operation and 

maintenance of the transportation 

system, is an allowable expense. State 

and Federal income taxes and severance 

taxes and other fees, including royalties, 

are not allowable expenses. 

(i)(1) To calculate depreciation and a 

return on undepreciated capital 

investment, you may elect to use either 

a straight-line depreciation method 

based on the life of equipment or on the 

life of the reserves that the 

transportation system services, or a unit 

of production method. After you make 

an election, you may not change 

methods without ONRR approval. If 

ONRR accepts your request to change 

methods, you may use your changed 

method beginning with the production 

month following the month ONRR 

received your change request. 

(i) A change in ownership of a 

transportation system will not alter the 

depreciation schedule the original 

transporter/lessee established for 

purposes of the allowance calculation. 

(ii) You may depreciate a 

transportation system only once with or 

without a change in ownership. 

(iii)(A) To calculate the return on 

undepreciated capital investment, you 

may use an amount equal to the 

undepreciated capital investment in the 

transportation system multiplied by the 

rate of return you determine under 

paragraph (i)(3) of this section. 

(B) After you have depreciated a 

transportation system to the reasonable 

salvage value, you may continue to 

include in the allowance calculation a 

cost equal to the reasonable salvage 

value multiplied by a rate of return 

under paragraph (i)(3) of this section. 

(2) As an alternative to using 

depreciation and a return on 

undepreciated capital investment, as 

provided under paragraph (b)(3) of this 

section, you may use as a cost an 

amount equal to the allowable initial 

capital investment in the transportation 

system multiplied by the rate of return 

determined under paragraph (i)(3) of 

this section. You may not include 

depreciation in your allowance. 

(3) The rate of return is the industrial 

rate associated with Standard & Poor’s 

BBB rating. 

(i) You must use the monthly average 

that BBB rate Standard & Poor’s 

publishes for the first month for which 

the allowance is applicable. 

(ii) You must redetermine the rate at 

the beginning of each subsequent 

calendar year. 

§ 1206.155 What are my reporting 

requirements under an arm’s-length 

transportation contract? 

(a) You must use a separate entry on 

Form ONRR–2014 to notify ONRR of an 

allowance based on transportation costs 

you or your affiliate incur(s). 

(b) ONRR may require you or your 

affiliate to submit arm’s-length 

transportation contracts, production 

agreements, operating agreements, and 

related documents. 

(c) You can find recordkeeping 

requirements in parts 1207 and 1212 of 

this chapter. 

§ 1206.156 What are my reporting 

requirements under a non-arm’s-length 

transportation contract? 

(a) You must use a separate entry on 

Form ONRR–2014 to notify ONRR of an 

allowance based on non-arm’s-length 

transportation costs you or your affiliate 

incur(s). 

(b)(1) For new non-arm’s-length 

transportation facilities or arrangements, 

you must base your initial deduction on 

estimates of allowable transportation 

costs for the applicable period. 

(2) You must use your or your 

affiliate’s most recently available 

operations data for the transportation 

system as your estimate. If such data is 

not available, you must use estimates 

based on data for similar transportation 

systems. 

(3) Section 1206.158 applies when 

you amend your report based on your 

actual costs. 

(c) ONRR may require you or your 

affiliate to submit all data used to 

calculate the allowance deduction. You 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 661 

can find recordkeeping requirements in 

parts 1207 and 1212 of this chapter. 

(d) If you are authorized under 

§ 1206.154(j) to use an exception to the 

requirement to calculate your actual 

transportation costs, you must follow 

the reporting requirements of 

§ 1206.155. 

§ 1206.157 What interest and penalties 

apply if I improperly report a transportation 

allowance? 

(a)(1) If ONRR determines that you 

took an unauthorized transportation 

allowance, then you must pay any 

additional royalties due, plus late 

payment interest calculated under 

§§ 1218.54 and 1218.102 of this chapter. 

(2) If you understated your 

transportation allowance, you may be 

entitled to a credit with interest. 

(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, 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 due. 

(c) If you improperly net a 

transportation allowance against the 

sales value of the residue gas, gas plant 

products, or unprocessed gas instead of 

reporting the allowance as a separate 

entry on Form ONRR–2014, ONRR may 

assess a civil penalty under 30 CFR part 

1241. 

§ 1206.158 What reporting adjustments 

must I make for transportation allowances? 

(a) If your actual transportation 

allowance is less than the amount you 

claimed on Form ONRR–2014 for each 

month during the allowance reporting 

period, you must pay additional 

royalties due, plus late payment interest 

calculated under §§ 1218.54 and 

1218.102 of this chapter from the date 

you took the deduction to the date you 

repay the difference. 

(b) If the actual transportation 

allowance is greater than the amount 

you claimed on Form ONRR–2014 for 

any month during the period reported 

on the allowance form, you are entitled 

to a credit plus interest. 

§ 1206.159 What general processing 

allowances requirements apply to me? 

(a)(1) When you value any gas plant 

product under § 1206.142(c) of this 

subpart, you may deduct from value the 

reasonable actual costs of processing. 

(2) You do not need ONRR approval 

before reporting a processing allowance. 

(b) You must allocate processing costs 

among the gas plant products. You must 

determine a separate processing 

allowance for each gas plant product 

and processing plant relationship. 

ONRR considers NGLs one product. 

(c)(1) You may not apply the 

processing allowance against the value 

of the residue gas. 

(2) The processing allowance 

deduction on the basis of an individual 

product may not exceed 662⁄3 percent of 

the value of each gas plant product 

determined under § 1206.142(c). Before 

you calculate the 662⁄3 percent limit, 

you must first reduce the value for any 

transportation allowances related to 

post-processing transportation 

authorized under § 1206.152. 

(3) If ONRR approved your request to 

take a processing allowance in excess of 

the limitation in paragraph (c)(2) of this 

section under former § 1206.158(c)(3), 

that approval is terminated as of 

[EFFECTIVE DATE OF FINAL RULE]. 

(4) If ONRR approved your request to 

take an extraordinary cost processing 

allowance under former § 1206.158(d), 

ONRR terminates that approval as of 

[EFFECTIVE DATE OF FINAL RULE]. 

(d)(1) ONRR will not allow a 

processing cost deduction for the costs 

of placing lease products in marketable 

condition, including dehydration, 

separation, compression, or storage, 

even if those functions are performed off 

the lease or at a processing plant. 

(2) Where gas is processed for the 

removal of acid gases, commonly 

referred to as ‘‘sweetening,’’ ONRR will 

not allow processing cost deductions for 

such costs unless the acid gases 

removed are further processed into a gas 

plant product. 

(A) In such event, you are eligible for 

a processing allowance determined 

under this subpart. 

(B) ONRR will not grant any 

processing allowance for processing 

lease production that is not royalty 

bearing. 

§ 1206.160 How do I determine a 

processing allowance, if I have an arm’slength 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 

paragraphs (a)(3)(1) and (a)(3)(ii) of this 

section and subject to the limitation in 

§ 1206.159(c)(2). 

(2) You must be able to demonstrate 

that your or your affiliate’s contract is 

arm’s length. 

(3) ONRR may determine your 

processing allowance under § 1206.144, 

if: 

(i) ONRR determines that your or your 

affiliate’s contract reflects more than the 

consideration actually transferred either 

directly or indirectly from you or your 

affiliate to the processor for processing; 

or 

(ii) ONRR determines that the 

consideration 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 for 

the mutual benefit of yourself and the 

lessor by processing your gas at a cost 

that is unreasonably high. We may 

consider a processing allowance 

unreasonably high, if it is 10-percent 

higher than the highest reasonable 

measures of processing costs, including 

but not limited to processing allowances 

reported to ONRR for gas processed in 

the same plant or area. 

(b)(1) If your or your affiliate’s arm’slength processing contract includes 

more than one gas plant product and 

you can determine the processing costs 

for each product based on the contract, 

then you must determine the processing 

costs for each gas plant product under 

the contract. 

(2) If your or your affiliate’s arm’slength processing contract includes 

more than one gas plant product and 

you cannot determine the processing 

costs attributable to each product from 

the contract, you must propose an 

allocation procedure to ONRR. 

(i) You may use your proposed 

allocation procedure until ONRR issues 

its determination. 

(ii) You must submit all relevant data 

to support your proposal. 

(iii) ONRR will determine the 

processing allowance based upon your 

proposal and any additional information 

ONRR deems necessary. 

(iv) You must submit the allocation 

proposal within 3 months of claiming 

the allocated deduction on Form 

ONRR–2014. 

(3) You may not take an allowance for 

the costs of processing lease production 

that is not royalty-bearing. 

(4) If your or your affiliate’s payments 

for processing under an arm’s-length 

contract are not based on a dollar-perunit basis, you must convert whatever 

consideration you or your affiliate paid 

to a dollar-value equivalent. 

(c) If you have no written contract for 

the arm’s-length processing of gas, then 

ONRR will determine your processing 

allowance under § 1206.144. You may 

not use this paragraph (c) if you or your 

affiliate perform(s) your own processing. 

(1) You must propose to ONRR a 

method to determine the allowance 

using the procedures in § 1206.148(a). 

(2) You may use that method to 

determine your allowance until ONRR 

issues a determination. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
662 Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 

§ 1206.161 How do I determine a 

processing allowance if I have a non-arm’slength processing contract? 

(a) This section applies if you or your 

affiliate do(es) not have an arm’s-length 

processing contract, including situations 

where you or your affiliate provide your 

own processing services. You must 

calculate your processing allowance 

based on you or your affiliate’s 

reasonable, actual costs for processing 

during the reporting period using the 

procedures prescribed in this section. 

(b) You or your affiliate’s actual costs 

include the following: 

(1) Capital costs and operating and 

maintenance expenses under paragraphs 

(d), (e), and (f) of this section; 

(2) Overhead under paragraph (g) of 

this section; 

(3) Depreciation and a return on 

undepreciated capital investment in 

accordance with paragraph (h)(1) of this 

section, or you may elect to use a cost 

equal to the initial depreciable capital 

investment in the processing plant 

under paragraph (h)(2) of this section. 

After you have elected to use either 

method for a processing plant, you may 

not later elect to change to the other 

alternative without ONRR approval. If 

ONRR accepts your request to change 

methods, you may use your changed 

method beginning with the production 

month following the month ONRR 

received your change request; and 

(4) A return on the reasonable salvage 

value under paragraph (h)(1)(iii) of this 

section, after you have depreciated the 

processing plant to its reasonable 

salvage value. 

(c) You may not use any cost as a 

deduction that duplicates all or part of 

any other cost that you use under this 

section. 

(d) Allowable capital investment costs 

are generally those for depreciable fixed 

assets (including costs of delivery and 

installation of capital equipment), 

which are an integral part of the 

processing plant. 

(e) Allowable operating expenses 

include: 

(1) Operations supervision and 

engineering; 

(2) Operations labor; 

(3) Fuel; 

(4) Utilities; 

(5) Materials; 

(6) Ad valorem property taxes; 

(7) Rent; 

(8) Supplies; and 

(9) Any other directly allocable and 

attributable operating expense that you 

can document. 

(f) Allowable maintenance expenses 

include: 

(1) Maintenance of the processing 

plant; 

(2) Maintenance of equipment; 

(3) Maintenance labor; and 

(4) Other directly allocable and 

attributable maintenance expenses that 

you can document. 

(g) Overhead, directly attributable and 

allocable to the operation and 

maintenance of the processing plant, is 

an allowable expense. State and Federal 

income taxes and severance taxes and 

other fees, including royalties, are not 

allowable expenses. 

(h)(1) To calculate depreciation and a 

return on undepreciated capital 

investment, you may elect to use either 

a straight-line depreciation method 

based on the life of equipment or on the 

life of the reserves which the processing 

plant services, or a unit-of-production 

method. After you make an election, 

you may not change methods without 

ONRR approval. If ONRR accepts your 

request to change methods, you may use 

your changed method beginning with 

the production month following the 

month ONRR received your change 

request. 

(i) A change in ownership of a 

processing plant will not alter the 

depreciation schedule that the original 

processor/lessee established for 

purposes of the allowance calculation. 

(ii) You may depreciate a processing 

plant only once with or without a 

change in ownership. 

(iii)(A) To calculate a return on 

undepreciated capital investment, you 

may use an amount equal to the 

undepreciated capital investment in the 

processing plant multiplied by the rate 

of return you determine under 

paragraph (h)(3) of this section. 

(B) After you have depreciated a 

processing plant to its reasonable 

salvage value, you may continue to 

include in the allowance calculation a 

cost equal to the reasonable salvage 

value multiplied by a rate of return 

under paragraph (h)(3) of this section. 

(2) You may use as a cost an amount 

equal to the allowable initial capital 

investment in the processing plant 

multiplied by the rate of return 

determined under paragraph (h)(3) of 

this section. You may not include 

depreciation in your allowance. 

(3) The rate of return is the industrial 

rate associated with Standard & Poor’s 

BBB rating. 

(i) You must use the monthly average 

that BBB rate Standard & Poor’s 

publishes for the first month for which 

the allowance is applicable. 

(ii) You must redetermine the rate at 

the beginning of each subsequent 

calendar year. 

(i)(1) You must determine the 

processing allowance for each gas plant 

product based on your or your affiliate’s 

reasonable and actual cost of processing 

the gas. You must base your allocation 

of costs to each gas plant product upon 

generally accepted accounting 

principles. 

(2) You may not take an allowance for 

processing lease production that is not 

royalty-bearing. 

(j) You may apply for an exception 

from the requirement to calculate actual 

costs under paragraphs (a) and (b) of 

this section. 

(1) ONRR will grant the exception, if: 

(i) You have or your affiliate has 

arm’s-length contracts for processing 

other gas production at the same 

processing plant; and 

(ii) At least 50-percent of the gas 

processed annually at the plant is 

processed under arm’s-length 

processing contracts. 

(2) If ONRR grants the exception, you 

must use as your processing allowance 

the volume-weighted average prices 

charged other persons under arm’slength contracts for processing at the 

same plant. 

§ 1206.162 What are my reporting 

requirements under an arm’s-length 

processing contract? 

(a) You must use a separate entry on 

Form ONRR–2014 to notify ONRR of an 

allowance based on arm’s-length 

processing costs you or your affiliate 

incur(s). 

(b) ONRR may require you or your 

affiliate to submit arm’s-length 

processing contracts, production 

agreements, operating agreements, and 

related documents. 

(c) You can find recordkeeping 

requirements in parts 1207 and 1212 of 

this chapter. 

§ 1206.163 What are my reporting 

requirements under a non-arm’s-length 

processing contract? 

(a) You must use a separate entry on 

Form ONRR–2014 to notify ONRR of an 

allowance based on non-arm’s-length 

processing costs you or your affiliate 

incur(s). 

(b)(1) For new non-arm’s-length 

processing facilities or arrangements, 

you must base your initial deduction on 

estimates of allowable gas processing 

costs for the applicable period. 

(2) You must use your or your 

affiliate’s most recently available 

operations data for the processing plant 

as your estimate, if available. If such 

data is not available, you must use 

estimates based on data for similar 

processing plants. 

(3) Section 1206.165 applies when 

you amend your report based on your 

actual costs. 

(c) ONRR may require you or your 

affiliate to submit all data used to 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 663 

calculate the allowance deduction. You 

can find recordkeeping requirements in 

parts 1207 and 1212 of this chapter. 

(d) If you are authorized under 

§ 1206.161(j) to use an exception to the 

requirement to calculate your actual 

processing costs, you must follow the 

reporting requirements of § 1206.162. 

§ 1206.164 What interest and penalties 

apply if I improperly report a processing 

allowance? 

(a)(1) If ONRR determines that you 

took an unauthorized processing 

allowance, then you must pay any 

additional royalties due, plus late 

payment interest calculated under 

§§ 1218.54 and 1218.102 of this chapter. 

(2) If you understated your processing 

allowance, you may be entitled to a 

credit with interest. 

(b) If you deduct a processing 

allowance on Form ONRR–2014 that 

exceeds 662⁄3 percent of the value of a 

gas plant product, 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 due. 

(c) If you improperly net a processing 

allowance against the sales value of a 

gas plant product instead of reporting 

the allowance as a separate entry on 

Form ONRR–2014, ONRR may assess a 

civil penalty under 30 CFR part 1241. 

§ 1206.165 What reporting adjustments 

must I make for processing allowances? 

(a) If your actual processing allowance 

is less than the amount you claimed on 

Form ONRR–2014 for each month 

during the allowance reporting period, 

you must pay additional royalties due, 

plus late payment interest calculated 

under §§ 1218.54 and 1218.102 of this 

chapter from the date you took the 

deduction to the date you repay the 

difference. 

(b) If the actual processing allowance 

is greater than the amount you claimed 

on Form ONRR–2014 for any month 

during the period reported on the 

allowance form, you are entitled to a 

credit plus interest. 

■ 8. Revise subpart F to read as follows: 

Subpart F—Federal Coal 

Sec. 

1206.250 What is the purpose and scope of 

this subpart? 

1206.251 How do I determine royalty 

quantity and quality? 

1206.252 How do I calculate royalty value 

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

arm’s-length or non-arm’s-length 

contract? 

1206.253 How will ONRR determine if my 

royalty payments are correct? 

1206.254 How will ONRR determine the 

value of my coal for royalty purposes? 

1206.255 What records must I keep to 

support my calculations of royalty under 

this subpart? 

1206.256 What are my responsibilities to 

place production into marketable 

condition and to market production? 

1206.257 When is an ONRR audit, review, 

reconciliation, monitoring, or other like 

process considered final? 

1206.258 How do I request a valuation 

determination or guidance? 

1206.259 Does ONRR protect information I 

provide? 

1206.260 What general transportation 

allowance requirements apply to me? 

1206.261 How do I determine a 

transportation allowance if I have an 

arm’s-length transportation contract or 

no written arm’s-length contract? 

1206.262 How do I determine a 

transportation allowance if I have a nonarm’s-length transportation contract? 

1206.263 What are my reporting 

requirements under an arm’s-length 

transportation contract? 

1206.264 What are my reporting 

requirements under a non-arm’s-length 

transportation contract? 

1206.265 What interest and penalties apply 

if I improperly report a transportation 

allowance? 

1206.266 What reporting adjustments must 

I make for transportation allowances? 

1206.267 What general washing allowance 

requirements apply to me? 

1206.268 How do I determine washing 

allowances if I have an arm’s-length 

washing contract or no written arm’slength contract? 

1206.269 How do I determine washing 

allowances if I have a non-arm’s-length 

washing contract? 

1206.270 What are my reporting 

requirements under an arm’s-length 

washing contract? 

1206.271 What are my reporting 

requirements under a non-arm’s-length 

washing contract? 

1206.272 What interest and penalties apply 

if I improperly report a washing 

allowance? 

1206.273 What reporting adjustments must 

I make for washing allowances? 

Subpart F—Federal Coal 

§ 1206.250 What is the purpose and scope 

of this subpart? 

(a) This subpart applies to all coal 

produced from Federal coal leases. It 

explains how you, as the lessee, must 

calculate the value of production for 

royalty purposes consistent with the 

mineral leasing laws, other applicable 

laws and lease terms. 

(b) The terms ‘‘you’’ and ‘‘your’’ in 

this subpart refer to the lessee. 

(c) If the regulations in this subpart 

are inconsistent with: 

(1) A Federal statute; 

(2) A settlement agreement between 

the United States and a lessee resulting 

from administrative or judicial 

litigation; 

(3) A written agreement between the 

lessee and the ONRR Director 

establishing a method to determine the 

value of production from any lease that 

ONRR expects, at least, would 

approximate the value established 

under this subpart; or 

(4) An express provision of a coal 

lease subject to this subpart, then the 

statute, settlement agreement, written 

agreement, or lease provision will 

govern to the extent of the 

inconsistency. 

(d) ONRR may audit and order you to 

adjust all royalty payments. 

§ 1206.251 How do I determine royalty 

quantity and quality? 

(a) You must calculate royalties based 

on the quantity and quality of coal at the 

royalty measurement point that ONRR 

and BLM jointly determine. 

(b) You must measure coal in short 

tons using the methods BLM prescribes 

for Federal coal leases under 43 CFR 

part 3000. You must report coal quantity 

on appropriate forms required in 30 CFR 

part 1210—Forms and Reports. 

(c)(1) You are not required to pay 

royalties on coal you produce and add 

to stockpiles or inventory until you use, 

sell, or otherwise finally dispose of such 

coal. 

(2) ONRR may request BLM to require 

you to increase your lease bond if BLM 

determines that stockpiles or inventory 

are excessive such that they increase the 

risk of resource degradation. 

(d) You must pay royalty at the rate 

specified in your lease at the time you 

use, sell, or otherwise finally dispose of 

the coal. 

(e) You must allocate washed coal by 

attributing the washed coal to the leases 

from which it was extracted. 

(1) If the wash plant washes coal from 

only one lease, the quantity of washed 

coal allocable to the lease is the total 

output of washed coal from the plant. 

(2) If the wash plant washes coal from 

more than one lease, you must 

determine the tonnage of washed coal 

attributable to each lease by: 

(i) First, calculating the input ratio of 

washed coal allocable to each lease by 

dividing the tonnage of coal you input 

to the wash plant from each lease by the 

total tonnage of coal input to the wash 

plant from all leases; and 

(ii) Then multiplying the input ratio 

derived under paragraph (e)(2)(i) of this 

section by the tonnage of total output of 

washed coal from the plant. 

§ 1206.252 How do I calculate royalty value 

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

arm’s-length or non-arm’s-length contract? 

(a) The value of coal under this 

section for royalty purposes is the gross 


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proceeds accruing to you or your 

affiliate under the first arm’s-length 

contract 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: 

(1) You sell under an arm’s-length 

contract; or 

(2) You sell or transfer to your affiliate 

or another person under a non-arm’slength contract, and that affiliate or 

person, or another affiliate of either of 

them, then sells the coal under an arm’slength contract. 

(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 you or your affiliate own(s) 

for the generation and sale of electricity 

and; 

(1) You or your affiliate sell(s) the 

electricity, then the value of the coal 

subject to this section, for royalty 

purposes, is the gross proceeds accruing 

to you for the power plant’s arm’slength sales of the electricity less 

applicable transportation and washing 

deductions determined under 

§§ 1206.260 through 1206.262 and 

§§ 1206.267 through 1206.269 of this 

subpart and, if applicable, transmission 

and generation deductions determined 

under §§ 1206.353 and 1206.352 of 

subpart H; 

(2) You or your affiliate do(es) not sell 

the electricity at arm’s length (i.e. you or 

your affiliate deliver(s) the electricity 

directly to the grid), then ONRR will 

determine the value of the coal under 

§ 1206.254. 

(i) You must propose to ONRR a 

method to determine the value using the 

procedures in § 1206.258(a). 

(ii) You may use that method to 

determine value, for royalty purposes, 

until ONRR issues a determination. 

(iii) After ONRR issues a 

determination, you must make the 

adjustments under § 1206.253(a)(2). 

(c) If you are a coal cooperative, or a 

member of a coal cooperative, and: 

(1) You sell or transfer coal to another 

member of the coal cooperative, and 

that member of the coal cooperative 

then sells the coal under an arm’s-length 

contract, then you must value the coal 

under paragraph (a) of this section; or 

(2) You sell or transfer coal to another 

member of the coal cooperative and the 

coal is used by you, the coal 

cooperative, or another member of the 

coal cooperative in a power plant for the 

generation and sale of electricity, then 

you must value the coal under 

paragraph (b) of this section. 

(d) If you are entitled to take a 

washing allowance and transportation 

allowance for royalty purposes under 

this section, under no circumstances 

may the washing allowance plus the 

transportation allowance reduce the 

royalty value of the coal to zero. 

(e) The values in this section do not 

apply, if ONRR decides to value your 

coal under § 1206.254. 

§ 1206.253 How will ONRR determine if my 

royalty payments are correct? 

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

audit the royalties 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, 

or decide your value, under § 1206.254. 

(2) If ONRR directs you to use a 

different royalty value, you must either 

pay any underpaid royalties due, plus 

late payment interest calculated under 

§ 1218.202 of this chapter or report a 

credit for, or request a refund of, any 

overpaid royalties. 

(b) When the provisions in this 

subpart refer to gross proceeds, in 

conducting reviews and audits, ONRR 

will examine if your or your affiliate’s 

contract reflects the total consideration 

actually transferred, either directly or 

indirectly, from the buyer to you or your 

affiliate for the coal. If ONRR 

determines that a contract does not 

reflect the total consideration, ONRR 

may decide your value under 

§ 1206.254. 

(c) ONRR may decide to value your 

coal under § 1206.254 if ONRR 

determines that the gross proceeds 

accruing to you or your affiliate under 

a contract do not reflect reasonable 

consideration because: 

(1) There is misconduct by or between 

the contracting parties; 

(2) You breached your duty to market 

the coal for the mutual benefit of 

yourself and the lessor by selling your 

coal at a value that is unreasonably low. 

ONRR may consider a sales price 

unreasonably low if it is 10-percent less 

than the lowest other reasonable 

measures of market price, including but 

not limited to, prices reported to ONRR 

for like-quality coal; or 

(3) ONRR cannot determine if you 

properly valued your coal under 

§ 1206.252 for any reason, including but 

not limited to, your or your affiliate’s 

failure to provide documents to ONRR 

under 30 CFR part 1212, subpart E. 

(d) You have the burden of 

demonstrating that your or your 

affiliate’s contract is arm’s length. 

(e) ONRR may require you to certify 

that the provisions in your or your 

affiliate’s contract include(s) all of the 

consideration the buyer paid you or 

your affiliate, either directly or 

indirectly, for the coal. 

(f)(1) Absent contract revision or 

amendment, if you or your affiliate 

fail(s) to take proper or timely action to 

receive prices or benefits to which you 

or your affiliate are entitled, you must 

pay royalty based upon that obtainable 

price or benefit. 

(2) If you or your affiliate make timely 

application for a price increase or 

benefit allowed under your or your 

affiliate’s contract, but the purchaser 

refuses, and you or your affiliate take 

reasonable documented measures to 

force purchaser compliance, you will 

not owe additional royalties unless or 

until you or your affiliate receive 

additional monies or consideration 

resulting from the price increase. You 

may not construe this paragraph to 

permit you to avoid your royalty 

payment obligation in situations where 

a purchaser fails to pay, in whole or in 

part, or timely, for a quantity of coal. 

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

all contracts, contract revisions, or 

amendments in writing, and all parties 

to the contract must sign the contract, 

contract revisions, or amendments. 

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

comply with paragraph (g)(1) of this 

section, ONRR may decide to value your 

coal under § 1206.254. 

(3) This provision applies 

notwithstanding any other provisions in 

this title 30 to the contrary. 

§ 1206.254 How will ONRR determine the 

value of my coal for royalty purposes? 

If ONRR decides to value your coal for 

royalty purposes under § 1206.254, or 

any other provision in this subpart, then 

ONRR will determine value by 

considering any information we deem 

relevant, which may include, but is not 

limited to: 

(a) The value of like-quality coal from 

the same mine, nearby mines, same 

region, or other regions, or washed in 

the same or nearby wash plant; 

(b) Public sources of price or market 

information that ONRR deems reliable, 

including but not limited to, the price 

of electricity; 

(c) Information available to ONRR and 

information reported to it, including but 

not limited to, on Form ONRR–4430; 

(d) Costs of transportation or washing, 

if ONRR determines they are applicable; 

or 

(e) Any other information ONRR 

deems relevant regarding the particular 

lease operation or the salability of the 

coal. 


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§ 1206.255 What records must I keep to 

support my calculations of royalty under 

this subpart? 

If you value your coal under this 

subpart, you must retain all data 

relevant to the determination of the 

royalty you paid. You can find 

recordkeeping requirements in parts 

1207 and 1212 of this chapter. 

(a) You must show: 

(1) How you calculated the royalty 

value, including all allowable 

deductions; and 

(2) How you complied with this 

subpart. 

(b) Upon request, you must submit all 

data to ONRR. You must comply with 

any such requirement within the time 

ONRR specifies. 

§ 1206.256 What are my responsibilities to 

place production into marketable condition 

and to market production? 

(a) You must place coal in marketable 

condition and market the coal for the 

mutual benefit of the lessee and the 

lessor at no cost to the Federal 

Government. 

(b) If you use gross proceeds under an 

arm’s-length contract to determine 

royalty, you must increase those gross 

proceeds to the extent that the 

purchaser, or any other person, provides 

certain services that you normally are 

responsible to perform to place the coal 

in marketable condition or to market the 

coal. 

§ 1206.257 When is an ONRR audit, review, 

reconciliation, monitoring, or other like 

process considered final? 

Notwithstanding any provision in 

these regulations to the contrary, ONRR 

will not consider any audit, review, 

reconciliation, monitoring, or other like 

process that results in ONRR 

redetermining royalty due, under this 

subpart, final or binding as against the 

Federal Government or its beneficiaries 

unless ONRR chooses to formally close 

the audit period in writing. 

§ 1206.258 How do I request a valuation 

determination or guidance? 

(a) You may request a valuation 

determination or guidance from ONRR 

regarding any coal produced. Your 

request must: 

(1) Be in writing; 

(2) Identify specifically all leases 

involved, all interest owners of those 

leases, and the operator(s) for those 

leases; 

(3) Completely explain all relevant 

facts. You must inform ONRR of any 

changes to relevant facts that occur 

before we respond to your request; 

(4) Include copies of all relevant 

documents; 

(5) Provide your analysis of the 

issue(s), including citations to all 

relevant precedents (including adverse 

precedents); and 

(6) Suggest a proposed valuation 

method. 

(b) In response to your request, ONRR 

may: 

(1) Request that the Assistant 

Secretary for Policy, Management and 

Budget issue a determination; or 

(2) Decide that ONRR will issue 

guidance; or 

(3) Inform you in writing that ONRR 

will not provide a determination or 

guidance. Situations in which ONRR 

typically will not provide any 

determination or guidance include, but 

are not limited to: 

(i) Requests for guidance on 

hypothetical situations; and 

(ii) Matters that are the subject of 

pending litigation or administrative 

appeals. 

(c)(1) A determination the Assistant 

Secretary for Policy, Management and 

Budget signs is binding on both you and 

ONRR until the Assistant Secretary 

modifies or rescinds it. 

(2) After the Assistant Secretary issues 

a determination, you must make any 

adjustments in royalty payments that 

follow from the determination and, if 

you owe additional royalties, you must 

pay any additional royalties due, plus 

late payment interest calculated under 

§ 1218.202 of this chapter. 

(3) A determination the Assistant 

Secretary signs is the final action of the 

Department and is subject to judicial 

review under 5 U.S.C. 701–706. 

(d) Guidance ONRR issues is not 

binding on ONRR, delegated States, or 

you with respect to the specific 

situation addressed in the guidance. 

(1) Guidance and ONRR’s decision 

whether or not to issue guidance or 

request an Assistant Secretary 

determination, or neither, under 

paragraph (b) of this section, are not 

appealable decisions or orders under 30 

CFR part 1290. 

(2) If you receive an order requiring 

you to pay royalty on the same basis as 

the guidance, you may appeal that order 

under 30 CFR part 1290. 

(e) ONRR or the Assistant Secretary 

may use any of the applicable criteria in 

this subpart to provide guidance or 

make a determination. 

(f) A change in an applicable statute 

or regulation on which ONRR based any 

guidance, or the Assistant Secretary 

based any determination, takes 

precedence over the determination or 

guidance after the effective date of the 

statute or regulation, regardless of 

whether ONRR or the Assistant 

Secretary modifies or rescinds the 

guidance or determination. 

(g) ONRR may make requests and 

replies under this section available to 

the public, subject to the confidentiality 

requirements under § 1206.259. 

§ 1206.259 Does ONRR protect information 

I provide? 

(a) Certain information you or your 

affiliate submit(s) to ONRR regarding 

royalties on coal, including deductions 

and allowances, may be exempt from 

disclosure. 

(b) To the extent applicable laws and 

regulations permit, ONRR will keep 

confidential any data you or your 

affiliate submit(s) that is privileged, 

confidential, or otherwise exempt from 

disclosure. 

(c) You and others must submit all 

requests for information under the 

Freedom of Information Act regulations 

of the Department of the Interior at 43 

CFR part 2. 

§ 1206.260 What general transportation 

allowance requirements apply to me? 

(a)(1) ONRR will allow a deduction 

for the reasonable, actual costs to 

transport coal from the lease to the point 

off the lease or mine as determined 

under § 1206.261 or § 1206.262, as 

applicable. 

(2) You do not need ONRR approval 

before reporting a transportation 

allowance for costs incurred. 

(b) You may take a transportation 

allowance when: 

(1) You value coal under § 1206.252 of 

this part; 

(2) You transport the coal from a 

Federal lease to a sales point, which is 

remote from both the lease and mine; or 

(3) You transport the coal from a 

Federal lease to a wash plant when that 

plant is remote from both the lease and 

mine and, if applicable, from the wash 

plant to a remote sales point. 

(c) You may not take an allowance for: 

(1) Transporting lease production that 

is not royalty-bearing; 

(2) In-mine movement of your coal; or 

(3) Costs to move a particular tonnage 

of production for which you did not 

incur those costs. 

(d) You only may claim a 

transportation allowance when you sell 

the coal and pay royalties. 

(e) You must allocate transportation 

allowances to the coal attributed to the 

lease from which it was extracted. 

(1) If you commingle coal produced 

from Federal and non-Federal leases, 

you may not disproportionately allocate 

transportation costs to Federal lease 

production. Your allocation must use 

the same proportion as the ratio of the 

tonnage from the Federal lease 

production to the tonnage from all 

production. 

(2) If you commingle coal produced 

from more than one Federal lease, you 


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must allocate transportation costs to 

each Federal lease as appropriate. Your 

allocation must use the same proportion 

as the ratio of the tonnage of each 

Federal lease production to the tonnage 

of all production. 

(3) For washed coal, you must allocate 

the total transportation allowance only 

to washed products. 

(4) For unwashed coal, you may take 

a transportation allowance for the total 

coal transported. 

(5)(i) You must report your 

transportation costs on Form ONRR– 

4430 as clean coal short tons sold 

during the reporting period multiplied 

by the sum of the per-short-ton cost of 

transporting the raw tonnage to the 

wash plant and, if applicable, the pershort-ton cost of transporting the clean 

coal tons from the wash plant to a 

remote sales point. 

(ii) You must determine the cost per 

short ton of clean coal transported by 

dividing the total applicable 

transportation cost by the number of 

clean coal tons resulting from washing 

the raw coal transported. 

(f) You must express transportation 

allowances for coal as a dollar-value 

equivalent per short ton of coal 

transported. If you do not base your or 

your affiliate’s payments for 

transportation under a transportation 

contract on a dollar-per-unit basis, you 

must convert whatever consideration 

you or your affiliate paid to a dollarvalue equivalent. 

(g) ONRR may determine your 

transportation allowance under 

§ 1206.254 because: 

(1) There is misconduct by or between 

the contracting parties; 

(2) ONRR determines that the 

consideration 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. We may 

consider a transportation allowance 

unreasonably high if it is 10-percent 

higher than the highest reasonable 

measures of transportation costs 

including, but not limited to, 

transportation allowances reported to 

ONRR and the cost to transport coal 

through the same transportation system; 

or 

(3) ONRR cannot determine if you 

properly calculated a transportation 

allowance under § 1206.261 or 

§ 1206.262 for any reason including, but 

not limited to, your or your affiliate’s 

failure to provide documents that ONRR 

requests under 30 CFR part 1212, 

subpart E. 

§ 1206.261 How do I determine a 

transportation allowance if I have an arm’slength transportation contract or no written 

arm’s-length contract? 

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

transportation costs under an arm’slength transportation contract, you may 

claim a transportation allowance for the 

reasonable, actual costs incurred for 

transporting the coal under that 

contract. 

(b) You must be able to demonstrate 

that your or your affiliate’s contract is at 

arm’s length. 

(c) If you have no written contract for 

the arm’s-length transportation of coal, 

then ONRR will determine your 

transportation allowance under 

§ 1206.254. You may not use this 

paragraph (c) if you or your affiliate 

perform(s) your own transportation. 

(1) You must propose to ONRR a 

method to determine the allowance 

using the procedures in § 1206.258(a). 

(2) You may use that method to 

determine your allowance until ONRR 

issues a determination. 

§ 1206.262 How do I determine a 

transportation allowance for a non-arm’slength transportation contract? 

(a) This section applies if you or your 

affiliate do(es) not have an arm’s-length 

transportation contract, including 

situations where you or your affiliate 

provide your own transportation 

services. You must calculate your 

transportation allowance based on your 

or your affiliate’s reasonable, actual 

costs for transportation during the 

reporting period using the procedures 

prescribed in this section. 

(b) Your or your affiliate’s actual costs 

may include: 

(1) Capital costs and operating and 

maintenance expenses under paragraphs 

(d), (e), and (f) of this section; 

(2) Overhead under paragraph (g) of 

this section; 

(3) Depreciation under paragraph (h) 

of this section and a return on 

undepreciated capital investment under 

paragraph (i) of this section, or you may 

elect to use a cost equal to a return on 

the initial depreciable capital 

investment in the transportation system 

under paragraph (j) of this section. After 

you have elected to use either method 

for a transportation system, you may not 

later elect to change to the other 

alternative without ONRR approval. If 

ONRR accepts your request to change 

methods, you may use your changed 

method beginning with the production 

month following the month ONRR 

received your change request; and 

(4) A return on the reasonable salvage 

value, under paragraph (i) of this 

section, after you have depreciated the 

transportation system to its reasonable 

salvage value. 

(c) You may not use any cost as a 

deduction that duplicates all or part of 

any other cost that you use under this 

section. 

(d) Allowable capital investment costs 

are generally those for depreciable fixed 

assets (including costs of delivery and 

installation of capital equipment), 

which are an integral part of the 

transportation system. 

(e) Allowable operating expenses 

include: 

(1) Operations supervision and 

engineering; 

(2) Operations labor; 

(3) Fuel; 

(4) Utilities; 

(5) Materials; 

(6) Ad valorem property taxes; 

(7) Rent; 

(8) Supplies; and 

(9) Any other directly allocable and 

attributable operating expenses that you 

can document. 

(f) Allowable maintenance expenses 

include: 

(1) Maintenance of the transportation 

system; 

(2) Maintenance of equipment; 

(3) Maintenance labor; and 

(4) Other directly allocable and 

attributable maintenance expenses that 

you can document. 

(g) Overhead, directly attributable and 

allocable to the operation and 

maintenance of the transportation 

system, is an allowable expense. State 

and Federal income taxes and severance 

taxes and other fees, including royalties, 

are not allowable expenses. 

(h)(1) To calculate depreciation, you 

may elect to use either (i) a straight-line 

depreciation method based on the life of 

the transportation system or the life of 

the reserves which the transportation 

system services, or (ii) a unit-ofproduction method. After you make an 

election, you may not change methods 

without ONRR approval. If ONRR 

accepts your request to change methods, 

you may use your changed method 

beginning with the production month 

following the month ONRR received 

your change request. 

(2) A change in ownership of a 

transportation system will not alter the 

depreciation schedule that the original 

transporter/lessee established for 

purposes of the allowance calculation. 

(3) You may depreciate a 

transportation system only once with or 

without a change in ownership. 

(i)(1) To calculate a return on 

undepreciated capital investment, you 

must multiply the remaining 

undepreciated capital balance as of the 

beginning of the period for which you 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 667 

are calculating the transportation 

allowance by the rate of return provided 

in paragraph (k) of this section. 

(2) After you have depreciated a 

transportation system to its reasonable 

salvage value, you may continue to 

include in the allowance calculation a 

cost equal to the reasonable salvage 

value multiplied by a rate of return 

determined under paragraph (k) of this 

section. 

(j) As an alternative to using 

depreciation and a return on 

undepreciated capital investment, as 

provided under paragraph (b)(3) of this 

section, you may use as a cost an 

amount equal to the allowable initial 

capital investment in the transportation 

system multiplied by the rate of return 

determined under paragraph (k) of this 

section. You may not include 

depreciation in your allowance 

(k) The rate of return is the industrial 

rate associated with Standard & Poor’s 

BBB rating. 

(1) You must use the monthly average 

BBB rate that Standard & Poor’s 

publishes for the first month for which 

the allowance is applicable. 

(2) You must redetermine the rate at 

the beginning of each subsequent 

calendar year. 

(3) After ONRR issues a 

determination, you must make the 

adjustments under § 1206.266. 

§ 1206.263 What are my reporting 

requirements under an arm’s-length 

transportation contract? 

(a) You must use a separate entry on 

Form ONRR–4430 to notify ONRR of an 

allowance based on transportation costs 

you or your affiliate incur(s). 

(b) ONRR may require you or your 

affiliate to submit arm’s-length 

transportation contracts, production 

agreements, operating agreements, and 

related documents. 

(c) You can find recordkeeping 

requirements in parts 1207 and 1212 of 

this chapter. 

§ 1206.264 What are my reporting 

requirements under a non-arm’s-length 

transportation contract? 

(a) You must use a separate entry on 

Form ONRR–4430 to notify ONRR of an 

allowance based on non-arm’s-length 

transportation costs you or your affiliate 

incur(s). 

(b)(1) For new non-arm’s-length 

transportation facilities or arrangements, 

you must base your initial deduction on 

estimates of allowable transportation 

costs for the applicable period. 

(2) You must use your or your 

affiliate’s most recently available 

operations data for the transportation 

system as your estimate, if available. If 

such data is not available, you must use 

estimates based on data for similar 

transportation systems. 

(3) Section 1206.266 applies when 

you amend your report based on the 

actual costs. 

(c) ONRR may require you or your 

affiliate to submit all data used to 

calculate the allowance deduction. You 

can find recordkeeping requirements in 

parts 1207 and 1212 of this chapter. 

§ 1206.265 What interest and penalties 

apply if I improperly report a transportation 

allowance? 

(a)(1) If ONRR determines that you 

took an unauthorized transportation 

allowance, then you must pay any 

additional royalties due, plus late 

payment interest calculated under 

§ 1218.202 of this chapter. 

(2) If you understated your 

transportation allowance, you may be 

entitled to a credit without interest. 

(b) If you improperly net a 

transportation allowance against the 

sales value of the coal instead of 

reporting the allowance as a separate 

entry on Form ONRR–4430, ONRR may 

assess a civil penalty under 30 CFR part 

1241. 

§ 1206.266 What reporting adjustments 

must I make for transportation allowances? 

(a) If your actual transportation 

allowance is less than the amount you 

claimed on Form ONRR–4430 for each 

month during the allowance reporting 

period, you must pay additional 

royalties due, plus late payment interest 

calculated under § 1218.202 of this 

chapter from the date you took the 

deduction to the date you repay the 

difference. 

(b) If the actual transportation 

allowance is greater than the amount 

you claimed on Form ONRR–4430 for 

any month during the period reported 

on the allowance form, you are entitled 

to a credit without interest. 

§ 1206.267 What general washing 

allowance requirements apply to me? 

(a)(1) If you determine the value of 

your coal under § 1206.252 of this 

subpart, you may take a washing 

allowance for the reasonable, actual 

costs to wash coal. The allowance is a 

deduction when determining coal 

royalty value for the costs you incur to 

wash coal. 

(2) You do not need ONRR approval 

before reporting a washing allowance. 

(b) You may not: 

(1) Take an allowance for the costs of 

washing lease production that is not 

royalty bearing; 

(2) Disproportionately allocate 

washing costs to Federal leases. You 

must allocate washing costs to washed 

coal attributable to each Federal lease by 

multiplying the input ratio determined 

under § 1206.251(e)(2)(i) by the total 

allowable costs. 

(c)(1) You must express washing 

allowances for coal as a dollar-value 

equivalent per short ton of coal washed. 

(2) If you do not base your or your 

affiliate’s payments for washing under 

an arm’s-length contract on a dollar-perunit basis, you must convert whatever 

consideration you or your affiliate paid 

to a dollar-value equivalent. 

(d) ONRR may determine your 

washing allowance under § 1206.254 

because: 

(1) There is misconduct by or between 

the contracting parties; 

(2) ONRR determines that the 

consideration 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. We may consider a 

washing allowance unreasonably high if 

it is 10-percent higher than the highest 

other reasonable measures of washing, 

including but not limited to, washing 

allowances reported to ONRR and costs 

for coal washed in the same plant or 

other plants in the region; or 

(3) ONRR cannot determine if you 

properly calculated a washing 

allowance under §§ 1206.267 through 

1206.269 for any reason, including but 

not limited to, your or your affiliate’s 

failure to provide documents that ONRR 

requests under 30 CFR part 1212, 

subpart E. 

(e) You only may claim a washing 

allowance, when you sell the washed 

coal and report and pay royalties. 

§ 1206.268 How do I determine washing 

allowances if I have an arm’s-length 

washing contract or no written arm’s-length 

contract? 

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

washing costs under an arm’s-length 

washing contract, you may claim a 

washing allowance for the reasonable, 

actual costs incurred. 

(b) You must be able to demonstrate 

that your or your affiliate’s contract is 

arm’s length. 

(c) If you have no written contract for 

the arm’s-length washing of coal, then 

ONRR will determine your washing 

allowance under § 1206.254. You may 

not use this paragraph (c) if you or your 

affiliate perform(s) your own washing. If 

you or your affiliate perform(s) the 

washing, then: 

(1) You must propose to ONRR a 

method to determine the allowance 

using the procedures in § 1206.258(a). 


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(2) You may use that method to 

determine your allowance until ONRR 

issues a determination. 

§ 1206.269 How do I determine washing 

allowances if I have a non-arm’s-length 

washing contract? 

(a) This section applies if you or your 

affiliate do(es) not have an arm’s-length 

washing contract, including situations 

where you or your affiliate provides 

your own washing services. You must 

calculate your washing allowance based 

on your or your affiliate’s reasonable, 

actual costs for washing during the 

reporting period using the procedures 

prescribed in this section. 

(b) Your or your affiliate’s actual costs 

can include: 

(1) Capital costs and operating and 

maintenance expenses under paragraphs 

(d), (e), and (f) of this section; 

(2) Overhead under paragraph (g) of 

this section; 

(3) Depreciation under paragraph (h) 

of this section and a return on 

undepreciated capital investment under 

paragraph (i) of this section, or you may 

elect to use a cost equal to a return on 

the initial depreciable capital 

investment in the wash plant under 

paragraph (j) of this section. After you 

have elected to use either method for a 

wash plant, you may not later elect to 

change to the other alternative without 

ONRR approval. If ONRR accepts your 

request to change methods, you may use 

your changed method beginning with 

the production month following the 

month ONRR received your change 

request; and 

(4) A return on the reasonable salvage 

value, under paragraph (i) of this 

section, after you have depreciated the 

wash plant to its reasonable salvage 

value. 

(c) You may not use any cost as a 

deduction that duplicates all or part of 

any other cost that you use under this 

section. 

(d) Allowable capital investment costs 

are generally those for depreciable fixed 

assets (including costs of delivery and 

installation of capital equipment), 

which are an integral part of the wash 

plant. 

(e) Allowable operating expenses 

include: 

(1) Operations supervision and 

engineering; 

(2) Operations labor; 

(3) Fuel; 

(4) Utilities; 

(5) Materials; 

(6) Ad valorem property taxes; 

(7) Rent; 

(8) Supplies; and 

(9) Any other directly allocable and 

attributable operating expenses that you 

can document. 

(f) Allowable maintenance expenses 

include: 

(1) Maintenance of the wash plant; 

(2) Maintenance of equipment; and 

(3) Maintenance labor. 

(4) Other directly allocable and 

attributable maintenance expenses that 

you can document. 

(g) Overhead, directly attributable and 

allocable to the operation and 

maintenance of the wash plant, is an 

allowable expense. State and Federal 

income taxes and severance taxes and 

other fees, including royalties, are not 

allowable expenses. 

(h)(1) To calculate depreciation, you 

may elect to use either a straight-line 

depreciation method based on the life of 

the wash plant or the life of the reserves 

which the wash plant services, or a unitof-production method. After you make 

an election, you may not change 

methods without ONRR approval. If 

ONRR accepts your request to change 

methods, you may use your changed 

method beginning with the production 

month following the month ONRR 

received your change request. 

(2) A change in ownership of a wash 

plant will not alter the depreciation 

schedule that the original washer/lessee 

established for purposes of the 

allowance calculation. 

(3) With or without a change in 

ownership, you may depreciate a wash 

plant only once. 

(i)(1) To calculate a return on 

undepreciated capital investment, you 

must multiply the remaining 

undepreciated capital balance as of the 

beginning of the period for which you 

are calculating the washing allowance 

by the rate of return provided in 

paragraph (k) of this section. 

(2) After you have depreciated a wash 

plant to its reasonable salvage value, 

you may continue to include in the 

allowance calculation a cost equal to the 

salvage value multiplied by a rate of 

return determined under paragraph (k) 

of this section. 

(j) As an alternative to using 

depreciation and a return on 

undepreciated capital investment, as 

provided under paragraph (b)(3) of this 

section, you may use as a cost an 

amount equal to the allowable initial 

capital investment in the wash plant 

multiplied by the rate of return as 

determined under paragraph (k) of this 

section. You may not include 

depreciation in your allowance. 

(k) The rate of return is the industrial 

rate associated with Standard & Poor’s 

BBB rating. 

(1) You must use the monthly average 

BBB rate that Standard & Poor’s 

publishes for the first month for which 

the allowance is applicable. 

(2) You must redetermine the rate at 

the beginning of each subsequent 

calendar year. 

(3) After ONRR issues its 

determination, you must make the 

adjustments under § 1206.273. 

§ 1206.270 What are my reporting 

requirements under an arm’s-length 

washing contract? 

(a) You must use a separate entry on 

Form ONRR–4430 to notify ONRR of an 

allowance based on washing costs you 

or your affiliate incur(s). 

(b) ONRR may require you or your 

affiliate to submit arm’s-length washing 

contracts, production agreements, 

operating agreements, and related 

documents. 

(c) You can find recordkeeping 

requirements in parts 1207 and 1212 of 

this chapter. 

§ 1206.271 What are my reporting 

requirements under a non-arm’s-length 

washing contract? 

(a) You must use a separate entry on 

Form ONRR–4430 to notify ONRR of an 

allowance based on non-arm’s-length 

washing costs you or your affiliate 

incur(s). 

(b)(1) For new non-arm’s-length 

washing facilities or arrangements, you 

must base your initial deduction on 

estimates of allowable washing costs for 

the applicable period. 

(2) You must use your or your 

affiliate’s most recently available 

operations data for the wash plant as 

your estimate, if available. If such data 

is not available, you must use estimates 

based on data for similar wash plants. 

(3) Section 1206.273 applies when 

you amend your report based on the 

actual costs. 

(c) ONRR may require you or your 

affiliate to submit all data used to 

calculate the allowance deduction. You 

can find recordkeeping requirements in 

parts 1207 and 1212 of this chapter. 

§ 1206.272 What interest and penalties 

apply if I improperly report a washing 

allowance? 

(a)(1) If ONRR determines that you 

took an unauthorized washing 

allowance, then you must pay any 

additional royalties due, plus late 

payment interest calculated under 

§ 1218.202 of this chapter. 

(2) If you understated your washing 

allowance, you may be entitled to a 

credit without interest. 

(b) If you improperly net a washing 

allowance against the sales value of the 

coal instead of reporting the allowance 

as a separate entry on Form ONRR– 

4430, ONRR may assess a civil penalty 

under 30 CFR part 1241. 


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§ 1206.273 What reporting adjustments 

must I make for washing allowances? 

(a) If your actual washing allowance 

is less than the amount you claimed on 

Form ONRR–4430 for each month 

during the allowance reporting period, 

you must pay additional royalties due, 

plus late payment interest calculated 

under § 1218.202 of this chapter from 

the date you took the deduction to the 

date you repay the difference. 

(b) If the actual washing allowance is 

greater than the amount you claimed on 

Form ONRR–4430 for any month during 

the period reported on the allowance 

form, you are entitled to a credit 

without interest. 

■ 9. Revise subpart J to read as follows: 

Subpart J—Indian Coal 

Sec. 

1206.450 What is the purpose and scope of 

this subpart? 

1206.451 How do I determine royalty 

quantity and quality? 

1206.452 How do I calculate royalty value 

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

arm’s-length or non-arm’s-length 

contract? 

1206.453 How will ONRR determine if my 

royalty payments are correct? 

1206.454 How will ONRR determine the 

value of my coal for royalty purposes? 

1206.455 What records must I keep to 

support my calculations of royalty under 

this subpart? 

1206.456 What are my responsibilities to 

place production into marketable 

condition and to market production? 

1206.457 When is an ONRR audit, review, 

reconciliation, monitoring, or other like 

process considered final? 

1206.458 How do I request a valuation 

determination or guidance? 

1206.459 Does ONRR protect information I 

provide? 

1206.460 What general transportation 

allowance requirements apply to me? 

1206.461 How do I determine a 

transportation allowance if I have an 

arm’s-length transportation contract or 

no written arm’s-length contract? 

1206.462 How do I determine a 

transportation allowance if I have a nonarm’s-length transportation contract? 

1206.463 What are my reporting 

requirements under an arm’s-length 

transportation contract? 

1206.464 What are my reporting 

requirements under a non-arm’s-length 

transportation contract or no written 

arm’s-length contract? 

1206.465 What interest and penalties apply 

if I improperly report a transportation 

allowance? 

1206.466 What reporting adjustments must 

I make for transportation allowances? 

1206.467 What general washing allowance 

requirements regarding apply to me? 

1206.468 How do I determine a washing 

allowance if I have an arm’s-length 

washing contract or no written arm’slength contract? 

1206.469 How do I determine a washing 

allowance if I have a non-arm’s-length 

washing contract? 

1206.470 What are my reporting 

requirements under an arm’s-length 

washing contract? 

1206.471 What are my reporting 

requirements under a non-arm’s-length 

washing contract or no written arm’slength contract? 

1206.472 What interest and penalties apply 

if I improperly report a washing 

allowance? 

1206.473 What reporting adjustments must 

I make for washing allowances? 

Subpart J—Indian Coal 

§ 1206.450 What is the purpose and scope 

of this subpart? 

(a) This subpart applies to all coal 

produced from Indian tribal coal leases 

and coal leases on land held by 

individual Indian mineral owners. It 

explains how you, as the lessee, must 

calculate the value of production for 

royalty purposes consistent with the 

mineral leasing laws, other applicable 

laws, and lease terms (except leases on 

the Osage Indian Reservation, Osage 

County, Oklahoma). 

(b) The terms ‘‘you’’ and ‘‘your’’ in 

this subpart refer to the lessee. 

(c) If the regulations in this subpart 

are inconsistent with: 

(1) A Federal statute or treaty; 

(2) A settlement agreement; 

(3) A written agreement between the 

lessee and the ONRR Director 

establishing a method to determine the 

value of production from any lease that 

ONRR expects, at least, would 

approximate the value established 

under this subpart; or 

(4) An express provision of a coal 

lease subject to this subpart, then the 

statute, settlement agreement, written 

agreement, or lease provision will 

govern to the extent of the 

inconsistency. 

(d) ONRR may audit and order you to 

adjust all royalty payments. 

(e) The regulations in this subpart, 

intended to ensure that the trust 

responsibilities of the United States 

with respect to the administration of 

Indian coal leases, are discharged under 

the requirements of the governing 

mineral leasing laws, treaties, and lease 

terms. 

§ 1206.451 How do I determine royalty 

quantity and quality? 

(a) You must calculate royalties based 

on the quantity and quality of coal at the 

royalty measurement point that ONRR 

and BLM jointly determine. 

(b) You must measure coal in short 

tons using the methods BLM prescribes 

for Indian coal leases. You must report 

coal quantity on appropriate forms 

required in 30 CFR part 1210. 

(c)(1) You are not required to pay 

royalties on coal you produce and add 

to stockpiles or inventory until you use, 

sell, or otherwise finally dispose of such 

coal. 

(2) ONRR may request BLM to require 

you to increase your lease bond if BLM 

determines that stockpiles or inventory 

are excessive such that they increase the 

risk of resource degradation. 

(d) You must pay royalty at the rate 

specified in your lease at the time you 

use, sell, or otherwise finally dispose of 

the coal. 

(e) You must allocate washed coal by 

attributing the washed coal to the leases 

from which it was extracted. 

(1) If the wash plant washes coal from 

only one lease, the quantity of washed 

coal allocable to the lease is the total 

output of washed coal from the plant. 

(2) If the wash plant washes coal from 

more than one lease, you must 

determine the tonnage of washed coal 

attributable to each lease by: 

(i) First, calculating the input ratio of 

washed coal allocable to each lease by 

dividing the tonnage of coal you input 

to the wash plant from each lease by the 

total tonnage of coal input to the wash 

plant from all leases; and 

(ii) Then multiplying the input ratio 

derived under paragraph (e)(2)(i) of this 

section by the tonnage of total output of 

washed coal from the plant. 

§ 1206.452 How do I calculate royalty value 

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

arm’s-length or non-arm’s-length contract? 

(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 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: 

(1) You sell under an arm’s-length 

contract; or 

(2) You sell or transfer to your affiliate 

or another person under a non-arm’slength contract, and that affiliate or 

person, or another affiliate of either of 

them, then sells the coal under an arm’slength contract. 

(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 you or your affiliate own(s) 

for the generation and sale of electricity 

and; 

(1) You or your affiliate sell(s) the 

electricity, then the value of the coal 

subject to this section, for royalty 

purposes, is the gross proceeds accruing 

to you for the power plant’s arm’sVerDate Sep<11>2014 20:22 Jan 05, 2015 Jkt 235001 PO 00000 Frm 00063 Fmt 4701 Sfmt 4702 E:\FR\FM\06JAP2.SGM 06JAP2

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length sales of the electricity less 

applicable transportation and washing 

deductions determined under 

§§ 1206.460 through 1206.462 and 

§§ 1206.467 through 1206.469 of this 

subpart and, if applicable, transmission 

and generation deductions determined 

under §§ 1206.353 and 1206.352 of 

subpart H; 

(2) You or your affiliate do(es) not sell 

the electricity at arm’s length (i.e. you or 

your affiliate deliver(s) the electricity 

directly to the grid), then ONRR will 

determine the value of the coal under 

§ 1206.454. 

(i) You must propose to ONRR a 

method to determine the value using the 

procedures in § 1206.458(a). 

(ii) You may use that method to 

determine value, for royalty purposes, 

until ONRR issues a determination. 

(iii) After ONRR issues a 

determination, you must make the 

adjustments under § 1206.453(a)(2). 

(c) If you are a coal cooperative, or a 

member of a coal cooperative, and; 

(1) You sell or transfer coal to another 

member of the coal cooperative, and 

that member of the coal cooperative 

then sells the coal under an arm’s-length 

contract, then you must value the coal 

under paragraph (a) of this section; or 

(2) You sell or transfer coal to another 

member of the coal cooperative, and the 

coal is used by you, the coal 

cooperative, or another member of the 

coal cooperative, in a power plant for 

the generation and sale of electricity, 

then you must value the coal under 

paragraph (b) of this section. 

(d) If you are entitled to take a 

washing allowance and transportation 

allowance for royalty purposes under 

this section, under no circumstances 

may the washing allowance plus the 

transportation allowance reduce the 

royalty value of the coal to zero. 

(e) The values in this section do not 

apply, if ONRR decides to value your 

coal under § 1206.454. 

§ 1206.453 How will ONRR determine if my 

royalty payments are correct? 

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

audit the royalties 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, 

or decide your value, under § 1206.454. 

(2) If ONRR directs you to use a 

different royalty value, you must either 

pay any underpaid royalties plus late 

payment interest calculated under 

§ 1218.202 of this chapter or report a 

credit for, or request a refund of, any 

overpaid royalties. 

(b) When the provisions in this 

subpart refer to gross proceeds, in 

conducting reviews and audits, ONRR 

will examine if your or your affiliate’s 

contract reflects the total consideration 

actually transferred, either directly or 

indirectly, from the buyer to you or your 

affiliate for the coal. If ONRR 

determines that a contract does not 

reflect the total consideration, ONRR 

may decide your value under 

§ 1206.454. 

(c) ONRR may decide to value your 

coal under § 1206.454, if ONRR 

determines that the gross proceeds 

accruing to you or your affiliate under 

a contract do not reflect reasonable 

consideration because: 

(1) There is misconduct by or between 

the contracting parties; 

(2) You breached your duty to market 

the coal for the mutual benefit of 

yourself and the lessor by selling your 

coal at a value that is unreasonably low. 

ONRR may consider a sales price 

unreasonably low, if it is 10-percent less 

than the lowest other reasonable 

measures of market price, including but 

not limited to, prices reported to ONRR 

for like-quality coal; or 

(3) ONRR cannot determine if you 

properly valued your coal under 

§ 1206.452 for any reason, including but 

not limited to, your or your affiliate’s 

failure to provide documents to ONRR 

under 30 CFR part 1212, subpart E. 

(d) You have the burden of 

demonstrating that your or your 

affiliate’s contract is arm’s length. 

(e) ONRR may require you to certify 

that the provisions in your or your 

affiliate’s contract include(s) all of the 

consideration the buyer paid you or 

your affiliate, either directly or 

indirectly, for the coal. 

(f)(1) Absent contract revision or 

amendment, if you or your affiliate 

fail(s) to take proper or timely action to 

receive prices or benefits to which you 

or your affiliate are entitled, you must 

pay royalty based upon that obtainable 

price or benefit. 

(2) If you or your affiliate make timely 

application for a price increase or 

benefit allowed under your or your 

affiliate’s contract, but the purchaser 

refuses, and you or your affiliate take 

reasonable documented measures to 

force purchaser compliance, you will 

not owe additional royalties unless or 

until you or your affiliate receive 

additional monies or consideration 

resulting from the price increase. You 

may not construe this paragraph to 

permit you to avoid your royalty 

payment obligation in situations where 

a purchaser fails to pay, in whole or in 

part, or timely, for a quantity of coal. 

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

all contracts, contract revisions, or 

amendments in writing, and all parties 

to the contract must sign the contract, 

contract revisions, or amendments. 

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

comply with paragraph (g)(1) of this 

section, ONRR may decide to value your 

coal under § 1206.454. 

(3) This provision applies 

notwithstanding any other provisions in 

this title 30 to the contrary. 

§ 1206.454 How will ONRR determine the 

value of my coal for royalty purposes? 

If ONRR decides to value your coal for 

royalty purposes under § 1206.454, or 

any other provision in this subpart, then 

ONRR will determine value by 

considering any information we deem 

relevant, which may include, but is not 

limited to: 

(a) The value of like-quality coal from 

the same mine, nearby mines, same 

region, or other regions, or washed in 

the same or nearby wash plant; 

(b) Public sources of price or market 

information that ONRR deems reliable, 

including but not limited to, the price 

of electricity; 

(c) Information available to ONRR and 

information reported to it, including but 

not limited to, on Form ONRR–4430; 

(d) Costs of transportation or washing, 

if ONRR determines they are applicable; 

or 

(e) Any other information ONRR 

deems relevant regarding the particular 

lease operation or the salability of the 

coal. 

§ 1206.455 What records must I keep to 

support my calculations of royalty under 

this subpart? 

If you value your coal under this 

subpart, you must retain all data 

relevant to the determination of the 

royalty you paid. You can find 

recordkeeping requirements in parts 

1207 and 1212 of this chapter. 

(a) You must show: 

(1) How you calculated the royalty 

value, including all allowable 

deductions; and 

(2) How you complied with this 

subpart. 

(b) Upon request, you must submit all 

data to ONRR or the representative of 

the Indian lessor, or to the Inspector 

General of the Department of the 

Interior or other persons authorized to 

receive such information. Such data 

may include arm’s-length sales and 

sales quantity data for like-quality coal 

sold, purchased, or otherwise obtained 

by you or your affiliate from the same 

mine, nearby mines, same region, or 

other regions. You must comply with 

any such requirement within the time 

ONRR specifies. 


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§ 1206.456 What are my responsibilities to 

place production into marketable condition 

and to market production? 

(a) You must place coal in marketable 

condition and market the coal for the 

mutual benefit of the lessee and the 

lessor at no cost to the Indian lessor. 

(b) If you use gross proceeds under an 

arm’s-length contract to determine 

royalty, you must increase those gross 

proceeds to the extent that the 

purchaser, or any other person, provides 

certain services that you normally are 

responsible to perform to place the coal 

in marketable condition or to market the 

coal. 

§ 1206.457 When is an ONRR audit, review, 

reconciliation, monitoring, or other like 

process considered final? 

Notwithstanding any provision in 

these regulations to the contrary, ONRR 

will not consider any audit, review, 

reconciliation, monitoring, or other like 

process that results in ONRR 

redetermining royalty due, under this 

subpart, final or binding as against the 

Federal Government or its beneficiaries 

unless ONRR chooses to formally close 

the audit period in writing. 

§ 1206.458 How do I request a valuation 

determination or guidance? 

(a) You may request a valuation 

determination or guidance from ONRR 

regarding any coal produced. Your 

request must: 

(1) Be in writing; 

(2) Identify specifically all leases 

involved, all interest owners of those 

leases, and the operator(s) for those 

leases; 

(3) Completely explain all relevant 

facts. You must inform ONRR of any 

changes to relevant facts that occur 

before we respond to your request; 

(4) Include copies of all relevant 

documents; 

(5) Provide your analysis of the 

issue(s), including citations to all 

relevant precedents (including adverse 

precedents); and 

(6) Suggest a proposed valuation 

method. 

(b) In response to your request, ONRR 

may: 

(1) Request that the Assistant 

Secretary for Policy, Management and 

Budget issue a determination; or 

(2) Decide that ONRR will issue 

guidance; or 

(3) Inform you in writing that ONRR 

will not provide a determination or 

guidance. Situations in which ONRR 

typically will not provide any 

determination or guidance include, but 

are not limited to: 

(i) Requests for guidance on 

hypothetical situations; and 

(ii) Matters that are the subject of 

pending litigation or administrative 

appeals. 

(c)(1) A determination the Assistant 

Secretary for Policy, Management and 

Budget signs is binding on both you and 

ONRR until the Assistant Secretary 

modifies or rescinds it. 

(2) After the Assistant Secretary issues 

a determination, you must make any 

adjustments in royalty payments that 

follow from the determination and, if 

you owe additional royalties, you must 

pay any additional royalties due, plus 

late payment interest calculated under 

§ 1218.202 of this chapter. 

(3) A determination the Assistant 

Secretary signs is the final action of the 

Department and is subject to judicial 

review under 5 U.S.C. 701–706. 

(d) Guidance ONRR issues is not 

binding on ONRR, Tribes, individual 

Indian mineral owners, or you with 

respect to the specific situation 

addressed in the guidance. 

(1) Guidance and ONRR’s decision 

whether or not to issue guidance or 

request an Assistant Secretary 

determination, or neither, under 

paragraph (b) of this section, are not 

appealable decisions or orders under 30 

CFR part 1290. 

(2) If you receive an order requiring 

you to pay royalty on the same basis as 

the guidance, you may appeal that order 

under 30 CFR part 1290. 

(e) ONRR or the Assistant Secretary 

may use any of the applicable criteria in 

this subpart to provide guidance or 

make a determination. 

(f) A change in an applicable statute 

or regulation on which ONRR based any 

guidance, or the Assistant Secretary 

based any determination, takes 

precedence over the determination or 

guidance after the effective date of the 

statute or regulation, regardless of 

whether ONRR or the Assistant 

Secretary modifies or rescinds the 

guidance or determination. 

(g) ONRR may make requests and 

replies under this section available to 

the public, subject to the confidentiality 

requirements under § 1206.459. 

§ 1206.459 Does ONRR protect information 

I provide? 

(a) Certain information you or your 

affiliate submit(s) to ONRR regarding 

royalties on coal, including deductions 

and allowances, may be exempt from 

disclosure. 

(b) To the extent applicable laws and 

regulations permit, ONRR will keep 

confidential any data you or your 

affiliate submit(s) that is privileged, 

confidential, or otherwise exempt from 

disclosure. 

(c) You and others must submit all 

requests for information under the 

Freedom of Information Act regulations 

of the Department of the Interior at 43 

CFR part 2. 

§ 1206.460 What general transportation 

allowance requirements apply to me? 

(a)(1) ONRR will allow a deduction 

for the reasonable, actual costs to 

transport coal from the lease to the point 

off the lease or mine as determined 

under § 1206.461 or § 1206.462, as 

applicable. 

(2) Before you may take any 

transportation allowance, you must 

submit a completed page 1 of Form 

ONRR–4293, Coal Transportation 

Allowance Report, under sections 

§ 1206.463 and § 1206.464 of this 

subpart. You may claim a transportation 

allowance retroactively for a period of 

not more than 3 months prior to the first 

day of the month that ONRR receives 

your Form ONRR–4293. 

(3) You may not use a transportation 

allowance that was in effect before 

[EFFECTIVE DATE OF THE FINAL 

RULE]. You must use the provisions of 

this subpart to determine your 

transportation allowance. 

(b) You may take a transportation 

allowance when: 

(1) You value coal under § 1206.452 of 

this part; 

(2) You transport the coal from an 

Indian lease to a sales point which, is 

remote from both the lease and mine; or 

(3) You transport the coal from an 

Indian lease to a wash plant when that 

plant is remote from both the lease and 

mine and, if applicable, from the wash 

plant to a remote sales point. 

(c) You may not take an allowance for: 

(1) Transporting lease production that 

is not royalty-bearing; 

(2) In-mine movement of your coal; or 

(3) Costs to move a particular tonnage 

of production for which you did not 

incur those costs. 

(d) You only may claim a 

transportation allowance when you sell 

the coal and pay royalties. 

(e) You must allocate transportation 

allowances to the coal attributed to the 

lease from which it was extracted. 

(1) If you commingle coal produced 

from Indian and non-Indian leases, you 

may not disproportionately allocate 

transportation costs to Indian lease 

production. Your allocation must use 

the same proportion as the ratio of the 

tonnage from the Indian lease 

production to the tonnage from all 

production. 

(2) If you commingle coal produced 

from more than one Indian lease, you 

must allocate transportation costs to 

each Indian lease as appropriate. Your 

allocation must use the same proportion 

as the ratio of the tonnage of each Indian 


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leases production to the tonnage of all 

production. 

(3) For washed coal, you must allocate 

the total transportation allowance only 

to washed products. 

(4) For unwashed coal, you may take 

a transportation allowance for the total 

coal transported. 

(5)(i) You must report your 

transportation costs on Form ONRR– 

4430 as clean coal short tons sold 

during the reporting period multiplied 

by the sum of the per short-ton cost of 

transporting the raw tonnage to the 

wash plant and, if applicable, the per 

short-ton cost of transporting the clean 

coal tons from the wash plant to a 

remote sales point. 

(ii) You must determine the cost per 

short ton of clean coal transported by 

dividing the total applicable 

transportation cost by the number of 

clean coal tons resulting from washing 

the raw coal transported. 

(f) You must express transportation 

allowances for coal as a dollar-value 

equivalent per short ton of coal 

transported. If you do not base your or 

your affiliate’s payments for 

transportation under a transportation 

contract on a dollar-per-unit basis, you 

must convert whatever consideration 

you or your affiliate paid to a dollarvalue equivalent. 

(g) ONRR may determine your 

transportation allowance under 

§ 1206.454 because: 

(1) There is misconduct by or between 

the contracting parties; 

(2) ONRR determines that the 

consideration 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. We may 

consider a transportation allowance 

unreasonably high if it is 10-percent 

higher than the highest reasonable 

measures of transportation costs 

including, but not limited to, 

transportation allowances reported to 

ONRR and the cost to transport coal 

through the same transportation system; 

or 

(3) ONRR cannot determine if you 

properly calculated a transportation 

allowance under § 1206.461 or 

§ 1206.462 for any reason including, but 

not limited to, your or your affiliate’s 

failure to provide documents that ONRR 

requests under 30 CFR part 1212, 

subpart E. 

§ 1206.461 How do I determine a 

transportation allowance if I have an arm’slength transportation contract or no written 

arm’s-length contract? 

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

transportation costs under an arm’slength transportation contract, you may 

claim a transportation allowance for the 

reasonable, actual costs incurred for 

transporting the coal under that 

contract. 

(b) You must be able to demonstrate 

that your or your affiliate’s contract is at 

arm’s length. 

(c) If you have no written contract for 

the arm’s-length transportation of coal, 

then ONRR will determine your 

transportation allowance under 

§ 1206.454. You may not use this 

paragraph (c) if you or your affiliate 

perform(s) your own transportation. 

(1) You must propose to ONRR a 

method to determine the allowance 

using the procedures in § 1206.458(a). 

(2) You may use that method to 

determine your allowance until ONRR 

issues a determination. 

§ 1206.462 How do I determine a 

transportation allowance if I have a nonarm’s-length transportation contract? 

(a) This section applies if you or your 

affiliate do(es) not have an arm’s-length 

transportation contract, including 

situations where you or your affiliate 

provide your own transportation 

services. Calculate your transportation 

allowance based on your or your 

affiliate’s reasonable, actual costs for 

transportation during the reporting 

period using the procedures prescribed 

in this section. 

(b) Your or your affiliate’s actual costs 

may include: 

(1) Capital costs and operating and 

maintenance expenses under paragraphs 

(d), (e), and (f) of this section; 

(2) Overhead under paragraph (g) of 

this section; and 

(3) Depreciation under paragraph (h) 

of this section and a return on 

undepreciated capital investment under 

paragraph (i) of this section, or you may 

elect to use a cost equal to a return on 

the initial depreciable capital 

investment in the transportation system 

under paragraph (j) of this section. After 

you have elected to use either method 

for a transportation system, you may not 

later elect to change to the other 

alternative without ONRR approval. If 

ONRR accepts your request to change 

methods, you may use your changed 

method beginning with the production 

month following the month ONRR 

received your change request. 

(c) You may not use any cost as a 

deduction that duplicates all or part of 

any other cost that you use under this 

section. 

(d) Allowable capital investment costs 

are generally those for depreciable fixed 

assets (including costs of delivery and 

installation of capital equipment) which 

are an integral part of the transportation 

system. 

(e) Allowable operating expenses 

include: 

(1) Operations supervision and 

engineering; 

(2) Operations labor; 

(3) Fuel; 

(4) Utilities; 

(5) Materials; 

(6) Ad valorem property taxes; 

(7) Rent; 

(8) Supplies; and 

(9) Any other directly allocable and 

attributable operating expense that you 

can document. 

(f) Allowable maintenance expenses 

include: 

(1) Maintenance of the transportation 

system; 

(2) Maintenance of equipment; 

(3) Maintenance labor; and 

(4) Other directly allocable and 

attributable maintenance expenses that 

you can document. 

(g) Overhead, directly attributable and 

allocable to the operation and 

maintenance of the transportation 

system, is an allowable expense. State 

and Federal income taxes and Indian 

tribal severance taxes and other fees, 

including royalties, are not allowable 

expenses. 

(h)(1) To calculate depreciation, you 

may elect to use either a straight-line 

depreciation method based on the life of 

the transportation system or the life of 

the reserves which the transportation 

system services, or a unit-of-production 

method. After you make an election, 

you may not change methods without 

ONRR approval. If ONRR accepts your 

request to change methods, you may use 

your changed method beginning with 

the production month following the 

month ONRR received your change 

request. 

(2) A change in ownership of a 

transportation system will not alter the 

depreciation schedule the original 

transporter/lessee established for 

purposes of the allowance calculation. 

(3) You may depreciate a 

transportation system only once with or 

without a change in ownership. 

(i) To calculate a return on 

undepreciated capital investment, 

multiply the remaining undepreciated 

capital balance as of the beginning of 

the period for which you are calculating 

the transportation allowance by the rate 

of return provided in paragraph (k) of 

this section. 

(j) As an alternative to using 

depreciation and a return on 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 673 

undepreciated capital investment, as 

provided under paragraph (b)(3) of this 

section, you may use as a cost an 

amount equal to the allowable initial 

capital investment in the transportation 

system multiplied by the rate of return 

determined under paragraph (k) of this 

section. You may not include 

depreciation in your allowance. 

(k) The rate of return is the industrial 

rate associated with Standard & Poor’s 

BBB rating. 

(1) You must use the monthly average 

BBB rate that Standard & Poor’s 

publishes for the first month for which 

the allowance is applicable. 

(2) You must redetermine the rate at 

the beginning of each subsequent 

calendar year. 

(3) After ONRR issues a 

determination, you must make the 

adjustments under § 1206.466. 

§ 1206.463 What are my reporting 

requirements under an arm’s-length 

transportation contract? 

(a) You must use a separate entry on 

Form ONRR–4430 to notify ONRR of an 

allowance based on transportation costs 

you or your affiliate incur(s). 

(b) ONRR may require you or your 

affiliate to submit arm’s-length 

transportation contracts, production 

agreements, operating agreements, and 

related documents. 

(c) You can find recordkeeping 

requirements in parts 1207 and 1212 of 

this chapter. 

(d)(1) You must submit page 1 of the 

initial Form ONRR–4293 prior to, or at 

the same time as, you report the 

transportation allowance determined 

under an arm’s-length contract on Form 

ONRR–4430. 

(2) The initial Form ONRR–4293 is 

effective beginning with the production 

month that you are first authorized to 

deduct a transportation allowance and 

continues until the end of the calendar 

year, or until the termination, 

modification, or amendment of the 

applicable contract or rate, whichever is 

earlier. 

(3) After the initial period that ONRR 

first authorized you to deduct a 

transportation allowance and for 

succeeding periods, you must submit 

the entire Form ONRR–4293 by the 

earlier of: 

(i) Within 3 months after the end of 

the calendar year; or 

(ii) After the termination, 

modification, or amendment of the 

applicable contract or rate. 

(4) You may request to use an 

allowance for a longer period than that 

required under paragraph (d)(2) of this 

section. 

(i) You may use that allowance 

beginning with the production month 

following the month ONRR received 

your request to use the allowance for a 

longer period until ONRR decides 

whether to approve the longer period. 

(ii) ONRR’s decision whether or not to 

approve a longer period is not 

appealable under 30 CFR part 1290. 

(iii) If ONRR does not approve the 

longer period, you must adjust your 

transportation allowance under 

§ 1206.466. 

§ 1206.464 What are my reporting 

requirements under a non-arm’s-length 

transportation contract or no written arm’slength contract? 

(a) You must use a separate entry on 

Form ONRR–4430 to notify ONRR of an 

allowance based on non-arm’s-length 

transportation costs you or your affiliate 

incur(s). 

(b) ONRR may require you or your 

affiliate to submit all data used to 

calculate the allowance deduction. You 

can find recordkeeping requirements in 

parts 1207 and 1212 of this chapter. 

(c)(1) You must submit an initial 

Form ONRR–4293 prior to, or at the 

same time as, the transportation 

allowance determined under a nonarm’s-length contract or no written 

arm’s-length contract situation that you 

report on Form ONRR–4430. If ONRR 

receives a Form ONRR–4293 by the end 

of the month that the Form ONRR–4430 

is due, ONRR will consider the form 

timely received. You may base the 

initial form on estimated costs. 

(2) The initial Form ONRR–4293 is 

effective beginning with the production 

month that you are first authorized to 

deduct a transportation allowance and 

continues until the end of the calendar 

year or termination, modification, or 

amendment of the applicable contract or 

rate, whichever is earlier. 

(3)(i) At the end of the calendar-year 

for which you submitted a Form ONRR– 

4293 based on estimates, you must 

submit another completed Form ONRR– 

4293 containing the actual costs for that 

calendar year. 

(ii) If the transportation continues, 

you must include on Form ONRR–4293 

your estimated costs for the next 

calendar year. 

(A) You must base the estimated 

transportation allowance on the actual 

costs for the previous reporting period 

plus or minus any adjustments based on 

your knowledge of decreases or 

increases that will affect the allowance. 

(B) ONRR must receive Form ONRR– 

4293 within 3 months after the end of 

the previous calendar year. 

(d)(1) For new non-arm’s-length 

transportation facilities or arrangements, 

on your initial Form ONRR–4293, you 

must include estimates of the allowable 

transportation costs for the applicable 

period. 

(2) You must use your or your 

affiliate’s most recently available 

operations data for the transportation 

system as your estimate, if available. If 

such data is not available, you must use 

estimates based on data for similar 

transportation systems. 

(e) Upon ONRR’s request, you must 

submit all data used to prepare your 

Form ONRR–4293. You must provide 

the data within a reasonable period of 

time, as ONRR determines. 

(f) Section 1206.466 applies when you 

amend your Form ONRR–4293 based on 

the actual costs. 

§ 1206.465 What interest and penalties 

apply if I improperly report a transportation 

allowance? 

(a)(1) If ONRR determines that you 

took an unauthorized transportation 

allowance, then you must pay any 

additional royalties due, plus late 

payment interest calculated under 

§ 1218.202 of this chapter. 

(2) If you understated your 

transportation allowance, you may be 

entitled to a credit without interest. 

(b) If you improperly net a 

transportation allowance against the 

sales value of the coal instead of 

reporting the allowance as a separate 

entry on Form ONRR–4430, ONRR may 

assess a civil penalty under 30 CFR part 

1241. 

§ 1206.466 What reporting adjustments 

must I make for transportation allowances? 

(a) If your actual transportation 

allowance is less than the amount you 

claimed on Form ONRR–4430 for each 

month during the allowance reporting 

period, you must pay additional 

royalties due, plus late payment interest 

calculated under § 1218.202 of this 

chapter from the date you took the 

deduction to the date you repay the 

difference. 

(b) If the actual transportation 

allowance is greater than the amount 

you claimed on Form ONRR–4430 for 

any month during the period reported 

on the allowance form, you are entitled 

to a credit without interest. 

§ 1206.467 What general washing 

allowance requirements apply to me? 

(a)(1) If you determine the value of 

your coal under § 1206.452 of this 

subpart, you may take a washing 

allowance for the reasonable, actual 

costs to wash coal. The allowance is a 

deduction when determining coal 

royalty value for the costs you incur to 

wash coal. 

(2) Before you may take any 

deduction, you must submit a 

completed page one of Form ONRR– 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
674 Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 

4292, Coal Washing Allowance Report, 

under §§ 1206.470 and 1206.471 of this 

subpart. You may claim a washing 

allowance retroactively for a period of 

not more than 3 months prior to the first 

day of the month that you have filed 

Form ONRR–4292 with ONRR. 

(3) You may not use a washing 

allowance that was in effect before the 

effective date of the final rule. You must 

use the provisions of this subpart to 

determine your washing allowance. 

(b) You may not: 

(1) Take an allowance for the costs of 

washing lease production that is not 

royalty bearing; 

(2) Disproportionately allocate 

washing costs to Indian leases. You 

must allocate washing costs to washed 

coal attributable to each Indian lease by 

multiplying the input ratio determined 

under § 1206.451(e)(2)(i) by the total 

allowable costs. 

(c)(1) You must express washing 

allowances for coal as a dollar-value 

equivalent per short ton of coal washed. 

(2) If you do not base your or your 

affiliate’s payments for washing under 

an arm’s-length contract on a dollar-perunit basis, you must convert whatever 

consideration you or your affiliate paid 

to a dollar-value equivalent. 

(d) ONRR may determine your 

washing allowance under § 1206.454 

because: 

(1) There is misconduct by or between 

the contracting parties; 

(2) ONRR determines that the 

consideration 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. We may consider a 

washing allowance unreasonably high if 

it is 10-percent higher than the highest 

other reasonable measures of washing, 

including but not limited to, washing 

allowances reported to ONRR and costs 

for coal washed in the same plant or 

other plants in the region; or 

(3) ONRR cannot determine if you 

properly calculated a washing 

allowance under §§ 1206.467 through 

1206.469 for any reason, including but 

not limited to, your or your affiliate’s 

failure to provide documents that ONRR 

requests under 30 CFR part 1212, 

subpart E. 

(e) You only may claim a washing 

allowance, if you sell the washed coal 

and report and pay royalties. 

§ 1206.468 How do I determine a washing 

allowance if I have an arm’s-length washing 

contract or no written arm’s-length 

contract? 

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

washing costs under an arm’s-length 

washing contract, you may claim a 

washing allowance for the reasonable, 

actual costs incurred. 

(b) You must be able to demonstrate 

that your or your affiliate’s contract is 

arm’s length. 

(c) If you have no contract for the 

washing of coal, then ONRR will 

determine your transportation 

allowance under § 1206.454. You may 

not use this paragraph (c), if you or your 

affiliate perform(s) your own washing. If 

you or your affiliate perform(s) the 

washing, then: 

(1) You must propose to ONRR a 

method to determine the allowance 

using the procedures in § 1206.458(a). 

(2) You may use that method to 

determine your allowance until ONRR 

issues a determination. 

§ 1206.469 How do I determine a washing 

allowance if I have a non-arm’s-length 

washing contract? 

(a) This section applies if you or your 

affiliate do(es) not have an arm’s-length 

washing contract, including situations 

where you or your affiliate provides 

your own washing services. Calculate 

your washing allowance based on your 

or your affiliate’s reasonable, actual 

costs for washing during the reporting 

period using the procedures prescribed 

in this section. 

(b) Your or your affiliate’s actual costs 

may include: 

(1) Capital costs and operating and 

maintenance expenses under paragraphs 

(d), (e), and (f) of this section; 

(2) Overhead under paragraph (g) of 

this section; and 

(3) Depreciation under paragraph (h) 

of this section and a return on 

undepreciated capital investment under 

paragraph (i) of this section, or a cost 

equal to a return on the initial 

depreciable capital investment in the 

wash plant under paragraph (j) of this 

section. After you have elected to use 

either method for a wash plant, you may 

not later elect to change to the other 

alternative without ONRR approval. If 

ONRR accepts your request to change 

methods, you may use your changed 

method beginning with the production 

month following the month ONRR 

received your change request. 

(c) You may not use any cost as a 

deduction that duplicates all or part of 

any other cost that you use under this 

section. 

(d) Allowable capital investment costs 

are generally those for depreciable fixed 

assets (including costs of delivery and 

installation of capital equipment), 

which are an integral part of the wash 

plant. 

(e) Allowable operating expenses 

include: 

(1) Operations supervision and 

engineering; 

(2) Operations labor; 

(3) Fuel; 

(4) Utilities; 

(5) Materials; 

(6) Ad valorem property taxes; 

(7) Rent; 

(8) Supplies; and 

(9) Any other directly allocable and 

attributable operating expenses that you 

can document. 

(f) Allowable maintenance expenses 

include: 

(1) Maintenance of the wash plant; 

(2) Maintenance of equipment; 

(3) Maintenance labor; and 

(4) Other directly allocable and 

attributable maintenance expenses that 

you can document. 

(g) Overhead, directly attributable and 

allocable to the operation and 

maintenance of the wash plant is an 

allowable expense. State and Federal 

income taxes and Indian tribal 

severance taxes and other fees, 

including royalties, are not allowable 

expenses. 

(h)(1) To calculate depreciation, you 

may elect to use either (i) a straight-line 

depreciation method based on the life of 

the wash plant or the life of the reserves 

which the wash plant services, or (ii) a 

unit-of-production method. After you 

make an election, you may not change 

methods without ONRR approval. If 

ONRR accepts your request to change 

methods, you may use your changed 

method beginning with the production 

month following the month ONRR 

received your change request. 

(2) A change in ownership of a wash 

plant will not alter the depreciation 

schedule the original washer/lessee 

established for purposes of the 

allowance calculation. 

(3) With or without a change in 

ownership, you may depreciate a wash 

plant only once. 

(i) To calculate a return on 

undepreciated capital investment, 

multiply the remaining undepreciated 

capital balance as of the beginning of 

the period for which you are calculating 

the washing allowance by the rate of 

return provided in paragraph (k) of this 

section. 

(j) As an alternative to using 

depreciation and a return on 

undepreciated capital investment, as 

provided under paragraph (b)(3) of this 

section, you may use as a cost an 

amount equal to the allowable initial 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 80, No. 3 / Tuesday, January 6, 2015 / Proposed Rules 675 

capital investment in the wash plant 

multiplied by the rate of return as 

determined under paragraph (k) of this 

section. You may not include 

depreciation in your allowance. 

(k) The rate of return is the industrial 

rate associated with Standard & Poor’s 

BBB rating. 

(1) You must use the monthly average 

BBB rate that Standard & Poor’s 

publishes for the first month for which 

the allowance is applicable. 

(2) You must redetermine the rate at 

the beginning of each subsequent 

calendar year. 

(3) After ONRR issues its 

determination, you must make the 

adjustments under § 1206.473. 

§ 1206.470 What are my reporting 

requirements under an arm’s-length 

washing contract? 

(a) You must use a separate entry on 

Form ONRR–4430 to notify ONRR of an 

allowance based on washing costs you 

or your affiliate incur(s). 

(b) ONRR may require you or your 

affiliate to submit arm’s-length washing 

contracts, production agreements, 

operating agreements, and related 

documents. 

(c) You can find recordkeeping 

requirements in parts 1207 and 1212 of 

this chapter. 

(d)(1) You must file an initial Form 

ONRR–4292 prior to, or at the same 

time, as the washing allowance 

determined under an arm’s-length 

contract or no written arm’s-length 

contract situation that you report on 

Form ONRR–4430. If ONRR receives a 

Form ONRR–4292 by the end of the 

month that the Form ONRR–4430 is 

due, ONRR will consider the form 

timely received. 

(2) The initial Form ONRR–4292 is 

effective beginning with the production 

month that you are first authorized to 

deduct a washing allowance and 

continues until the end of the calendar 

year, or until the termination, 

modification, or amendment of the 

applicable contract or rate, whichever is 

earlier. 

(3) After the initial period that ONRR 

first authorized you to deduct a washing 

allowance, and for succeeding periods, 

you must submit the entire Form 

ONRR–4292 by the earlier of: 

(i) Within 3 months after the end of 

the calendar year; or 

(ii) After the termination, 

modification, or amendment of the 

applicable contract or rate. 

(4) You may request to use an 

allowance for a longer period than that 

required under paragraph (d)(2) of this 

section. 

(i) You may use that allowance 

beginning with the production month 

following the month ONRR received 

your request to use the allowance for a 

longer period until ONRR decides 

whether to approve the longer period. 

(ii) ONRR’s decision whether or not to 

approve a longer period is not 

appealable under 30 CFR part 1290. 

(iii) If ONRR does not approve the 

longer period, you must adjust your 

transportation allowance under 

§ 1206.466. 

§ 1206.471 What are my reporting 

requirements under a non-arm’s-length 

washing contract or no written arm’s-length 

contract? 

(a) You must use a separate entry on 

Form ONRR–4430 to notify ONRR of an 

allowance based on non-arm’s-length 

washing costs you or your affiliate 

incur(s). 

(b) ONRR may require you or your 

affiliate to submit all data used to 

calculate the allowance deduction. You 

can find recordkeeping requirements in 

parts 1207 and 1212 of this chapter. 

(c)(1) You must submit an initial 

Form ONRR–4292 prior to, or at the 

same time as, the washing allowance 

determined under a non-arm’s-length 

contract or no written arm’s-length 

contract situation that you report on 

Form ONRR–4430. If ONRR receives a 

Form ONRR–4292 by the end of the 

month that the Form ONRR–4430 is 

due, ONRR will consider the form 

received timely. You may base the 

initial reporting on estimated costs. 

(2) The initial Form ONRR–4292 is 

effective beginning with the production 

month that you are first authorized to 

deduct a washing allowance and 

continues until the end of the calendar 

year or termination, modification, or 

amendment of the applicable contract or 

rate, whichever is earlier. 

(3)(i) At the end of the calendar year 

for which you submitted a Form ONRR– 

4292, you must submit another 

completed Form ONRR–4292 containing 

the actual costs for that calendar year. 

(ii) If coal washing continues, you 

must include on Form ONRR–4292 your 

estimated costs for the next calendar 

year. 

(A) You must base the estimated coal 

washing allowance on the actual costs 

for the previous period plus or minus 

any adjustments based on your 

knowledge of decreases or increases that 

will affect the allowance. 

(B) ONRR must receive Form ONRR– 

4292 within 3 months after the end of 

the previous calendar year. 

(d)(1) For new non-arm’s-length 

washing facilities or arrangements on 

your initial Form ONRR–4292, you must 

include estimates of allowable washing 

costs for the applicable period. 

(2) You must use your or your 

affiliate’s most recently available 

operations data for the wash plant as 

your estimate, if available. If such data 

is not available, you must use estimates 

based on data for similar wash plants. 

(e) Upon ONRR’s request, you must 

submit all data you used to prepare your 

Forms ONRR–4293. You must provide 

the data within a reasonable period of 

time, as ONRR determines. 

(f) Section 1206.472 applies when you 

amend your Form ONRR–4292 based on 

the actual costs. 

§ 1206.472 What interest and penalties 

apply if I improperly report a washing 

allowance? 

(a)(1) If ONRR determines that you 

took an unauthorized washing 

allowance, then you must pay any 

additional royalties due, plus late 

payment interest calculated under 

§ 1218.202 of this chapter. 

(2) If you understated your washing 

allowance, you may be entitled to a 

credit without interest. 

(b) If you improperly net a washing 

allowance against the sales value of the 

coal instead of reporting the allowance 

as a separate entry on Form ONRR– 

4430, ONRR may assess a civil penalty 

under 30 CFR part 1241. 

§ 1206.473 What reporting adjustments 

must I make for washing allowances? 

(a) If your actual washing allowance 

is less than the amount you claimed on 

Form ONRR–4430 for each month 

during the allowance reporting period, 

you must pay additional royalties due, 

plus late payment interest calculated 

under § 1218.202 of this chapter from 

the date you took the deduction to the 

date you repay the difference. 

(b) If the actual washing allowance is 

greater than the amount you claimed on 

Form ONRR–4430 for any month during 

the period reported on the allowance 

form, you are entitled to a credit 

without interest. 

[FR Doc. 2014–30033 Filed 12–19–14; 4:15 pm] 

BILLING CODE 4310–T2–P 


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